This paper presents an overview of the microbiology of sulfate-reducing bacteria (SRB) and their detrimental effects in oil technology and summarizes a study on SRB in an oil field. SRB are a group of specialized microorganisms that occur in aqueous environments in the absence of oxygen. The main nutrients for SRB are simple organic acids and molecular hydrogen (H2) from decomposing natural organic matter. The nutrients are oxidized, with sulfate being reduced to sulfide (hydrogen sulfide, H2S). The formed H2S is the principal agent in the disastrous effects caused by SRB. It contaminates gas and stored oil, precipitates ferrous sulfide that plugs injection wells, and promotes precipitates ferrous sulfide that plugs injection wells, and promotes corrosion of iron and steel in the absence of oxygen (anaerobic corrosion). Another principal mechanism by which SRB are involved in corrosion is their ability to depolarize iron surfaces by consumption of cathodically formed hydrogen. The postulated mechanism in anaerobic corrosion are briefly explained. As an example for a microbiological study of SRB in oil technology, examination of an oil treater in a field in northern Germany is presented. On the basis of measured growth characteristics of the SRB, presented. On the basis of measured growth characteristics of the SRB, possibilities for controlling their activity are discussed. possibilities for controlling their activity are discussed.
Biological sulfate reduction by SRB is the only known process by which, in aquatic environments of moderate process by which, in aquatic environments of moderate temperatures (O to 75 degrees C [32 to 167 degrees F]), H2S is formed from sulfate. In sediments of ponds, lakes, and marine environments, SRB are usually part of the indigenous community of microorganisms and are rather inconspicuous in nonpolluted waters. In oilfield water systems, however, SRB cause serious problems:corrosion of iron in the absence of air (anaerobic corrosion),precipitation of amorphous ferrous sulfide that, by precipitation of amorphous ferrous sulfide that, by plugging, diminishes the in injectivity of water injection wells, plugging, diminishes the in injectivity of water injection wells,contamination of fuel gas with H2S, andcontamination of stored fuel oil with H2S.
Furthermore, H2S is extremely toxic if inhaled: it easily escapes from contaminated waters and may accumulate under poorly ventilated conditions. It is usually recognized by its distinctive, unpleasant odor, but high concentrations anesthetize the sense of smell. The objective of this paper is to present an overview of" the biological features of SRB and of their activities in oil technology with emphasis on anaerobic corrosion. We also include results from our studies on SRB in an oil field in northern Germany.
Microbiology of SRB
SRB are an assemblage of specialized bacteria that thrive in the absence of oxygen and obtain energy for growth by, oxidation of organic nutrients, with sulfate being reduced to H2S. The biological significance of this form of life is best understood within the overall natural decomposition process carried out by living organisms.
Processes in Biological Decomposition
The natural Processes in Biological Decomposition. The natural decomposition of organic material in our biosphere through a food chain of oxygen-breathing (respiring) organisms-namely, animals, fungi, and bacteria-is a well-known process. Biochemically, respiration is a transport of reducing power (hydrogen, "electrons") from the organic nutrients (organic substrates, electron donors) being oxidized to oxygen (electron acceptor) being reduced (Fig. la). Respiration liberates the energy that has been originally conserved in the organic matter during photosynthesis by green plants and cyanobacteria photosynthesis by green plants and cyanobacteria (bluegreen algae). In the oxygen-breathing organisms, the liberated energy is used for maintenance of their living structures and for growth-i.e., a net synthesis of their own cell material from the nutrients. Thus every organic substrate of a respiring organism is partly decomposed for obtaining energy and partly converted into new cell material. These functionally distinctive reactions in living organisms are designated catabolism or dissimilation (energy metabolism) and anabolism or assimilation (cell synthesis), respectively. An amount of biomass initially synthesized by photosynthesis is diminished more and more by passing through the food chain because of respiratory losses. The final result is a reoxidation (mineralization) of the chemically complex biomass to CO7, H2O, and other minerals (Fig. 1a). These inorganic end products are used by green plants and cyanobacteria for products are used by green plants and cyanobacteria for photosynthesis of new organic substances (the natural cycle photosynthesis of new organic substances (the natural cycle of matter). The total reoxidation of biomass is possible only if the conditions are aerobic- i.e., if sufficient oxygen is present. If biomass gets into stagnant or rather closed water present. If biomass gets into stagnant or rather closed water systems where the gas exchange with the atmosphere is limited, dissolved oxygen may be completely consumed.
The directional behavior analysis of polycrystalline diamond compact (PDC) bits was presented. A full-scale drilling bench was built to measure PDC bit walking tendency and steerability. A 3D theoretical rock/bit interaction model was developed to reproduce the drilling test results. The weight on bit (WOB) and lateral force required for axial and lateral motion were calculated using this 3D rock/bit model.
A wide range of intermittent gas-lift tests was conducted in a 1,500-ft experimental well through 1 1/4 - and 1 1/2-in. nominal size tubing. The well was equipped with two gas-lift valves, four Maihak electronic pressure transmitters and surface facilities to measure casing and tubing pressures, temperature, liquid production and the rate and volume of gas injected. For each tubing size, tests were conducted varying the slug length, gas volume injected and liquid viscosity and surface tension. From these tests, an empirical "fallback" or liquid loss correlation has been developed. No general fallback correlation could be obtained, and the correlation is presented in the form of one curve for each slug length of a given liquid and tubing size. A conceptual model has been developed which combines the fallback correlation with equations which govern liquid slow flow. A mathematical simulation of the model in the form of a digital computer program is used to calculate total recovery, gas volume used and clearance time for a given test. Tubing pressures at the gas-lift valve and at the gas-slug interface are calculated as a function of time. Tubing pressures at the surface during slug clearance are also calculated. The results compare favorably with the test data and verify the conceptual model. The extent to which the model can be used for other tubing sizes, depths, liquids and gas-lift valves can only be determined with additional experimental data. Data are also necessary so that a fallback curve can be constructed for the particular test conditions studied.
The flow of liquid slugs in vertical conduits has long been an established production method in the petroleum industry. Under the name "intermittent gas lift", many advances have been made in engineering design. However, the unsteady-state nature of liquid slug flow has discouraged attempts to describe the problem analytically. The result has been that intermittent gas lift is dominated by rules-of-thumb engineering practices developed over many years. The advent of slim-hole completions has increased the demand for a more rigorous solution to the intermittent problem. Small-diameter conduits offer more frictional resistance to flow, and also reduce the slug volume lifted per intermittent cycle. Small-diameter conduits are defined to be 1 1/2-in. nominal size tubing or smaller. When oil is produced from the reservoir in which it is found, and transported to surface tanks by intermittent gas lift, three separate flow stages are encountered: flow of the fluids to the wellbore through a porous medium, vertical flow of a liquid slug from the point of gas injection to the surface, and horizontal flow of the liquid slug through the surface flowlines from the wellhead to the surface tanks. The three stages are depicted schematically in Fig. 1. The present study deals with liquid slug flow in both the vertical and horizontal conduits, ending when the bottom of the liquid slug reaches the surface. Due to the large number of variables involved, the analytical study of intermittent gas lift is extremely complex. The possibility of flow regimes other than slug type, the nature of the force fields acting on the system, the interfacial instabilities involved, the varying operational principles of existing gas-lift valves and the complete unsteady-state nature of the physical phenomena occurring in an intermittent gas-lift cycle relate some of the difficulties encountered.
Axial force transfer is an issue in deviated wells where friction and buckling phenomenon take place. The general perception of the industry is that once drill pipe exceeds conventional buckling criteria, such as Paslay-Dawson, axial force cannot be transferred down-hole anymore. This paper shows that, even though buckling criteria are exceeded, axial force transfer could be still good if drill pipe is in rotation. On the contrary, there exists sliding operations where lockup is observed, due to buckling, even though standard buckling criteria are not exceeded. This paper is intended to show and explain how axial force is transferred down-hole in many simulated field conditions: sliding, rotating, with or without dog legs. These new results have been obtained from an advanced model dedicated to drill string mechanics successfully validated with laboratory tests.
This paper will show applicable results for practical well operations where axial force transfer is an issue. These results will enable to give some guidelines to help the drilling engineer to select cases where conventional buckling criteria should be used cautiously. Indeed, simultaneous torque-drag-buckling calculations show that tubular can tolerate significant levels of compression, enabling to provide weight transfer to the drill bit, even though drill pipe is buckled. Others examples, in contrast, show that standard buckling criteria cannot predict the occurrence of buckling that may cause tubular lockup while tripping in the hole.
The applications of these results are numerous for all deviated wells such as horizontal or extended reach drilling wells. This paper should contribute to reduce unpredictable lock-up situations and improve axial load transfer performance.
State of the Art
Axial force transfer is generally an issue in highly deviated wells, such as horizontal and extended reach drilling wells, where drag friction is significant and buckling may occur, leading sometimes to lock-up. These challenging wells are characterized by a long horizontal departure (HD) relative to the vertical depth (TVD) of the well. The horizontal departure to vertical depth ratio (HD/TVD) from which axial force transfer becomes critical is approximately 4. Resulting from excessive friction and/or buckling, operations such as mud motor sliding, tubulars and completion running, or transferring weight on bit while drilling, become very difficult. The axial force transfer issue comes from an insufficient tubulars weight in the vertical or low deviated section of the well to run the drill string in the long deviated hole. To overcome this problem, drilling engineers utilized sometimes drill collars or heavy weight drill pipes above drill pipes to push the string downhole. For a given coefficient of friction (m), it is practical to define the critical angle (Incgravity), that is the angle for which tubular can no longer move down hole due to its own weight. This angle depends on the friction coefficient (m) and takes the form:
For example, a coefficient of friction equal to 0.3 gives a critical angle around 73 deg. That means that if the inclination is greater than 73 deg., tubulars need to be pushed in the hole to start a downward motion.
The object of this study was to determine if crude oil could be produced successfully by a process of crude oil vaporization using carbon dioxide repressuring. This process appears to have application to highly fractured formations where the major oil content of the reservoir is contained in the non-fractured porosity with little associated permeability.Crude oil was introduced into the windowed cell and carbon dioxide was charged to the cell at the desired pressure. A vapor space was formed above the oil, and the crude oil-carbon dioxide mixture was allowed to come to equilibrium. The vapor phase was removed and the vaporized oil collected as condensate. Samples of all produced and unproduced fluids were analyzed. Tests were also performed to evaluate the amount of vaporized oil that can be produced by rocking from a high to a lower pressure. The carbon dioxide repressuring process was applied to a sand-filled cell to investigate the performance in a porous medium. A test was performed to evaluate how the condensate recovery changes as the size of the gas cap in contact with the oil changes.
This study has been directed toward a relatively new process of vaporization of crude oil designed to increase ultimate production of hydrocarbons through the application of carbon dioxide to an oil reservoir. Suggested advantages of carbon dioxide repressuring of a petroleum reservoir are:reduction in viscosity of liquid hydrocarbons due to the solubility of carbon dioxide in crude oil,swelling of the reservoir oil into a larger liquid-oil volume with a resulting increase in production and decrease in residual oil saturation due to an increase in the relative permeability to oil,displacement of more stock-tank oil from the reservoir since the residual liquid is a swelled crude oil, andgasification of some of the hydrocarbons into a carbon dioxide-hydrocarbon vapor mixture.
Balanced against these advantages are several detrimental factors which must be evaluated; i.e., high compression costs and corrosion of well equipment and flow lines.Some of the more outstanding contributions to the study of carbon dioxide injection have been reviewed in order to furnish a basis for a continuation of research pertaining to this method. The literature reviewed has been limited to that dealing with carbon dioxide repressuring processes or with carbon dioxide-crude oil-natural gas phase behavior. Articles relating to carbonated water injection and literature published on the use of low pressure carbon dioxide gas injection in water flooding have not been included in this study.In 1941 Pirson suggested the high pressure injection of carbon dioxide into a partially depleted reservoir for the purpose of causing the reservoir oil to vaporize and thus produce the oil as a vapor along with the carbon dioxide gas. By reducing the pressure on this produced mixture of hydrocarbons and carbon dioxide at the surface, it was proposed to separate the hydrocarbons from the carrier gas. He theorized that essentially all the oil in a reservoir could be produced by simply injecting enough carbon dioxide to vaporize the residual oil.This present investigation deals with the vaporization of a crude oil by carbon dioxide, the molecular weight and gravity of the vaporized oil product and the characteristics of the residual oil after several repressuring cycles with carbon dioxide. An attempt is made to evaluate the merits of a vaporization process for the crude oil rather than a flow process where the oil recovery is determined by relative permeability considerations. Such a vaporize of crude oil by carbon dioxide repressuring appears to have possible use in a highly fractured formation where the major oil content of the reservoir is contained in the non-fractured porosity with little permeability. The carbon dioxide flows into the fractures, contacts the crude oil in the matrix and vaporizes part of the crude oil; this vaporized oil is produced and recovered and the carbon dioxide is reinjected again.The specific problem of this study is to attempt to answer this question; Can crude oil be produced successfully (technically, but without economic considerations) from a petroleum reservoir by a process of vaporization of the crude oil by carbon dioxide repressuring?
DEFINITION OF TERMS AS APPLIED IN THIS STUDY
Carbon Dioxide Contact: One cycle in which carbon dioxide was injected and bled off. Condensate: The hydrocarbon liquid which was condensed out of the mixture of hydrocarbon-carbon dioxide vapor upon reduction of the pressure of the vapor.Hydrocarbons Produced (HCP): All the hydrocarbons which were vaporized by the carbon dioxide repressuring process and were removed from the cell during any specific cycle or carbon dioxide contact.
This paper presents the results of an investigation of two-phase, gas-liquid flow in horizontal pipelines. Experimental data were taken in three field-size, horizontal pipelines, two of which were constructed for this purpose. The data were obtained using water, distillate and crude oil separately as the liquid phase, and natural gas as the second phase. Experimental pressure-length traverse, liquid holdup and flow-pattern data were collected for each set of flow rates. These data were used to develop three correlations that are presented herein. The liquid-holdup values correlated with various flow parameters without regard to the existing flow pattern. The same was true for the energy-loss factors. A new flow-pattern map is presented that appears to be quite reliable, but not required for the pressure-loss calculations. The liquid-holdup correlation and the energy-loss factor correlation are used in conjunction with a two-phase flow power balance, developed during this study, to predict the pressure losses that occur during gas-liquid flow in horizontal pipelines. A recommended calculational procedure is given, as well as a statistical analysis of the results. This procedure lends itself to computer application, since several small pressure decrements are needed to calculate a pressure-length traverse. The correlations are shown graphically, but may be curve fitted with existing curve-fitting computer programs.
Due to the frequent occurrence of gas-liquid flow in pipelines and the desire to accurately calculate the pressure losses that occur in these lines, two-phase flow is of considerable interest to the petroleum, chemical and nuclear industries. In the petroleum industry, gas-liquid mixtures have been transported over relatively long distances in a common line due to the advent of centralized gathering and separation systems. Long two-phase flowlines are usually accompanied by large pressure drops which influence the design of the system. Gas-lift installations are designed on the basis of known tubing pressures at the wellheads. The horizontal flowline connecting the wellhead and the separator system must be correctly sized in order to minimize the horizontal flowline pressure losses and the wellhead tubing pressure. Practically all oilwell production design involves horizontal two-phase flow in pipelines. All of the flow processes of oil and gas production must be studied simultaneously to insure good well design. Since the beginning of offshore oilfield development, long horizontal flowlines have been constructed. Because pressure losses greatly influence the performance of producing wells, a method is desired that can be used to predict such pressure losses and select optimum flowline size. Several types of gas-liquid flow exist, and many of these are discussed by Gouse. The study of pressure gradients, fluid distributions and flow patterns that occur in horizontal multiphase flow is made difficult by the great number of variables involved. The various flow regimes give rise to changing velocities of the fluid particles in all directions. These instabilities of the interface between the gas and liquid prohibit the determination of actual vector velocities of fluid particles in each phase. Also, it is practically impossible to arrive at correct sets of boundary conditions. Therefore, most investigators have concluded that a solution to the problem by the classical fluid dynamics approach, whereby the Navier-Stokes equations are formulated and solved, is far too complex. Other methods must be utilized to develop general correlations that will predict the behavior of gas-liquid horizontal flow systems. Multiphase flow studies have sought to develop a technique with which the pressure drop can be calculated. Pressure losses in two-phase, gas-liquid flow are quite different from those encountered in single-phase flow; in most cases an interface exists and the gas slips past the liquid. The interface may be smooth or have varying degrees of roughness, depending on the flow pattern. Therefore, a transfer of energy from the gaseous phase to the liquid phase may take place while energy is lost from the system through the wetting phase at the pipe wall. Such an energy transfer may be either in the form of heat exchange or of acceleration. Since each phase must flow through a smaller area than if it flowed alone, amazingly high pressure losses occur when compared to single-phase flow. Most investigators of horizontal two-phase flow phenomena have chosen to separate their experimental data into several groups of observed flow patterns or regimes.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Sept. 29-Oct. 2, 1968. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Drilling exploratory wells in the petroleum industry is an economic undertaking petroleum industry is an economic undertaking in which the probability of success of the individual venture is low, but the payoffs from successful wells compensate for the costs of the failures. There is a recent trend toward expressing the possible payoffs in terms of a probability distribution. probability distribution. Appraisal methods were developed that were predicated toward the use of a predetermined predicated toward the use of a predetermined risk factor, as is generally used in statistical decision methods. Cumulative values of groups of exploratory ventures were shown by computer simulation to approximate closely the normal distribution. Solutions developed include determination of the maximum fractional participation in a relatively large venture, participation in a relatively large venture, determination of the maximum appraisal price consistent with financial resources of the economic unit, and determination of the value of information that increases the chance of success. A maximum appraisal price is limited by required expected rate of return when capital resources are very large. However, the appraisal price is dominated by risk where capital resources are not relatively large.
The evaluation of petroleum exploratory ventures is concerned with the appraisal of economic undertakings wherein the probability of complete failure of the individual venture is high and the probability of success is low and the magnitude of the occasional success itself is variable. For an individual well, even when it is located with geologic guidance, there is quite a low probability of discovering sufficient quantities of oil to repay the drilling and completion costs. However, where a drilling program consists of a score of such wells, there is often a high probability that the better discoveries will repay the costs of the entire program as well as pay the necessary profits. profits. Several of the methods that have been proposed for evaluate exploratory ventures have proposed for evaluate exploratory ventures have used an expected value, if successful, in combination with some method for handling the relative success ratio. The binomial distribution has been used for describing the distribution of occurrences of successful and unsuccessful trials, and the lognormal distribution has been recognized as adequate for describing the distribution of sizes of resource deposits.
Ultimate oil recovery by solution gas drive can be greatly affected by variations in production rates --- in general the higher the rate the higher the recovery. However, the quantitative relationship for a given field will be influenced by factors other than rate and vertical permeability: reservoir thickness, gas solubility, shrinkage factor, oil permeability: reservoir thickness, gas solubility, shrinkage factor, oil viscosity, relative permeability, and capillary pressure.
The relationship between ultimate oil recovery and rate of oil production has been the subject of many investigations since 1924 when Cutler published a study of field data. Cutler concluded that higher oil production rates yielded higher ultimate oil production rates yielded higher ultimate oil recoveries. Subsequent studies of performance from a variety of fields showed that factors other than producing rate caused so much variation in total oil producing rate caused so much variation in total oil recovered that no conclusion could be reached concerning the effects attributable to this single factor. Because of the impossibility of imposing different production histories on a given reservoir to observe production histories on a given reservoir to observe the difference in ultimate oil produced, confirmation of any such relationship had to depend on analytical studies and laboratory model tests. Analytical approaches using simplified models, in which effects of capillary pressure and gravity forces were ignored, led to the conclusion that any effect of production rate upon ultimate recovery was negligible. They did show gross differences in horizontal saturation distributions imposed by production rate variations. In 1953 and 1954 the foundation was laid for solution of the unsteady-state fluid flow equations by use of difference approximations and high-speed computers. The development of these techniques led to numerous mathematical model investigations of fluid displacement in one and two dimensions. These works treated a range of fluid systems in one and two dimensions; generally they were confined to incompressible fluids, and included gravity and capillary, effects. When simulating compressible fluid systems, gravity and capillary forces were ignored. Levine et al. and Heuer et al. studied the effects of production rate on ultimate oil recovery by solution gas drive, using these more sophisticated mathematical techniques. Both efforts neglected the effect of gravity, but Levine included capillary forces. Both concluded that producing rate had a negligible effect on ultimate recovery. Ridings et al. showed that performance of long horizontal laboratory systems performance of long horizontal laboratory systems coincided closely with performance calculated by numerical modeling techniques, with one exception. Noticeably increasing recovery was observed with increasing production rate in the laboratory system, whereas the numerical model showed no rate effect. Gravity was not a factor in either system. Since the production rate sensitivity was less on very long production rate sensitivity was less on very long laboratory systems than for the shorter ones, it was concluded that the rate effect observed on the short laboratory system was, for reasons not specified, typical only of short systems. It bas been recognized for some time that, under certain conditions, gravitational forces can be very important in the displacement of oil from natural reservoirs. Muskat treats exhaustively the performance of wells and reservoirs in which gravity is performance of wells and reservoirs in which gravity is the sole driving mechanism.
Fishing usually is needed when least expected and brings a sudden halt to operations, especially if the drillstring becomes stuck. Reaction planning begins at this time unless the drilling project was planned properly from the outset. That reaction planning is not good and should not be done is not the question. What is important is to establish the facts. What caused the drillstring to become stuck? What should be done to free the drillstring? What will the cost be? This paper addresses these questions. It also emphasizes the importance of routine, continuous, but often unrewarded, effort by operation personnel. This paper presents one viewpoint for evaluating alternatives to fishing, for retrieving a fish compared with sidetracking, and for using economics and risk factors in the decision-making process. These alternatives are compared in Fig. 1. The discussion includes factors that can prevent fishing, such as drillstring inspection, and that can cause fishing, such as poor mud programs and differential-pressure sticking. An example illustrates decision-making processes involved in recovering or sidetracking the fish when the processes involved in recovering or sidetracking the fish when the drillstring is stuck by differential pressure. Even though this is only one of many causes for fishing, the process used to evaluate the economics may be applied to many other operations. The goal is to provide a usable wellbore at the lowest ultimate cost.
Planning Precludes Fishing Planning Precludes Fishing Drillstring
The most economical method of fishing is to develop a drilling plan that precludes factors and operations that may result in fishing. The most important rule in any drilling operation is to ensure that the drillstring, especially the bottomhole assembly (BHA), is designed for the specific drilling conditions and inspected before a well is begun. Additional inspections may be necessary to preclude a fatigue failure or to ensure that the maximum anticipated loads can be handled safely. Another critical factor is inspection of all threads on rental equipment and fishing and directional tools planned for use. The complete string, from the top of the kelly to the bottom connection in the drillstring, should be inspected. Economics or risk evaluation for justifying costs can be evaluated by comparing the cost of fishing and the cost of inspections and the operations required to preclude fishing. The typical cost to inspect a drillstring before spudding and two BHA's during drilling of a30-day 12,000-ft well is about $15,000. The cost for fishing at about 10,000 ftto recover part of a BHA in a clean hole is roughly $20,000 (including part of a BHA in a clean hole is roughly $20,000 (including lost rig time and fishing expense). Some operators include tubular inspection in prespud costs. The costscited are for land operations in the U.S., but the principle applies to offshore or remote operations. Inspection is cheaper than fishing.
Another important factor in preventing fishing is use of a good mud system. A good mud system will circulate cuttings to the surface(clean the hole); provide a thin, impermeable filter cake (prevent differential sticking); and maintain wellbore stability (control shales). These three characteristics have various degrees of importance, depending on the drilling environment. It is extremely important to consider a mud system designed to address these items in initial drilling economics. A mud system with poor properties can make the drillstring very susceptible to sticking. This often can be avoided with nominal expenditures to improve mud properties.
Many operating practices developed to preclude fishing are generally accepted and peculiar to a specific preclude fishing are generally accepted and peculiar to a specific geologic province. One such practice that will minimize the chances of the BHA sticking in a keyseat is to add a stabilizer or a keyseat wiper (with an OD larger than drillpipe tool joints and drill collars) at the top of drill collars to guide the BHA around the keyseat. The expense of one stabilizer is minimal compared with the cost to recover a stuck drillstring. Other practices that may prevent fishing include frequent wiper trips, controlled rates of penetration (ROP's), and the pumping of viscous sweeps before trips.
Types of Fishing Jobs
Parted Drillstring and/or Tools
Fishing for a parted string can Parted Drillstring and/or Tools. Fishing for a parted string can be extremely expensive and may be a reason to consider sidetracking the fish. A normal job would consist of running jars on a properly sized overshot/grapple, latching onto the fish, and pulling (may jar loose first) the fish out of the hole. However, the fish top can be damaged, which will require the fish top to be dressed with a milling tool, or the fish top may be difficult to locate, which will mean several trips before the fish is engaged. The fish may become stuck by the time it is actually engaged with the fishing string. Then, a procedure for removing the free (unstuck) sections of the fish by "backing off"becomes necessary. At this time, an economic comparison between fishing orsidetracking should be finalized. The decision to continue fishing or tosidetrack should be based on a comparison of the estimated cost and associated risk of these alternatives.
Another type of fishing involves a stuck drillstring. If differential sticking is suspected, the first step usually is to spot a special fluid around the drillstring at the suspected stuck point to free the drillstring. (A spotting fluid in the wellbore at the stuck point will penetrate the filter cake along the pipe and reduce the area subject to differential pressure. The tension to move the drillstring is decreased and the drillstring often can be freed.) The cost to free a stuck drillstring with a spotting fluid is minimal compared with backing off a free section and then washing over to free additional sections. Therefore, the first step should be to use a spotting fluid. If this procedure does not free the stuck string, a free point with or without a stuck-pipe log (similar to a cement-bond point with or without a stuck-pipe log (similar to a cement-bond log) is run to determine the uppermost stuck point. Then, fishing operations to retrieve the stuck string may begin. Again, the decision to fish or to sidetrack should be based on a comparison of their estimated costs.
The production of oil by water flooding can be substantially increased bythe maintenance of free gas saturation in the reservoir during the floodingoperation. This effect is accomplished by the alteration of oil relativepermeability characteristics and the occupation by gas of pore space that wouldotherwise be filled with residual oil. The amount of reduction in residual oilcan be calculated from appropriate water-oil relative permeabilitycharacteristics.
This paper presents experimental data in support of the foregoingconclusions and an example of the calculations. The microscopic pore saturationconcepts of the mechanism are discussed. A method of practical application tofield floods is presented together with discussion of certainlimitations.
The presence of free gas has been reported by a number of investigators tosignificantly affect the oil recovery which can be obtained from sandstone flowsystems by water flooding. The effect of gas, noted in every instance, has beento cause lower residual oil saturations than could be obtained by waterflooding the same systems in the absence of free gas. The degree of improvementin recovery has been observed to vary widely, depending on the systems used andthe conditions of the tests. The increased oil recovery obtained because of thepresence of gas during a water flood has been variously attributed to changesin physical characteristics of the oil, selective plugging action of the gas, inclusion of oil mist in the free gas phase, and the additional sweeping ordriving action of the free gas.
All but the first of these suggestions imply changes in the displacementmechanism. The change in viscosity and interfacial tension of the oil phase, within the pressure range used for all the experimental work, is certainly notsufficient to account for the differences in residual oil saturation notedunless there is a drastic change in the displacement process.
One other effect which logically seems capable of causing differences inresidual oil saturation of the magnitude noted in the experimental work is thatof simple replacement. In a water-wet system containing oil, water, and gas, itis to be expected that the gas will exist inside the oil.
This study extends our information on solid-liquid slurries to the flow of sand in horizontal fractures. Inasmuch as this is basically an unsteady-state process. a comprehensive photographic study was undertaken in a 10- ft windowed cell to determine if the basic flow regimes described for steady-state flow in pipes applied to the subject process. Since the number of potential variables far exceeds the capacity of a single study, emphasis has been placed on the effects of sand concentration, oil viscosity and oil flow rate.The extensive photographic evidence obtained has proven very valuable in gaining an insight into the basic flow mechanisms. Being able to follow visually the flow characteristics that accompany the quantitative data is valuable in the application of the results.Although the use of dimensionless parameters was carefully investigated, it was found that the data obtained could be more easily, and as accurately, correlated by judicious use of the dimensional variables investigated. However, a study into the feasibility of scaling slurry flow was made in the event this technique is justified in future investigations.The data presented show that the pressure behavior observed in solids transport in pipes basically applies to slurry flow in horizontal fractures. The roles of the parameters are altered but a basic equivalence exists. The most significant correlating parameter was the oil viscosity (mu) and the bulk velocity of the slurry (vB), expressed as "muv" product.The most significant correlation expresses the rate of advance of the sand as a function of the variables investigated. There are many practical ramifications of this phase of the investigation that should aid in better treatment design. Evaluation of sand advance rates provides a means of estimating sand placement efficiencies during a treatment and the resulting sand distribution in the fracture. The results show that sand placement efficiencies are low under typical treatment conditions. A brief description of the effects of overflushing is also included.
The flow of sand-oil slurries in fractures is an area in which little basic knowledge is available. This stems to some degree from the fact that it is impossible to duplicate fractures at the surface. They occur in various shapes and sizes with an infinite combination of irregularities. Unfortunately, we can never "see" these fractures except in cores and by indirect means of measurement. In spite of this inherent difficulty, it is desirable to develop some basic concepts that will provide a better understanding of the sand transport mechanism.An insight into the problem is provided by investigations of fluid flow in rectangular conduits. Several studies on the flow of liquids in non-circular conduits show that a Reynolds number-Fanning friction factor relationship can be written if the hydraulic diameter is substituted for the regular diameter in a circular pipe. This hydraulic, or equivalent, diameter is taken as four times the cross-sectional area occupied by the flowing fluid divided by the wetted perimeter. Eq. expresses an extension of this same work when applied to infinite parallel planes b distance apart.(1)
where Re equals
Eq. 1 is a theoretical equation expressing the friction factor as a function of the Reynolds number for laminar single-phase fluid flow. This expression has been verified experimentally. The equivalent expression for a smooth circular conduit differs only in that the value of the constant is 16 instead of 24. Numerous studies have related friction losses to Reynolds number in both circular and non-circular conduits. These results are widely used and are not reviewed here.Huitt investigated the effect of surface roughness on fluid flow in simulated fractures. He concluded that fluid flow in fractures may be treated similarly to fluid flow in circular conduits. This work, together with that of Nikuradse, shows that surface roughness has no appreciative effect upon the resistance to flow in the viscous flow region. In the region of turbulent flow, surface roughness is a prominent factor.Hydraulic conveyance literature is another important source of inform ation. Durand has attempted to organize systematically the variables involved in hydraulic-solid transport in pipes. He has classified the modes of flow into three types according to the size of the particles in the mixture-homogeneous mixtures, intermediary mixtures and heterogeneous mixtures. With the usual concentrations and flow rates used in hydraulic transportation, particles with diameters of less than 20 or 30 microns form essentially homogeneous mixtures with water. The data show, however, that even small materials will tend to settle out under laminar flow conditions.Mixtures containing solids over 50 microns in diameter do not achieve total homogeneity even under turbulent flow conditions. Particles from 50 microns to 0.2 mm in diameter may be transported in fully suspended flow at normal transport velocities although the concentration in the vertical plane is not uniform. Above 2 mm in diameter solid materials are transported along the bottom of the conduit at a velocity substantially less than that of the liquid itself. Between 0.2 and 2 mm in diameter, the particles tend to be in a transition zone between heterogeneous suspended flow and deposit flow at normal hydraulic transport velocities. The sand sizes used in fracturing usually fall in this size range.It is interesting to note that the grain size range designated by Durand for this transition zone corresponds closely to the transition zone between
The technological applications which includes cementing system for coalbed methane production, cableless telemetry system, antiagglomerant hydrate inhibitor and olefin drilling fluid are discussed. The cementing coalbed-methane well provides production-quality cement properties and prevents lost circulation in oil seams during cementing operations. The technology involved in the cableless telemetry system is compatible with many in-well sensor systems and well configurations. The inhibitor technology is designed to reduce the cost of hydrate control in deepwater wells by replacing high-volume methanol treatment while the rapid-biodegradation properties of olefin drilling fluid technology improves the land-remediation process.
Over the past decade, well technology has advanced exponentially. Horizontal wells, multiple completions, and wells that cycle between steam injection and heavy oil production have superseded the traditional vertical well with one completion zone.
Advances in the way the oil and gas sector describes and identifies well data elements have not matched the growth in well technology, however. Even the way the sector defines basic well concepts, such as wellbores, completions, and depths, can vary between companies and regulatory jurisdictions.
Several factors have contributed to that inconsistency. The foundation for regulations and well technology dates back more than a century: many terminologies arose when the petroleum sector was in its infancy. Drilling technology has changed dramatically in the past 10 years, yet the regulatory descriptions have remained relatively static. Part of the reason is the lack of international standards; for many years, guidance was offered by the American Petroleum Institute in the US, but lapsed in the 1980s.
The myriad of modern drilling techniques also add to the confusion. Start with a simple producing well, which is wellbore WB1 (Fig. 1). Later, when the operator deepens the well (WB2) and completes new formations (WB2-C1 and WB2-C2), there is some disagreement about whether the deepened segment is part of the same wellbore, or a new wellbore. Of those who think it is a new wellbore, some measure the new wellbore from the surface to the new bottom hole, and some think the new wellbore is only the newly drilled portion.
Many modern wells have far more complex production histories. In Fig. 2, the operator has drilled a pilot well, WB1, with two lateral segments, WB2 and WB3, which are then completed in separate reservoirs. Knowing which production exists in which wellbores becomes far more important; an engineering decision made on incorrect or incomplete information has the potential to create significant repercussions.
In Search of a Solution
The Professional Petroleum Data Management Association (PPDM), based in Calgary, has been working to resolve the issue. PPDM was formed in 1989 and incorporated in 1991. It is a not-for-profit organization that provides data management expertise for the petroleum exploration and production industry. The membership is made up of more than 150 petroleum companies, government agencies, software application providers, data vendors, and service companies.
The petroleum industry generates a large amount of data, including exploration seismic, well drilling, and oil and gas production information. PPDM originally set out to develop an open data model that would allow the industry to reduce costs and allow companies to become more productive, efficient, and competitive. Over the past two decades, industry professionals working as volunteers with PPDM have created a comprehensive data model that benefits a wide array of functions within an oil company, such as well information, surface and mineral rights management, well activities and operations, equipment and facilities management, seismic information, and production and reserves data.
This article is a synopsis of paper OTC 8791, "Risk Assessment of a BOP and Control System for 10,000-Ft Water Depths," by Marc Quilici and Thomas Roche, EQE Intl.; Peter Fougere, Transocean Offshore Inc.; and Dave Juda, Hydril Co., originally presented at the 1998 Offshore Technology Conference, Houston, 4-7 May.
Intervention is necessary during the life cycles of most subsea wells. However, traditional methods can make it time consuming and very costly, with spread rates for drilling and semisubmersible rigs running at USD 1 million to USD 1.4 million per day. There are more than 4,000 producing subsea (wet tree) oil and gas wells worldwide, and the number is increasing by approximately 500 per year. With many wells more than a decade old, intervention is crucial to enable maximum oil and gas extraction.
The sustained rise in deepwater exploration has made the need for cost-effective intervention on wet well trees even more pertinent. With the challenging conditions encountered in deep subsea settings such as Asia, Brazil, West Africa, and the Gulf of Mexico, many wells have produced for several years without necessary intervention. This often results in suboptimal production and reduced ultimate recovery.
The AX-S system, developed by Expro, is designed to provide a safe, riserless, and remotely operated subsea well intervention method that can complete a typical deepwater intervention in six to eight days, compared with 10 to 12 days for a rig intervention, at a cost savings of approximately 75% to 80% based on lower day rates and speedier job completion. The system, designed and built over a seven-year development period with the input of more than 200 vendors, is in the final commissioning stage. Commercialization is expected later this year.
Deployed from a monohull vessel (Fig. 1), the system is the first rigless intervention technology that can operate in waters up to 10,000 ft—several hundred feet deeper than the world’s deepest subsea well. The improved economics afforded by the system will allow operators to increase production and recovery rates in wet tree wells that otherwise might wait additional years for interventions.
To enable deployment of the system, Expro has entered into a multiyear charter party contract with TS Marine Asia Pacific to use its dynamically positioned (DP) multiservices vessel Havila Phoenix for worldwide operations. The DP 2 Class vessel is 361 ft long and 75 ft wide with a moonpool of 23.6 ft by 23.6 ft, a 94-ton fiber rope drum winch with deployment tower, a 276-ton wire rope subsea crane, and two ultraheavy-duty Work Class remotely operated vehicles (ROVs) rated to more than 13,000 ft. The winch and crane are equipped with active heave compensation systems.
DeepStar has evaluated new and emerging technologies for developing small standalone (marginal) fields in 10,000 ft of water in the US Gulf of Mexico (GOM). These studies identified viable field-development scenarios that improve field economics. The studies identified knowledge gaps requiring further investment before these development systems are ready for field application. The evaluation process is described and uses floating production, storage, and offloading (FPSO) vessel development alternatives to illustrate the identification of specific knowledge gaps for FPSO in 10,000-ft water depths.
SPE is celebrating a milestone: our association has reached 100,000 members! From its beginnings as a society within the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) in 1957, SPE has grown to the largest individual-member organization serving managers, engineers, scientists, and other professionals worldwide in the upstream segment of the oil and gas industry. Because of its mission to collect, disseminate, and exchange technical knowledge and provide opportunities for professionals to enhance their technical and professional competence, SPE is still the source the industry turns to for the latest technical advances. But the organization has changed a lot in the past 50 years.
So what does the SPE of today look like? It is no longer just the US-centric association it began as; it is a very diverse global organization. If we made a composite of the several people who joined SPE on the day we hit 100,000 members, the “SPE member” would be from Stony Plain, Alberta, Canada; Dacono, Colorado, and Hattiesburg, Mississippi, United States; Singapore; Al-Khobar, Saudi Arabia; and Perth, Australia. Spanning over 10,000 miles with a median age of 47, this member has a background in production and operations, service and manufacturing, and academia.
Our membership is growing in nearly every SPE region, including those in North America, although our greatest growth is outside North America. Many years ago, SPE’s leaders had the foresight to see the expansion of the oil and gas industry globally and adapt our services and reach when other North American associations did not. Membership has doubled in just the past 10 years, driving SPE to offer more programs and services to a truly diverse industry hungry for information.
With that diversity comes the challenge of how to reach and serve all of our members. To better extend our member services, SPE now operates offices in Calgary, Dallas, Dubai, Houston, London, Kuala Lumpur, and Moscow, and offers technical conferences and workshops in locations across the globe. SPE has also expanded to reach new segments of members, from young professionals with programs including global workshops and a dedicated magazine, The Way Ahead, to new technical areas such as projects, facilities, and construction with a new magazine, Oil and Gas Facilities.
SPE also made it easier for its members to access data. Members can access more technical information online than ever before, including electronic books and the ability to view presentations from more conferences. The development and expansion of OnePetro has given SPE members access to technical information from 14 associations and more than 120,000 articles.
Our society has an impressive legacy, and a bright future. Together we will continue to make it a society of achievement and respect in the industry. But we must be disciplined in what we want and be selective in what we do. We will pave the path to be a high-performance organization and position ourselves to reach our potential. I am looking forward to the new year and the great milestones we will achieve together. I will work tirelessly to do my part in ensuring our continued excellence in existing programs and in developing new programs and services to meet member needs.
Management - This is an excerpt from SPE 152596.
The use of horizontal wells and hydraulic fracturing is so effective that it has been called “disruptive.” That is, it threatens the profitability and continued development of other energy sources, such as wind and solar, because it is much less expensive and far more reliable. Not only that, but compared with coal, natural gas produces only half the carbon dioxide and almost no sulfur, nitrous oxides, or mercury.
Those demonstrable benefits over both traditional and alternative energy draw monetary and political attacks. Some university and media reports have focused on two main environmental concerns about using hydraulic fracturing to recover shale gas:
Groundwater and/or surface-water contamination by methane or chemicals
Escape of methane gas to the atmosphere
These risks come from well construction, transportation of chemicals and fluids to the well site, and operation of the wells and the gas-transport system. This paper is an abbreviated analysis of a larger document on factual information about the purported risks of hydraulic fracturing:
1. Deep-well hydraulic fracturing does not travel through the rock far enough to harm fresh-water supplies. Thousands of field-monitoring tests and millions of fracturing jobs have confirmed this point.
2. In the deep, properly constructed wells that produce most US shale gas, the chance of even minor water contamination from fracturing chemicals is less than one event in a million fracture treatments, based on statistical analysis. When compared with the frequency of pollution from chemical dumps, acid mine drainage, general manufacturing, oil refining, and other energy- or product-producing activities, natural gas from conventional and unconventional sources generates more energy with the least impact and fewest problems.
3. Even as underground fractures grow (mostly outward with limited upward and downward growth), the total fracture extent remains thousands of feet below the deepest fresh water sands. The height of any fracture is limited by rock stresses, leakage of fracturing fluids within the target fracturing zone, and the hundreds of natural rock barriers that border the shale zone. Typical fracture height is 100 to 300 ft and separation between the top of the fracture and the deepest fresh water sands ranges from 3000 to over 5000 ft.
4. Water contamination due to spilled industrial chemicals occurs rarely and even less so for fracturing chemicals and comes exclusively from careless road transport, on-site storage and surface mixing, or well construction. These failings can be addressed successfully with existing technology and effective regulations. It is interesting to note that the states with the fewest problems are those with strong state regulations. Appropriate regulations already exist in most producing states and work very effectively to protect the environment.
The evaluation of recompletion opportunities using pulsed neutron logs is made easier by preparing predictive synthetic logs using openhole log data. Wellsite personnel can assess drainage quickly by comparing the actual log with the synthetic expected response, thus avoiding time-consuming trial calculations.
The pulsed neutron capture (PNC) log has proved to be a valuable production surveillance tool for the U.S. gulf coast environment since its introduction in 1962. In this geographic area, more than 900 PNC logging runs have been made in producing Shell wells alone. We have come to rely on this tool as a reliable aid for basing many of our remedial and recompletion decisions. In conventional PNC log evaluation, water saturation (Sw) calculated from openhole logs is compared with Sw computed from the cased-hole PNC log. Drainage is indicated when a statistically significant difference in Sw is observed. Although this technique is a practical procedure, the calculations can be time-consuming and subject to hidden errors. A nearly foolproof method of assessing drainage from PNC log data is the time-lapse technique. In this method, a base PNC log is run early in the life of the well, preferably before water production begins. When subsequent drainage requires assessment, a second log is run and compared with the first. If the wellbore environment (production equipment, annular fluids) has not changed greatly, differences between the logs can be caused only by reservoir fluid change. The problem with this approach, of course, is the expense and practicality of building a complete base-log inventory. It usually is not justifiable. This paper presents a simple computer technique for creating synthetic base PNC logs using the original openhole log information. Offering many of the advantages of actual base-log data, the computer technique is easy to use and surprisingly accurate. In addition, synthetics can indicate quickly whether a PNC log can be interpreted reliably under adverse conditions. This can help the engineer choose more wisely among evaluation alternatives before a logging commitment is made.
Fig. 1 shows an example of a synthetic pulsed neutron log made using this technique. An openhole gamma-ray induction log is displayed on the left; cased-hole PNC curves (synthetic and actual) are shown on the right. Note the capture cross section curve of a Schlumberger TDT-K (TM) log ("Sigma log"-the dashed curve) run 1 year after the well was drilled and cased. This curve is flanked by two log traces, Sigma i and Sigma d, generated by the computer process using openhole logs. The Sigma i curve represents a "synthetic" PNC sigma curve at initial conditions. It shows what an actural PNC base log would have looked like before the zone was drained. The d curve represents the fully drained condition, in which the zone is totally water saturated. This curve represents the end point of drainage.(Actually, this condition will never quite be reached since some residual hydrocarbon saturation always remains after waterflood in water-wet reservoirs.)
Either move or be moved. - Ezra Pound, American poet, 1885–1972
Flank Speed (a ship’s maximum speed)
Character cannot be developed in ease and quiet. Only through experience of trial and suffering can the soul be strengthened, ambition inspired, and success achieved. - Helen Keller, American author, 1880–1968 (she was blind and deaf from birth)
I will be uncharacteristically brief: if there were ever a time for operating at maximum capacity/capability, then this is it. I ask that everyone reading this column think of 10 tasks/ideas/concepts that they can perform right now that will change their trajectory (and hopefully SPE’s as well), distill those 10 tasks to three, and commit like your life depends on it to performing at least one of those tasks in the next 6–12 months.
Call it homework if you want, but every person reading this column can create, innovate, and deliver some task/idea/concept that will significantly benefit our industry. Don’t say you have more important things to do—this is your profession and your passion. Get started, push directly to flank speed, and get it done. Then move to the next idea on your list. SPE needs its member contributions as never before.
SPE and You
Democracy is finding proximate solutions to insoluble problems. - Reinhold Niebuhr, American theologian, 1892–1971
It is very easy to sit on the fence, but sooner or later the post will hurt you where it counts. You must do something constructive in this life to be alive. More simply, in the words of the British clergyman John Henry Newman, “Growth is the only evidence of life.”
SPE must grow its missions, but its missions must also include what we do now to prepare for the foreseeable future. Energy transition is not a fad; it is a critical path we as an industry and as a professional society must pursue to provide energy for all.
Oil and gas are simultaneously our most secure energy resources, as well as our “battery backup” for situations where renewable options are either unavailable or impractical. Energy sustainability will evolve (I guarantee it), but let’s never forget what will pave the way to that sustainable and renewable energy future—oil and gas. Every conceivable product that is part of the energy transition is either fueled by or dependent on oil and gas as raw materials.
Regardless of how you feel about SPE as a professional organization, it cannot and will not grow into what it must become without your volunteerism and your engagement. I understand that “change=pain,” but we are in a different world now. We can choose to be patient (wait and see what happens), pause (basically be in a state of paralysis), or we can pivot, which is to say that we can push or change/evolve to another path. It is complicated, because in the last year on an individual basis most if not all, of us have done all three.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184846, “Cracking the Volcanic Rocks in India: Substantial Benefits From Continuous Improvements Over 11 Years and 100 Fracturing Treatments,” by Shobhit Tiwari, SPE, Raymond Joseph Tibbles, SPE, Shashank Pathak, Saurabh Anand, SPE, Yudho Agustinus, Punj Siddharth, Rajat Goyal, Vishal Ranjan, SPE, Pranay Shrivastava, Hindul Bharadwaj, SPE, and Pranay Shankar, SPE, Cairn India, prepared for the 2017 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 24–26 January. The paper has not been peer reviewed.
This paper summarizes key engineering discoveries and technical findings observed during the execution of 200 hydraulic-fracturing diagnostic injection tests in the Raageshwari Deep Gas (RDG) Field in the southern Barmer Basin of India (Fig. 1). These tests were conducted in one of the few commercially viable thick and laminated volcanic gas reservoirs in the world. These diagnostic tests were spread over five separate campaigns over 11 years.
Because of the low permeability of this gas reservoir, hydraulic fracturing was necessary for sustained economic productivity. Because this massive laminated reservoir contained between 15 and 40 vertically separated pay sections, a key design consideration was to connect as much pay as possible with the least number of fracturing stages.
Although a conventional plug-and-perforation fracturing technique gives full assurance of optimal fractures for every bit of pay, the completion cost would undermine the project’s economics. Therefore, a limited-entry technique was selected. The uncertainties and risks were evaluated to maximize the probability of success.
More than 60 diagnostic fracture injection tests (DFITs), approximately 90 step-rate tests (SRTs), and approximately 50 minifracture tests have been conducted. In addition to conventional fracture diagnostics tests, other techniques were applied successfully. One such example was the use of multiple SRTs within the same fracture stage to evaluate limited-entry efficiency. As a result of the test data, the number of clusters per fracture stage was increased from three to six, achieving an overall increase in net-pay coverage of approximately 65%.
Hydraulic-fracturing operations and well flowback have several challenges in Rajasthan. Because this is an arid region, a continuous supply of water is problematic at best. In addition, the oilfield infrastructure is much smaller than typically seen in North America, with few suppliers and a dependence on small suppliers for periphery services such as water hauling. Because of these issues, the first campaigns suffered from significant operation delays and cost overruns. Key issues from previous campaigns were evaluated, and various plans were put in place to ensure smoother future operations.
With operational changes, an RDG Field 15-well program set new operational planning and execution benchmarks. The number of fracture treatments per month increased by more than 400%, while the cost per fracture treatment was cut in half. A summary of main operational challenges and their respective solutions is presented next.
In typical oilfield casing design work, engineers specify the force that a casing must withstand. For example, it is generally necessary for each section of a casing string to support the weight of all the pipe that is suspended below. The force and stress are known quantities, and the resulting pipe deformation, called strain, can be calculated using the physical properties of the casing steel.
However, there are situations where the casing loading is of a displacement type, for which the deformation is specified. In this case, the stress is unknown. An example is surface casing subjected to soil subsidence. In soil subsidence, the compacting soils will tend to strain the adjacent casing, and the amount of resulting pipe strain can be essentially independent of the casing properties.
As a part of the Prudhoe Bay permafrost-thaw subsidence studies, Exxon Co., U.S.A., and Atlantic Richfield Co. conducted a testing program to determine the amount of casing strain that would cause failure. The casing tested, 13 3/8-in., N-80, 72-lb/ft buttress, is used as surface casing in many Prudhoe wells.
Three tension tests and three compression tests were made with strain gauges installed as shown in Fig. 1. The compression specimens were of relatively short length (2 1/2 ft) to prevent Euler buckling. (Actual surface casing will not column buckle if it is laterally supported by cement and the formation.) The tension specimens used welded end fixtures to provide a means of attachment to the test machine.
The casing tested was 13 3/8-in.-OD, controlled yield N-80 (normalized), 72-lb/ft buttress, selected from mill runs for Prudhoe Bay. Both mill- and field-end connections were constructed by the torque-turn method, which specifies both minimum turns and minimum torque required for a satisfactory connection. Mill ends were made at the mill with an epoxy thread-lock compound, while the field ends used a teflon thread compound.
Based on metallurgical test coupons, the API yield strength (0.5-percent strain) of this casing ranged from 83 to 92 ksi. The ultimate strengths ranged from 110 to 122 ksi and occurred at strains of 12 to 16 percent. Elongation (maximum strain) was 25 to 35 percent, indicating good ductility. The post-yield behavior was uniform, with plastic moduli of 550,000 to 850,000 psi. Wall plastic moduli of 550,000 to 850,000 psi. Wall thicknesses were uniform, and averaged 0.495 in. (API minimum/nominal is 0.450/0.512 in.2)
The samples were tested at the U. of California Field Research Facility at Richmond. Load increments of 50,000 to 200,000 lb were spaced 5 to 30 minutes apart.
Tension Test Results
Fig. 2 shows the tension axial-strain readings for the D locations, which are located on the pipe 7 in. from the buttress collar. There were three tests, and the mill-end and the field-end gauges provided six sets of data. Test 1 was terminated without failing the casing at a load of 2,250,000 lb and with pipe strains of 3.6 percent (mill end) and 3.7 percent (field end). Tests 2 and 3 experienced fractures near the last perfect thread of the mill end at loads of 2,350,000 and 2,250,000 lb, respectively. The mill-end strains were 3.6 to 4.2 percent.
Fig. 3 shows a comparison of strain data taken at various locations on the casing.
Editor’s note: This is the first of two articles on the technical challenges and regulatory hurdles that were overcome to allow the use of floating production, storage, and offloading vessels (FPSOs) in the US Gulf of Mexico (GOM). The FPSO that will be installed at Petrobras’ Cascade-Chinook development in the deepwater GOM is planned for mid-2010 startup.
The practical start of the journey of the first floating production, storage, and offloading (FPSO) vessel to the US Gulf of Mexico (GOM) came in 1996, when an operator thought that an FPSO might be a viable candidate to efficiently develop a deepwater prospect. Back then there were a number of FPSOs in operation in different parts of the world, so the idea was not revolutionary. Several conference papers at the time showed potential arrangements for an FPSO at Texaco’s Fuji development. As events unfolded, estimates of reserves were not as good as initially expected and the Fuji prospect was abandoned, but the idea of considering an FPSO in the GOM had taken hold.
During 1998–1999, Shell and its partner BP conducted feasibility studies for using an FPSO at its Na Kika development, involving study work by leading FPSO contractors. These studies were not just simple paper exercises, although traditional paper studies were made. Groups of facilities and subsurface experts met, examining every aspect of proposed candidates for field development and debating the pros and cons of solutions. Many in the industry may not appreciate the rigor of these debates unless you were in the middle of them. And in the middle of all this was a patient, objective participant, bringing out the best in everyone, George Rodenbusch of Shell (see sidebar).
Despite every consideration given to the FPSO option, all these debates and studies led to the conclusion that for the particular field at hand an FPSO was not the best solution, and today a semisubmersible is the centerpiece of the Na Kika development.
Again in 2000–2001 a supermajor looked exhaustively at the FPSO option but, weighing the regulatory uncertainties at the time and competitive pipeline economics, the FPSO and shuttle-tanker combination lost out to spars and semisubmersibles. About this time another development for another operator prompted presentations at an SPE lunch meeting in Houston showing shuttle tankers and an FPSO as the way to go. But that development became a tension leg platform (TLP), exporting via pipeline to produce that asset.
During this period some operators—often from outside the US—concluded that there was prejudice in the US against FPSOs, but the evidence of these repeated considerations of FPSOs over the years does not bear this out. Regulatory expert Rick Meyer of Shell summed it up in a presentation at an SPE workshop in 2002: “Economics, economics, economics.” It was more a matter of just not having the right project for an FPSO in the GOM.
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 78318, "Controlled Acid Jet Technique for Effective Single Operation Stimulation of 14,000+ ft Long Reservoir Sections," by J.H. Hansen and N. Nederveen, SPE, Mærsk Olie og Gas AS, originally presented at the 2002 SPE European Petroleum Conference, Aberdeen, 29-31 October.
This article is a synopsis of paper OTC 11891, "Gyrfalcon: World's First 15K Subsea Development," by Robert L. Byers, Reading & Bates Development Co.; Richard E. Trevitt, Total Offshore Production Systems; and William R. Philliber, Intec Engineering Inc., originally presented at the 2000 Offshore Technology Conference, Houston, 1-4 May.
History of Artificial Lift
On 27 August 1859, near Titusville, Pennsylvania, USA, “Colonel” Edwin Laurentine Drake found “rock oil” in a well he deliberately drilled to produce it.
It was not just the oil that ushered in the modern petroleum era, but also the rig and tools Drake and his driller, saltwater-well expert and blacksmith “Uncle Billy” Smith, used to drill and pump the oil from the well.
“[T]he production end of the fledgling oil industry was able to launch its phenomenal expansion,” writes hydraulic pumping pioneer Clarence J. Coberly in “Production Equipment” (History of Petroleum Engineering, American Petroleum Institute, 1961), “with the almost-identical tools and techniques that had been developed in the waterwell industry.”
The greatest influence on the initial production equipment used by the oil industry, writes Coberly, resulted from the cable tools used to drill the wells: “The oscillating walking beam—a simple and effective means of lifting and dropping the bit—was also well-suited for operating the bottomhole plunger pump once the well was completed. Both drilling and pumping loads were small enough to permit the use of wooden structural elements with a few pieces of iron to serve as bearing points. As crude as the rig was, it was effective and inexpensive.”
Coberly also notes that almost all advances in drilling and producing methods relied either directly or indirectly on the use of casing. The first cased well was likely in 1861.
Within 10 years of Drake’s discovery, well casing was routine and conventional pumping equipment was well-established as consisting of what is now known as the “standard rig front.”
History: Sucker-Rod Lift (Beam Pumping)
Pumping by combining a walking beam and sucker rods extends back at least to 476 CE, when the walking-beam principle was known to have been used in Egypt. In addition, archeologists—when excavating wealthier families’ homes that existed in the early days of the Roman Empire—have found double-acting pumps, made of cast lead, with plungers made of wood and leather. Roman sucker rods were made of wood and worked in compression.
Microcomputers have been around for several years now. Bringingthis technology to small, sometimes remote operations, however, hasproved to be a formidable task. We decided to apply this technology asa maintenance function-specifically, a pilot test of a small maintenance management system at a remote gas-processing plant.
In late 1983, Mobil E and P Services Inc. (MEPSI) becameinvolved in evaluation of maintenance managementsystems based on microcomputers. Continuous feedbackfrom our operating units indicated that such a system would be useful. After several existing packages wereinitially screened, we determined that there probably wasnot a package that met our requirements. We found packagesthat satisfied part, but no single package had all the functions we required. We then requested the help of alarge international consulting organization to develop sucha package. Subsequently, a contract was developed withthat organization.
As part of the contract, we agreed to perform a pilottest at one of our gas plants. The pilot test had two primaryobjectives:determine whether useful hardware andsoftware could be installed and used by regular operating personnel anddetermine whether the system wascost effective.
Background on Pilot Project
The La Gloria gas plant near Falfurrias in south Texaswas chosen as the test site. The primary reasons forchoosing the La Gloria plant were as follows.An existing manual preventive maintenance (PM)program already in place and functioning well allowedthe transfer of existing manual maintenance proceduresto the computerized system with a minimum ofadjustment.A concentration of equipment located within the plantfence eliminated the logistics of coordinating the flow ofinformation over a large regional area.An operating warehouse allowed the testing of theinventory-control functions of the software.Experienced supervisors on site understood theadvantages and benefits of a planned maintenance program.
The plant uses a basic cryogenic process to handleapproximately 115 MMscf/D [3.3x10(6) std m3/d]. Thecritical equipment items that were made a part of thepilot test are shown in Table 1. A simplified schematic ofthe process is shown in Fig.
Schedule. A schedule was developed to judge the pilotproject. This schedule also provided the plant supervisorswith an estimated time of personnel commitment. Theproject schedule is shown in Fig.
Personnel. It was necessary to set up a project structurethat would allow sufficient project control but also allowthe other parties to interact. The project structure is shownin Fig.
The database group is an extremely importantpart of the project structure because of the importance ofthe database accuracy. They must be dedicated 100% tothe project. The maintenance supervisor worked closelywith the database group to ensure that valid, up-to-dateinformation was gathered and entered.
Data Bases. The first major task was to organize and totake inventory of the warehouse. Even though the warehousehad been in operation for some time, it had been operatedon an evolved informal system. A coding system andorganizational scheme were set up to identify eachpart and its location within the warehouse. Theidentification and tagging of existing items proved to bedifficult. Some of the equipment, such as the reciprocatingcompressors, had been installed in the late 1940's. Thedata-base group had to rely heavily on the knowledge of thewarehouse operator and the maintenance supervisor toidentify many spare parts correctly. An example of awarehouse database entry is shown in Fig.
At the same time the warehouse was organized, basicequipment data were gathered. Equipment nameplateinformation, along with location and service data, wasentered. The equipment data would eventually form the nucleus for the inventory and work-order parts of thesystem. Once the nameplate data were entered, each pieceof equipment could be subdivided into identifiablecomponents to which individual parts could be assigned. An example of an equipment database entry is shown inFig.
The documentation of the existing maintenance routineswas used to define standard tasks. These tasks werecompiled, coded, and entered into the program. It was thenpossible to set up the various planned and predictive maintenance work orders. Again, the maintenance supervisor's
In May 2020, I wrote an article for JPT that tried to make sense of what was happening to the oil and gas industry. Remember, this was after the discovery of the pandemic that shut down the world’s economy for many months. Factories and businesses went dark. Roads were empty. People were hunkering down, not knowing or understanding how bad this virus was.
All of this meant that demand for hydrocarbons came to a screeching halt. I had just listened to the earnings calls from Halliburton, Schlumberger, and Baker Hughes, and the outlook was doom and gloom—every executive was trying to reduce spending by millions of dollars.
This came to the detriment of scores of employees and especially those within technology departments—many of which were shuttered.
I said at the time that the industry should be satisfied with whatever technology was available because it would be several years before we would see any new technology. So, how did I do in my prediction?
I will let you judge, but I think we have seen examples of spin being put on what amounts to normal work. Any advancements are mostly cosmetic, with no real, new groundbreaking developments. Now that 2 years have passed and we are cautiously looking around the corner at the world opening up, what do we have to look forward to?
Once again, I listened to the first-quarter earnings calls from the “big three” oilfield services (OFS) companies. The outlook was much more optimistic, and we heard some of the new slants on those calls.
When I wrote the original article in 2020, the letters “ESG” were seldom mentioned in conversation, and especially not on earnings calls. Now, the OFS companies are all about what they are doing to seduce those ESG investors.
Why are they worried? Because all the “traditional” big money that once went into the old-fashioned oil and gas sector is now being swayed by this “new” concept of ESG, which is simply the criteria around environmental, social, and governance practices in any company.
Note: The situation with the spread of the virus and government and company responses to it is very fluid. To meet press deadlines for JPT, this piece was written in mid-March. As the situation evolves, SPE will update this note at www.spe.org and individual event or other activity websites with the latest information.
Networking is core to SPE activities, whether through an event, a local section meeting, service on a committee or other activity. The rapid spread of the COVID-19 virus globally is having far-reaching impacts across SPE activities. SPE has acted quickly, first in Asia Pacific, then elsewhere, to avoid increasing potential member and staff exposure. To date, SPE has postponed a number of conferences and most workshops including the following (see event websites for more details).
OTC Asia, Kuala Lumpur
Oman Petroleum & Energy Show, Muscat
International HSE Conference, Bogota
Latin America and Caribbean Petroleum Engineering Conference, Bogota
Canada Heavy Oil Conference, Calgary
Canada Unconventional Resources Conference, Calgary
Norway Subsurface Conference, Bergen
Offshore Technology Conference, Houston
By the time you are reading this, it is very likely that more events will have been postponed. By postponing, rather than canceling these events, we ensure that the significant work of program committees and authors to prepare for these events covering important technical topics will not have been wasted.
In a few cases, it may be necessary to cancel an event. Thus far, this includes only the SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas. Canceled events are most likely annual events and postponing by a few months would harm the next edition of the event. We are actively investigating options to allow those presenting papers at these events to do so in a digital format to share the content.
In determining whether to postpone an event, SPE is taking into consideration the following factors:
Conditions in the location where the event is to be held
Mix of local and international participation expected at the event
Guidance from key companies for the event about employee travel and participation
Most of the Distinguished Lecturer (DL) tours for March and April have been canceled either due to the situation in the region to be visited or company travel restrictions. We are exploring virtual and digital options for the DL program. SPE has pro-vided some guidance to sections on their decision-making regarding local events, recognizing these are decisions best made at the local level. SPE will use criteria similar to those above in determining how to proceed with activities such as Regional Officers Meetings, Student Paper Contests, and PetroBowl Regional Qualifiers.
We are seeking ways to enable remote participation in as many activities as feasible. Our emphasis in all cases is on local conditions and the health and safety of participants. SPE will continue actively monitoring the situation and potential impacts on future activities. The health and safety of our members, attendees, and staff is our highest priority, and that will guide any decisions that we make.
In the 1940s, the majority of research in America into shaped charge technology was performed by the US military and government laboratories. Information was largely classified. Shortly after the US Army declassified some details of this technology, extensive research and testing began in many American companies. Along with this came the filing of several patents. These US patents from the early years of shaped charge design reveal a transition from an almost naive optimism over the nascent technology to solutions for oilfield issues. A focus on the early claims and the issues with carriers and charge detonation reveals much in this regard.
The Early Years—Optimism and Uncertainty
A patent filed by E.I. du Pont de Nemours and Company in 1942 (2399211) typified the wave of optimism of shaped charge capabilities (this was not too unexpected, for du Pont manufactured the charges) (Fig. 1). Liners for the charges were not required, stated the document, but if they were present the metal slugs (“carrots”) produced from the detonation would be “projected at very high velocity through the perforation and into the adjacent strata.” In other words, the liner remnant was a positive consequence of the detonation. The patent also advocated the use of plastics or cardboard materials for the carrier, stating that the charge “may or may not be enclosed in a watertight container…they are generally insensitive to the action of water and impervious thereto.”
Two years later, another du Pont patent (2605703) described a “novel and improved explosive device.” The document provided many details about shaped charge liners, but admitted that an understanding of why the devices worked was unclear and speculated the penetration was due to “pulverizing, molecular fragmentation or abrasion.” Even the liner was considered a contributing factor in the “net destructive effect,” but the patent admitted it “was not possible to determine this.”
A Gulf Research and Development Company patent filed in 1945 (2494256) proposed a panoply of shaped charge configurations—as if to cover all possible uses. The document mentioned “numerous results of our experiments” that verified the penetrating power of the lined shaped charge and revealed the charges should be “provided with a suitable cover to pre vent any liquid entering the cavity (the liner).” The patent optimistically predicted that a slug would be “sufficiently small to pass through the hole in the casing and come to rest deep in the formation where it has negligible effect on the flow of fluids through the hole.”
Before there was SPE, there was AIME. The Society of Petroleum Engineers had its origins in the American Institute of Mining Engineers, an organization created by a small band of Pennsylvania miners in 1871 to help promote and develop their trade. Petroleum was not part of the institute's original charter, but after the historic Spindletop oil gusher blew in at Beaumont, Texas, in January 1901, oil gained new significance. SPE's history then followed the trajectory of the oil and gas industry—it began as a small AIME committee in the industry's infancy, grew in stature as the science and technique of applying engineering principles to oil production took root, and blossomed after World War II when it became apparent that the world was going to run on oil.
Captain Anthony Lucas, an Austrian native and the engineer behind the Spindletop discovery that ushered in the modern oil industry, was one of SPE's founders. Lucas was not your average saloon-and-boom-town wildcatter, but a pioneer petroleum engineer who studied and understood geology. Shortly after the Spindletop gusher, Lucas delivered a paper on the technical details of the discovery at an AIME gathering. He had used a relatively new technology, rotary drilling, to make his famous discovery. Three years later, Lucas would exemplify his understanding of the need for appropriate production methods and conservation, commenting that Spindletop's rapid decline came from being "punched too full of holes." He added: "The cow was milked too hard, and, moreover, she was not milked intelligently."
By 1913, oil had achieved enough prominence to deserve its own small committee in AIME, and Lucas became its first chairman. Petroleum engineering as a profession was growing, and some universities began teaching petroleum engineering courses. By 1922, the 11-member committee had evolved into the Petroleum Division of AIME, one of the institute's 10 professional divisions.
Other historic oilmen besides Lucas were instrumental in forming what eventually would become SPE, including Everette L. DeGolyer, often called the father of applied geophysics. In fact, pioneer petroleum geologist Wallace Pratt called DeGolyer—a founder of the American Association of Petroleum Geologists (AAPG)—the "true father" of the Petroleum Branch, which succeeded the Petroleum Division and eventually would become SPE.
"I think it is valid to declare that, but for De (DeGolyer), the Petroleum Branch would not have come into being when it did," Pratt wrote SPE Executive Secretary Joe B. Alford in 1957. "At the time the Petroleum Branch first began to take form, there was considerable opposition to it, among both geologists and engineers. Resentment and jealousy were rife. De lent his support and influence to the project of a Petroleum Division. Numbers of his friends opposed the new division. For one thing, they were hostile to AIME, and, for another, they planned to bring the petroleum engineers into AAPG. DeGolyer, with great energy and industry and no little courage, persisted in his efforts and finally put into execution the plans he himself had worked out for the new society."
The year 1957 was a time of advancement in technology, science, and education around the world. On 16 January, three B-52s took off from Castle Air Force Base in California on the first nonstop, round-the-world flight by jet plane, which lasted 45 hours and 19 minutes. The "space age" began on 4 October when the Soviet Union launched Sputnik, the first man-made space satellite. This led to the US's first attempt at putting a satellite into orbit, which failed when Vanguard TV-3 blew up on the launch pad at Cape Canaveral, Florida, on 6 December 1957. The complete microscopic theory of superconductivity was proposed in 1957 by John Bardeen, Leon Cooper, and John Robert Schrieffer, and the Treaty of Rome was signed by France, West Germany, Italy, and Benelux, establishing the European Economic Community.
In medicine, there were several breakthroughs, such as the invention of the temporary artificial heart by Willem Kolff. Alick Isaacs and Jean Lindemann produced interferon, and the internal pacemaker was created by Clarence W. Lillehie and Earl Bakk. Less dramatic events that year included the introduction of the electric watch by Hamilton Watch Company and the Frisbee by Wham-O, and a patent was awarded for Velcro.
Among these historical moments in politics, science, and popular culture came the official creation of SPE. John P. Hammond, 1957 President of the SPE of the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME), led the society through its first year of transformation. Hammond, who had graduated from the University of Tulsa, was Assistant General Superintendent of the Production Department of Amerada at the time. Since joining AIME in 1938, he held numerous chairman positions within local sections and committees.
In the beginning, SPE meetings were held only in the US and Caracas, Venezuela, and most meetings took place in Texas and Louisiana, where the oil business was thriving. As membership increased, meetings cropped up in places such as Montana, California, and West Virginia, with meeting locations dependent on local section support. To hold a meeting, a section or a sufficient number of members needed to be able to sponsor and prepare the event. SPE's meeting schedule in 1957 was as follows:14–15 February, Joint Annual Technical Meeting, University of Texas and A&M College of Texas, Austin, Texas24–28 February, AIME Annual Meeting, New Orleans18–19 April, Permian Basin Oil Recovery Conference, Midland, Texas23–24 May, Third Annual Joint Meeting, Rocky Mountain Petroleum Sections, Billings, Montana6–9 October, SPE of AIME Annual Fall Meeting, Dallas17–18 October, Southern California Petroleum Section Fall Meeting, Los Angeles17–18 October, Second Annual Conference of the Electrical and Radioactivity Logging Oil Institute, Abilene, Texas6–9 November, Second Annual Regional Meeting, Venezuela Petroleum Sections, Caracas8–9 November, Central Appalachian Section Annual Meeting, White Sulphur Springs, West Virginia
During the 1970s, SPE evolved from a technical organization into a technical-professional society, established firm groundwork for international expansion, and began to map its future course through its first Long-Range Plan.
It was a momentous decade for both the oil and gas industry and for SPE. Energy was front and center in international political debate. Oil came under heavy scrutiny from politicians and the public as air and water pollution, company profits, oil embargoes, OPEC's ascendancy, gasoline shortages, and government regulation dominated the news. The decade began with the first politically charged "Earth Day" and ended with the Iranian revolution and the second
For SPE, it was a decade of soul-searching. Just what was the society and in what direction should it go? Should it join—or avoid—the contentious political debate of the times? Was it an organization just for disseminating technical information, or should it be concerned with the larger issues of professionalism and the public standing of petroleum engineering? Was it an adjunct of an American organization, AIME, or should it embrace the internalization of the oil industry, which was rapidly tearing down artificial borders?
Air and water pollution emerged as a leading subject of debate, and government regulation began to affect members' jobs. Pollution control was the main topic of the 1970 Fall Meeting in Houston. Representatives of government, the industry, and academia were featured in two 5-paper technical sessions covering petroleum technology and its impact on pollution and oil-spill control. Technical papers at other meetings and in the pages of JPT also addressed these topics. Beginning with the passage of the US National Environmental Protection Act in 1970, the oil and gas industry faced a flood of new regulations. The US Congress passed 14 major federal statutes between 1970 and 1980, including the Clean Air Act and the Clean Water Act, designed to protect the health and safety of people and the environment. These statutes generated thousands of pages of regulations at both the federal and state levels, and most of them affected E&P operations.
The media were rife with stories about pollution and the oil industry's role in it, articles that often were plagued with inaccuracies. Several SPE local section officers, particularly those from the Gulf Coast Section, began to lobby the SPE Board of Directors for permission to establish a public affairs committee that would work to correct technical inaccuracies being presented to the public. The SPE Board concluded that the best way that the society could contribute to the public debate regarding environmental matters was to provide a forum for the dissemination of knowledge on the technology for improving environmental quality, and to establish a literature base on environmental quality as it applied to the industry. The Board also approved a plan permitting members to participate in public affairs by contributing interpretations of technical issues. The plan allowed local sections to establish Technical Information Committees (TICs) to offer assistance to local civic and government groups and to the news media on matters involving E&P. By the end of 1971, seven TICs had been formed throughout the US.
SPE made additional strides in internationalization and membership growth during the 1980s. Despite the free fall in oil prices that would mark a low point for the oil and gas industry during the decade—and lead to massive layoffs and restructurings—SPE not only survived, but in some ways thrived.
In 1980, membership rose 14% from the year before to 38,799. By now, a fifth of the society's membership resided outside the US and several regional meetings around the globe had developed. As membership and the diversity of members' technical interests grew, SPE was challenged to ensure that its meetings and publications were relevant to the specialist while appealing to a broad spectrum of disciplines. The scope of SPE's defined technical focus began to expand and include such interests as unconventional resources, geothermal energy, shale oil recovery, and facilities.
Ken Arnold, Senior Executive Vice President of AMEC Paragon and SPE's first Technical Director for Projects, Facilities, and Construction, was instrumental in getting SPE to offer more programs and services for facilities engineers. He chaired an ad hoc committee in the early 1980s in investigating SPE's relation to facilities engineering. "We presented to the SPE Board a plan outlining how we could provide more service to this group, with hopes of increasing its membership," Arnold said. "In those days, facilities engineering was not even considered a specialty; it was part of production operations. … One of the key recommendations that was implemented was the creation of a committee within SPE for facilities. It started to create programming for at least three or four sessions at each SPE Annual Technical Conference and Exhibition (ATCE), and that began to generate papers. Another thing we did was, when the SPE Production Engineering technical journal was first put together, we added a review chairperson and a technical editor committee for facilities topics to make sure that journal had facilities content."
Early in the decade, an ad hoc committee began to review the society's first Long-Range Plan, which had been adopted in 1976. It advised several changes that reflected the society's increased international presence and the importance and strength of local sections. The committee recommended adding director positions representing the Middle East, Asia Pacific, and South America, in addition to the one non-US director on the board from Europe. It proposed several other additions, including recommendations thatSection financial procedures include annual budgets and auditsThe society offer more continuing education support to sectionsSections establish their own newslettersSections create annual section awards and plans for officer rotationSPE become more involved in intersociety activitiesChanges should be made to SPE election procedures, including allowing members, for the first time, to select SPE regional director nominees through regional nominating committees.
Special Section: The Value and Future of Petroleum Engineering
Contrary to popular imagination, which favors John Wayne stereotypes heroically rescuing the oil industry with wrench and hammer, the oilfield is a place of exquisite engineering, the match of anything on Earth, a marvel of innovation at the biggest and smallest scales.
The office-block sized blowout preventers on the ocean floor or the minute geopositioning electronics inside a logging while drilling (LWD) tool both are designed to operate perfectly within exacting environmental specifications. Almost every aspect of upstream exploitation is the result of exhaustively leveraging the glorious value chain of math, science, and engineering.
Along this trajectory, failure is met more often than success, as ideas and developments are tried out and eventually fine-tuned until something begins to work reliably. The journey is not for the faint-hearted. Whether it be one obsessive individual or a team with an equal desire to win, both energy and imagination must be sustained at every hurdle, to force progress and eventual success. This is as valid for the glamorous game-changing innovation as it is for a leap-of-faith improvement to existing technological practice.
Since the 1980s, our industry has experienced a technology renaissance all along this innovation spectrum—the oil price volatility in this modern era of our industry certainly focused minds on doing things more efficiently at less cost. As a celebration of these years of technical innovation, we now make so bold as to list perhaps 10 of the most significant contributions.
No doubt it is foolhardy to propose such a list because we all have an opinion on what should be on it. Nevertheless, there is surely enough common ground to guarantee some degree of objectivity. What may be objectionable is limiting the number to 10. Within that constraint, however, just the intellectual and practical bravado displayed surely merits all 10 to be included.
1981: Horizontal Wells Increase Production
The Soviet Union pioneered horizontal wells in the late 1960s only to turn its back on furthering the development of the practice in favor of vertical wells that were easier and faster to drill. But the mantle was picked up by Jacques Bosio, a drilling engineer with French oil company Elf Aquitaine, which needed horizontal drilling to intersect fractures and increase production from a karst reservoir found off the Italian coast, the Rospo Mare field.
In 1981, for twice the cost of a vertical well, horizontal drilling was sanctioned. The first well would bring in 3,000 B/D—more than 20 times its off-set vertical well. By the mid-1980s, horizontal drilling was seeing wider adoption as a way to target thin oil and gas reservoirs in Texas, the Middle East, and the North Sea. Operators had known about these skinny hydrocarbon- bearing layers for years—now they had a way to contact them with enough surface area to make money. Bosio would go on to become the first SPE President from outside the US, in 1993.
In March 1982, the Secretary of Energy requested the Natl. Petroleum Council (NPC) to evaluate the EOR potential of the U.S. The NPC Committee on EOR was formed to fulflll this request. Under this committee, a coordinating subcommittee and four working task groups were selected to perform the study. This paper describes the work of the Miscible Displacement Task Group and reports their findings and conclusions on the potential for EOR by miscible processes in known U.S. reservoirs.
In conjunction with the coordinating subcommittee and the other task groups, the Miscible Displacement Task Group helped upgrade the DOE reservoir data base into the most comprehensive data base available to date on U.S. reservoirs.
A miscible process and economic screening model prepared under contract for the DOE was analyzed, modified, and calibrated by the Miscible Displacement Task Group for this study. With physical screening parameters, the Miscible Displacement Task Group selected reservoirs susceptible to miscible processes from the data base, and then processed them with the NPC model to estimate tertiary oil recovery. Sensitivity to oil prices and rate of return (ROR) were investigated, and the results were combined with the results from the other process task groups (thermal and chemical) to reach an overall assessment of the EOR potential in the U.S.
The potential EOR for miscible flooding is estimated to vary between 2.0×109 and 8.5×109 bbl [0.32×109 and 1.4×109 m3] over the range of prices and technologies considered. Peak rate varies from 200×103 to 980×103 B/D [32×103 to 156×103 m3/d] for the cases investigated.
Field tests and full-scale operations of EOR have increased in recent years. Research in the basic fluid behavior and specific reactions of reservoir fluids to heat, chemicals, and miscible fluids have increased industry knowledge of EOR processes. These activities and the growing importance of increasing potential oil recovery in the U.S. prompted the Secretary of Energy to request the NPC to evaluate the EOR potential from known reservoirs. This paper reports on the methodology used and results developed by the Miscible Displacement Task Group.
Miscible floods to date have used CO2, N2, and hydrocarbons as miscible solvents. Commercial hydrocarbon miscible floods have been operated since the 1950's. CO2 miscible flooding on a large scale is relatively recent, and CO2 is expected to be the significant solvent used in the future. There were at least 11 commercial, large-scale CO2 projects under way in Dec.
Several additional commercial projects have been started in west Texas. Since then, development of natural sources of CO2 in Colorado, New Mexico, and Mississippi are in progress. All these activities indicate that CO2 miscible flooding will be a significant EOR process.
In this study, two levels of technology, designated as implemented and advanced, were considered. The implemented-technology case is based on current project design used in recent field projects. A CO2 slug size equivalent to 40% of the HCPV was assumed, along with a water-alternating-gas (WAG) ratio of 1.5:1.
The advanced-technology case assumed that certain improvements in technology would be developed and available for full-scale operations in 1995. For reservoirs with moderate heterogeneity, those with good waterflood sweep efficiency, the volume of CO2 injected was increased. For more highly stratified, heterogeneous reservoirs, it was assumed that "foam" chemicals would be developed to control the flow of CO2 and to improve the sweep efficiency. The estimated potential for miscible EOR from known reservoirs varies between 2.0×109 and 8.5×109 bbl [0.32×109 and 1.4×109 m3] over the range of oil prices considered. The peak rate of EOR production from miscible flooding varies between 200×103 and 980×103 B/D [32×103 and 156×103 m3/d] for the same cases. These ranges cover both the implemented- and advanced-technology cases.
Related papers: SPE 13239, SPE 13240, SPE 13241
Related discussions and replies:SPE 18397, SPE 20007, SPE 20009
The single most important productivity improvement in the history of the petroleum business may have been the implementation of horizontal wells. The engineering and economic challenges its early innovators faced were steep, but rapid advances between 1984 and 1994 progressively broke down the challenges. A Shell executive once confided to me that, in the early days of that period, one needed permission to plan horizontal wells, but by the late 1990s, one needed permission not to plan one. That is the hallmark of a "disruptive technology"—at first it is viewed with suspicion and elicits risk avoidance, but after industry acceptance, the technology becomes the norm and deviations from it are viewed with disapproval by the very people who questioned the technology in the first place.
In the late 1970s, Teleco perfected the technique to measure well position and direction while drilling. Then it and others added important lithology-marker technology in the form of natural gamma and resistivity measurement. The early days of measurement while drilling (MWD) were marked by low reliability, but the industry persevered because of the cost savings in not having to stop to make openhole position measurements. Positioning in 3D space was now available on the fly.
The First Reports
Horizontal wells were still a curiosity. Then, in the early 1980s, reports started trickling in of directional drillers trying something really different. They were making radical angular changes using a nonrotating drillstring, with a motor for propulsion and a bent sub for angle build. But instead of following convention, which called for pulling the string and drilling the new section without the bent sub and motor, they drilled ahead with the assembly, this time rotating the string and providing motive power by the rotary and the motor. The bent sub in a rotary mode held angle, and the steerable system was born.
Groundwork for Advancement
I still remember reading the first such report—I thought the authors were nuts! Bent sub flopping around: What would that do to the hole shape, and what about stressing the string? Well, as it turned out, these were tractable issues and one more brick was in the wall to enable efficient angled drilling. Note that, once again, the advance was to eliminate a rig-time hog. The significance was that the early horizontal wells cost roughly 2.7 times as much as conventional wells, and while well productivity was higher, reduction in well cost was an important objective in those days of decision silos that separated drilling and reservoir actions. There are some who believe, and I can be counted among them, that horizontal wells were a trigger for sustained integrated decision making, although clearly the shift to asset units, which occurred during the same time period, was a significant driver. Decisions about wells were made now not by functional units, but by asset teams made up of representatives from the functional units. These events, together with the key advent of formation evaluation while drilling (FEWD), laid the groundwork for this significant advance.
During the 1990s, SPE took significant steps to ensure that it remained valuable to the practicing petroleum professional. It became truly international, continuing the mission that had begun more than 2 decades earlier; it opened offices outside the US and broadened board representation to enhance global member needs and services; it expanded programming to keep up with demographic and technological changes sweeping the industry; and it entered the electronic age, streamlining internal processes and giving the industry a powerful and effective Web tool.
The next decade and a half would see SPE broadening its presence on the ground throughout the world. In 1990, the SPE Board voted to open an office in London to coordinate activities in Europe, Africa, the Middle East, and India. At the end of 1981, SPE had 3,837 members, excluding students, in these regions—just under 10% of total membership. But by year-end 1990, membership in those regions had almost tripled and now represented 21.5% of total membership. During the same period, membership in the US had declined more than 5%. An office in Kuala Lumpur would open in 1995 to improve member services in the growing Asia region, and an office in Dubai to bolster Middle East activities would follow in 2003. This year, SPE will open an office in Russia.
That international trend was borne out in total membership growth as well. Overall membership grew by a third in the 1980s, despite the severe industry contraction, thanks to non-US growth. Total membership rose from 38,799 in 1980 to 51,586 at the end of 1990. Non-US membership more than doubled, from 7,876 in 1980 to 17,127 at the end of 1990. Members residing in countries other than the US now represented a third of total membership, and international growth would continue in the new decade. Eight new sections from seven countries and five new student chapters received charters in 1990, for example, putting the total number of countries with SPE sections or student chapters at 41. Among the new sections formed were ones in Mexico, Germany, Nigeria, Congo, and Bombay, India. New student chapters were formed in the United Arab Emirates and Yugoslavia. International growth was increasingly reflected in the makeup of SPE programs and services.
But perhaps the most symbolic event representing this trend came in 1991, when the society's Nominating Committee selected Jacques Bosio to become 1993 SPE President. Bosio, an executive with Elf Aquitaine Production in Paris, would become SPE's first non-US president.
"SPE was perceived as 100% US at one time, but it was opening new sections every year outside the US and appeared to be going in that direction," recalls Bosio, who had helped establish the SPE France Section in the early 1980s. "Fortunately, some presidents before me, such as Orville Gaither and Kenneth Robbins, had vision and realized that the center of gravity of the oil business was moving east.