Natural gas-hydrates are an unconventional source of energy. Potential reserves of hydrated gas are over 1.5 × 1016 m3 and are distributed all over the earth both on the land and offshore. Presently, in many countries national programs exist for the research and production of natural gas from gas-hydrate deposits. As a result over 220 gas hydrate deposits have been discovered, more than a hundred wells drilled, and kilometers of hydrated cores studied. Properties of the hydrated cores have been investigated, effective tools for the recovery of gas from the hydrate deposits prepared and new technology for the exploration of gas-hydrate fields developed. The commercial production of natural gas from gas-hydrates exist for many years now with good results. Still, many complex problems have to be studied. More high-level studies on the properties of the gas-hydrates are needed and new technology for the production of natural gas from gas-hydrates has to be developed. Note, it is not the amount of potential reserves of hydrated gas that is important, but the volume of gas that can be commercially produced (17 – 20% from potential).
We report the stochastic reconstruction of chalk pore networks from limited morphological information that may be readily extracted from 2D backscatter electron (BSE) images of the pore space. The reconstruction technique employs a simulated annealing (SA) algorithm, which can be constrained by an arbitrary number of morphological descriptors. Backscatter electron images of a high-porosity North Sea chalk sample are analyzed and the morphological descriptors of the pore space are determined. The morphological descriptors considered are the void-phase two-point probability function and lineal path function computed with or without the application of periodic boundary conditions (PBC). 2D and 3D samples have been reconstructed with different combinations of the descriptors and the reconstructed pore networks have been analyzed quantitatively to evaluate the quality of reconstructions. The results demonstrate that simulated annealing technique may be used to reconstruct chalk pore networks with reasonable accuracy using the void-phase two-point probability function and/or void-phase lineal path function. Void-phase two-point probability function produces slightly better reconstruction than the void-phase lineal path function. Imposing void-phase lineal path function results in slight improvement over what is achieved by using the void-phase two-point probability function as the only constraint. Application of periodic boundary conditions appears to be not critically important when reasonably large samples are reconstructed.
An experimental study was conducted to examine the effectiveness of sodium carbonate in alkali, surfactant and polymer combined slugs in recovering waterflood residual oil. The effects of sodium carbonate concentration on the slug viscosity, interfacial tension, and phase behavior were first examined. Core flood experiments were conducted with unfired linear Berea sandstone cores. The incremental oil recovery, oil cut, residual resistance factor, and chemical propagation were measured for each flood.A significant oil bank was formed for all combined slugs having sodium carbonate concentration ≥1 wt%. The incremental oil recovery, oil cut and the injectivity of the combined slugs greatly improved as sodium carbonate concentration was increased. The effect of sodium carbonate concentration on chemical propagation was dramatic for the synthetic surfactant; a slight delay in surfactant breakthrough and a much slower rate of surfactant propagation were observed at high sodium carbonate concentrations.The results obtained in the present study indicate that the residual oil was recovered by two mechanisms: low interfacial tension and wettability reversal. The former mechanism is dominant at sodium carbonate concentrations ≤1 wt%, whereas the latter plays an important role only at high sodium carbonate concentrations.
In this paper, the basic features of 3D (spatially r and z and time) interval pressure transient testing (IPTT) are described for the estimation of horizontal and vertical permeabilities and delineation of fracture and fault conductivities using the packer module and observation probe tool combination of the multiprobe wireline formation tester. Mathematical models for the pressure behavior of IPTT tests for using the packer module and the observation probes in multilayer (stratified) formations are presented. The maximum likelihood (ML) method is presented for nonlinear parameter estimation to handle uncertainty in error variances (weights) in observed data. The main advantage of the ML method over the traditional weighted least squares (WLS) is that it eliminates the trial-and-error procedure required to determine appropriate weights to be used in the WLS estimation. As shown by the examples presented in the paper, the ML method provides significant improvement in parameter estimation when working with pressure data sets of disparate orders of magnitude and noise, e.g., pressure measurements for the packer–probe and multiprobe interval tests.A field example where eight IPTT tests were conducted in a major carbonate formation is presented for characterization of vertical and horizontal layer permeabilities and vertical communication through the main producing reservoir section. These IPTT tests were conducted with a Formation Tester Dual Straddle Packer and two Probe Modules in a newly drilled well. An IPTT test at each location was interpreted using an appropriate geological model with the packer and probe pressure and flow rate measurements. The interpretation procedure consisted of identification of the different flow regimes followed by history (type curve) matching for the estimation of vertical and horizontal permeabilities for each layer. A detailed interpretation of two of the interval pressure transient tests is presented.
Systematic studies involving stochastic reconstruction, geometric and topological characterization, and network modeling of chalk, aiming at computation of petrophysical properties, are reported. The numerical chalk models are constructed exclusively from limited morphological information obtained from 2D backscatter scanning electron microscope images of the microstructure. Two different stochastic reconstruction methods are considered: conditioning and truncation of Gaussian random fields (GRF), and simulated annealing (SA). The potential of initializing the simulated annealing reconstruction with input generated using the Gaussian random fields method is evaluated and found to accelerate significantly the rate of convergence of simulated annealing reconstruction. This finding is important because the main advantage of simulated annealing method, namely its ability to impose a variety of reconstruction constraints, is usually compromised by its very slow rate of convergence.
Three-dimensional (3D) seismic data are commonly used to identify the size and shape of putative flow barriers in hydrocarbon reservoirs. It is less clear to what extent determining the spatial distribution of engineering properties (e.g., porosity, permeability, pressures, and fluid saturations) can improve predictions (i.e., improve accuracy and reduce uncertainty) of hydrocarbon recovery, given the multiple non-linear and often noisy transformations required to make a prediction. Determining the worth of seismic data in predicting dynamic fluid production is one of the goals of this paper.
The concept of multiscale percolation system (MPS) is proposed as a tool for the reconstitution of a 3D idealized pore space. The statistical properties of the MPS are generated on the basis of the size distributions of pores and solid particles of the porous medium under investigation that were obtained by microphotograph processing. The generation process is based on upscaling by means of renormalization. Renormalization is also used for computing MPS intrinsic permeability. The method is applied to a series of 23 reservoir sandstones which experimental permeability vary in a range 1:400. Permeability values computed according to the MPS model appear to be well correlated with experimental values.
Automatic history matching of both production data and time-lapse seismic data to achieve reservoir characterization with reduced uncertainty has been extensively studied in recent years. Feasible applications, however, require either the adjoint method or the gradient simulator method to compute the gradient/Hessian matrix of the objective function for the minimization algorithm. Both methods are computationally expensive when either the number of model parameters or the number of observed data is large.In this paper, the ensemble Kalman filter (EnKF) is used to history match both production data and time-lapse seismic impedance data. EnKF uses a set of reservoir models as input; continuously updates the models by assimilating observation data whenever they are available; and outputs a number of “history-matched” models that are suitable for uncertainty analysis. Since EnKF does not require the adjoint code, it is independent of reservoir simulators. A small synthetic case study was conducted, which shows the possibility of integrating both time-lapse seismic data and production data using the EnKF for reservoir characterization. The observed data are matched very well, and the true model features are recovered. The estimated porosity field is better than the estimated permeability field because seismic data are directly sensitive to porosity but only indirectly sensitive to permeability. The improved initial member sampling algorithm helps to keep large variance space within ensemble members, ensuring stable filter behavior.
A set of more than 5000 data points is proposed here as a reference database for the evaluation of thermodynamic packages dedicated to the prediction of phase behavior and volumetric properties of oils. A set of 13 reservoir crude oils coming from different countries in the world was selected from PVT reports of the French petroleum company TOTALFINAELF. Measurements at reservoir conditions and at standard conditions were addressed. Constant mass expansion, differential vaporization, swelling test, slim tube test, multi-contact test and stock tank oil density measurement were the experiments considered as reference laboratory data source. In each case, the reservoir fluid was obtained from recombination of produced separator gases and stabilized oil. The stock tank oil was produced in the laboratory by using a multi-stage separation procedure.
The present paper highlights the importance of abnormal formation pressure environments in oilfield operations.The detection and quantitative evaluation of overpressured formations is critical to exploration, drilling, and production operations involving hydrocarbon resources. As a result, an interdisciplinary technical team approach is required to optimize the safety, engineering, and financial aspects of operating in such hostile subsurface environments.Pulsed neutron capture (PNC) logging devices can be used for detection and quantitative evaluation of overpressure environments through the drillpipe and to monitor pressure depletion behind casing.Field observations clearly indicate that the Σ-values in shale formations decrease in a regular fashion with depth in normally compacted clastic sequences. Abnormal formation pressures are, however, flagged by divergence from this normal Σ-trend.Several field examples are presented to illustrate applications of PNC logging devices.
The writers proposed a method for estimating (1) the sonic velocity υa in abnormally-pressured shales using resistivity logs and, thus, (2) shale bulk density. Analysis of the well-log data for productive strata in Azerbaijan showed that there is a poor correlation between the sonic velocities and other well-log data, such as resistivity, SP, neutron and gamma-ray. Introducing normal trend of sonic velocity υn and resistivity ϱn allowed us to express sonic velocity (and, therefore, the bulk density of the shale) as a nonlinear function of resistivity with good correlation between the normalized velocity and normalized resistivity. The best-fit regression equation is of the following form: (where ϱa and ϱn are the resisitvities of abnormally-pressured and normally-compacted shales, respectively).The coefficient of correlation between parameters ] and ] is 0.87 and the mean-squared error for υa is 190 m/s. The average relative error of velocity estimation is 6% — ranging from zero to a maximum of 14%. Thus, υa can be estimated from the ratio and the υn obtained from the normal compaction trend in the area studied.
The aim of this paper is to provide new data on the properties of molecular aggregation in toluene solutions of crude oils and of solid asphaltenes. The shape of the optical absorption spectrum was found to be sensitive to the details of asphaltene aggregation processes. In dilute solutions, these processes are apparently determined by the net concentrations of asphaltenes; other oil constituents play a secondary role. Our experimental data indicate that molecular solutions of asphaltenes are possible only for concentrations below 1 mg/l. With increasing asphaltene content, more and more complex molecular aggregates are formed. In particular, asphaltene dimers evidently are the predominant species in the range of 5–15 mg/l, while stable “nanocrystallites” (dimer pairs) are predominant at concentrations ≈90 mg/l. Aggregates at higher concentrations may be viewed as assemblies of such “crystallites”. The observed gradual aggregation process is distinct from conventional micellisation phenomena with step-like changes at critical micelle concentrations (CMCs).
The properties of molecular aggregation in toluene solutions of a crude oil and solid asphaltenes are determined almost solely by the concentration of asphaltenes, as shown by absorptivity measurements at 315–750 nm. From non-monotonic concentration dependencies of absorptivities, it is concluded that asphaltene monomers are abundant in solutions with asphaltene concentrations below 1–5 mg/l, while molecular aggregates are effectively formed above 20–25 mg/l. The most stable oligomers are a dimer and a dimer pair (Yen's “nanocrystallite” [NC]). Nanocrystallites act as building blocks for more complex aggregates at asphaltene concentrations exceeding 90–100 mg/l. These optical absorption results are supported by studies of Rayleigh scattering in asphaltene solutions.
The purpose of this paper is the valuation of an option to defer an oilfield development. A methodology is implemented to determine the suitable continuous-time stochastic processes for these risk factors: the crude oil price, the convenience yield and the risk-free interest rate. The analysis reveals that the convenience yield follows a mean-reverting process, that the oil price is better fitted by the Geometric Brownian Motion with jumps and that the risk-free interest rate can be considered constant. The valuation of the option to defer is based on the Monte-Carlo simulation adapting the Least-Square simulation method for valuing American type options. Results indicate that using multi-factor pricing models leads to rejecting the project contrary to the one-factor pricing model which leads to postponing investment for option maturity.
A model that combines chemical effects with mechanical effects and provides a quantitative tool for evaluating wellbore stability is presented. In the past, wellbore stability models have introduced chemical effects by adding an osmotic potential modified by a membrane efficiency to the pressure acting at the wellbore wall [Fonseca, C.F., 2000. Chemical–mechanical modeling of wellbore instability in shales. Proceeding of ETCE 2000 and OMAE 2000 Joint Conference: Energy for the New Millenium, Feb. 14–17, 2000, New Orleans, LA.]. In this paper, an entirely different approach is adopted. The fluxes of water and ions into and out of the shale are accounted for. The pressure profiles obtained using our model differ significantly from the error function decline in pressure that is predicted by earlier models. As a consequence of this near wellbore pore pressure profile, wellbore failure can now occur inside the shale not just at the wellbore wall (as predicted by earlier models). The onset of instability now depends not only on the activity of the water but also on the properties of the solutes.
Thick salt beds in the Lower Tertiary were developed in the Kuqa foreland fold belt of the northern Tarim Basin. The salt beds controlled the structural deformation and hydrocarbon accumulation of the belts. Because of the salt beds, the Meso-Cenozoic structures of the Kuqa foreland fold belts can be divided into three major tectono-sequences: suprasalt structures, salt bed structures and subsalt structures. Suprasalt structures include thrusts and fault-related folds. Salt bed structures are dominated by salt pillows, allochthonous salt sheets, salt welds and fish-tail structures. Subsalt structures mainly include imbricated thrust belts, duplex structures, fault-related folds and pop-up structures. Formation of the salt structures in the Kuqa foreland fold belts is controlled by compression, gravitational gliding and gravitational spreading. The basin-mountain coupling and compression resulted in intense shortening of the fold belt. The rising of the South Tianshan Mountains caused the gravity gliding and gravity spreading. Plastic flow deformation of the salt beds resulted in salt thickening from the mountain front to the south of the fold belt. The thick salt bed accumulated in the Klasu and Qiulitag structural belts, and controlled the distribution of the salt-related structural traps and oil–gas pools. The structural traps have a bearing upon salt beds in the Kuqa foreland fold belts. The source rocks are mainly located below the salt beds, which can act as excellent cap rocks and seal the gas pools. The subsalt beds are the favorable places for hydrocarbons to accumulate.
Oil and gas fields of the Paleozoic cratonic basin in Tarim are mainly distributed in the Tabei and the Tazhong Uplifts. In the Tazhong Uplift, there are three sets of oil and gas stratum systems, of which the Ordovician traps are the largest in size and close to oil source beds with the most favorable conditions to form large-scale oil and gas fields. The Ordovician sediments in the Tazhong Uplift have experienced a stable platform and tableland margin development period. The Ordovician is divided into mudstone interval, interbedded mudstone and limestone interval, limestone interval, limestone and dolomite transitional interval and dolomite interval. Of these intervals, both interbedded mudstone and limestone interval and limestone interval contain source rocks, while limestone interval and dolomite interval are reservoir beds. Fault activities and denudation have an obvious impact on carbonate rock reservoirs. The major Ordovician trap types of the Tazhong Uplift include compressional fault block, fault anticline and buried hill, and regionally. The Tazhong Uplift can be generally divided into central fault horst trap belt, northern slope trap belt and southern slope trap belt. In view of the in-situ oil source in the Tazhong, oil and gas migration in the Tazhong Uplift is characterized by a short distance migration through sand bodies and unconformity surfaces laterally and along faults vertically. Based on this study, it is concluded that the favorable oil and gas accumulation zone should be the northern slope and the northwestern pitchout end of the uplift because these areas are located in the hydrocarbon migration pathway with weak tectonic activities and favorable preservation conditions.
Combined thin layer chromatography (TLC) and flame ionization detection (FID) of the Iatroscan TLC-FID instrument were used for geochemical screening of 600 core samples from the Elf-operated Frøy Field and Rind Discovery on the Norwegian Continental Shelf. The results allowed a pseudo 3-D characterization of the bitumen distribution in the reservoirs. Calibration of the data to well log-defined oil saturations allowed much more detailed recognition of variation in residual oil saturations (ROS) and helped in determining present and palaeo-oil–water contacts (OWCs). The quantification of bitumen amount and composition between different reservoir units was used to define OWCs. Palaeo-oil zones within present condensate and water zones were identified using an empirical approach to measure bitumen content and composition from live oil zones, condensate zones and dry gas zones, respectively. In this way, the Iatroscan TLC-FID data can be used to reconstruct elements of the filling history of the reservoirs. The application of this technique for identifying compartments, barriers for fluid flow and tar mats is also demonstrated.
Xanthan gum is used extensively for enhanced oil recovery as a mobility control agent, in drilling operations to increase the suspension capacity of the drilling mud, and in gels to improve the volumetric sweep efficiency. Flow properties, injectivity, and adsorption characteristics depend on acetate and pyruvate content of xanthan. This review discusses various methods and techniques available for measuring the concentration of xanthan and its pyruvate and acetate content in laboratory and field samples. It includes a description of the principles of each method, advantages, limitations, interferences, and other information necessary to understand the strengths and weaknesses of each.
Several techniques have been used to minimize the problems caused by the wax deposition, and the continuous addition of polymeric inhibitors is considered an attractive technological alternative. The addition of copolymers like polyacrylates, polymethacrylates or poly(ethylene-co-vinyl acetate) (EVA) permit to inhibit the deposition phenomenon; nonetheless, this effect is specific, i.e. similar copolymers present different performance depending on their physical–chemical properties in solution. In this work, the influence of the EVA vinyl acetate content on the viscosity and the pour point of a Brazilian crude oil were evaluated. A correlation between both results was also obtained. The phase behavior and the solubility parameter of EVA copolymers, with different vinyl acetate contents, were investigated in various solvents together with an evaluation of the efficiency of these copolymers as pour point depressants for two different samples of crude oil. EVA copolymers containing 20, 30, 40 and 80 wt.% of vinyl acetate were used and tests with the crude oil were carried out using 50, 500, 1000 and 5000 ppm of EVA as additive. The results obtained from viscosity measurements showed that only below the temperature at which wax crystals start forming did the copolymer exhibit a strong influence in the reduction of oil viscosity, at an optimum concentration. The pour point results revealed EVA 30 to be the most efficient. The results obtained from both experiments showed that the viscosity and the pour point behaviors do not show good correlation. Not only the solubility parameter and the vinyl acetate content, but also the molecular weight and polydispersity have an important influence on both phase behavior and pour point depression. Furthermore, it was confirmed that the additive must present a reduced solubility at a temperature close to the crude oil cloud point. This, however, is not the only factor that determines the efficiency of the additive as paraffin/wax deposition inhibitor.
In order to treat produced water from polymer flooding (PWPF), a new treatment method of combining hydrolysis acidification-dynamic membrane bioreactor (DMBR)–coagulation process was developed. The experimental results demonstrated that the highest acidification efficiency in hydrolysis acidification reactor (HAR) was 10.98% under hydraulic retention time (HRT) of 12 h. During the stable stage of dynamic membrane, the average concentration of ammonia nitrogen (NH3–N) and chemical oxygen demand (COD) in effluent from DMBR was 1.50 and 476.63 mg/L, respectively, while the concentration of oil was too low to be detected. In coagulation process, when the effluent from DMBR at pH 9.0 was treated directly, the COD removal efficiency could reach 89.41% with Aluminum sulfate (Al2(SO4)3) under the dosage of 140 mg/L. However, the dosage of Al2(SO4)3 would decrease to 80 mg/L with the same COD removal efficiency (88.37%) under the optimal pH 5.0. The combined process operated continuously for 30 days and the final effluent could meet the class I National Wastewater Discharge Standard of China. (GB 8978-1996).
Both small- (micron) to large- (centimeter) scale heterogeneities in carbonates cause the injected acids to propagate very differently than that predicted by a homogeneous model. Very few studies, either theoretical or experimental, address the effect of large scale heterogeneities (vugs) on matrix acidizing.This study explores the effects of heterogeneity on vuggy carbonate acidizing with high resolution computerized tomography imaging, image processing, geostatistical characterization, acid core-flood experiments (with 4-inch by 20-inch vuggy cores), and numerical simulations. We observed that acid propagates wormholes through vuggy carbonates much more rapidly than those in homogeneous rocks. In fact, an order of magnitude early acid breakthrough observed in the experiments highlighted the necessity of understanding the flow and transport in vuggy carbonates. The fact that acid channeled through the vugular cores and following the path of the vug system, is underlined with computerized tomography scans of the cores before- and after acid injection and with the connected component labeling (CCL) algorithm. This observation suggests that the local pressure drops created by vugs are more dominant in establishing the wormhole flow path than the chemical reactions occurring at the pore level. Following this idea, we present a modeling study to understand the flow in porous media in the presence of vugs. Use of coupled Darcy and Stokes flow principles, known as Darcy–Brinkman formulation (DBF), underpin the proposed approach.The results demonstrate that the total injection volume to breakthrough is affected by spatial distribution, and the amount and connectivity of vuggy pore space. Much deeper penetration of wormholes is predicted for the vugular rocks with low pore volumes to breakthrough or PVbt ranging from 0.04 to 0.15, compared to the homogeneous cases with PVbt close to one.
A new two-dimensional geochemical simulator, CIRF.A, and its application to matrix acidizing analysis and design are presented. The simulator is based on the solution of the equations of fully coupled fluid flow, species transport and rock/fluid reactions and includes the effects of grain growth/dissolution and the alteration of porosity and permeability due to mineral reactions. Our program has a large built-in thermodynamic and kinetic database.The simulator is tested by laboratory core acidizing results. It is demonstrated that simulation results are in good agreement with experimental observations. Both laboratory and simulation results indicate that an acidizing treatment may induce formation damage due to the precipitation of byproducts from the reactions of acids with rock minerals. A series of simulation runs have been carried out under different conditions to determine the strategy for minimizing the acid induced formation damage. High injection velocity and higher acid concentration are shown to reduce mineral precipitation and formation damage.The simulator is also used to predict permeability and productivity improvements for typical acid treatments of undamaged and damaged wells in sandstone formations. Our simulator is shown to be capable of simulating all the sandstone acidizing procedures that include pre-flush, mud acid treatment, after-flush and back production.In carbonate formations, matrix acidizing may lead to the development of dissolution fingers and the creation of wormholes. It is demonstrated that the simulator can also capture the fingering and wormholing phenomena. We believe this new geochemical simulator is an invaluable tool for matrix acidizing analysis and design.
Fatty acids in presence of water film alter calcite surface to oil-wet. The wettability alteration is dependent on the structure of the fatty acids, water composition and pH. Long chain fatty acid (stearic acid), strongly adsorbs onto the calcite surface from “oil phase” (n-C10) in oil/water/calcite system as indicated by contact angle measurements. On the other hand, short chain fatty acid (heptanoic acid) adsorbs on the calcite surface to a lesser extent, which agrees with “Traube's rule”.Adsorption of carboxylate anion is influenced by the ionic composition of the water, ionic strength and pH. The presence of Mg2+ and SO42− ions is shown to increase the water-wetness of the calcite. The degree of wetting is dependent on the pH. At pH < 7 in stearic acid/n-decane/water/calcite system, both ions reduce the contact angle. Higher reduction is obtained in presence of SO42− compared to Mg2+. The measured advancing contact angles are 95°, 108° at pH 5 and 88°, 82° at pH 7 in presence of SO42− and Mg2+, respectively. Further increase of the pH in the presence of Mg2+ causes more reduction of contact angle (68° at pH 10); while in the presence of SO42− ions an inflection point occurred where the advancing contact angle increased to 100°. In other words, the calcite surface became slightly more oil-wet.
To improve our understanding of the interaction of methane gas hydrate with host sediment, we studied: (1) the effects of gas hydrate and ice on acoustic velocity in different sediment types, (2) effect of different hydrate formation mechanisms on measured acoustic properties (3) dependence of shear strength on pore space contents, and (4) pore pressure effects during undrained shear.A wide range in acoustic p-wave velocities (Vp) were measured in coarse-grained sediment for different pore space occupants. Vp ranged from less than 1 km/s for gas-charged sediment to 1.77–1.94 km/s for water-saturated sediment, 2.91–4.00 km/s for sediment with varying degrees of hydrate saturation, and 3.88–4.33 km/s for frozen sediment. Vp measured in fine-grained sediment containing gas hydrate was substantially lower (1.97 km/s). Acoustic models based on measured Vp indicate that hydrate which formed in high gas flux environments can cement coarse-grained sediment, whereas hydrate formed from methane dissolved in the pore fluid may not.The presence of gas hydrate and other solid pore-filling material, such as ice, increased the sediment shear strength. The magnitude of that increase is related to the amount of hydrate in the pore space and cementation characteristics between the hydrate and sediment grains. We have found, that for consolidation stresses associated with the upper several hundred meters of sub-bottom depth, pore pressures decreased during shear in coarse-grained sediment containing gas hydrate, whereas pore pressure in fine-grained sediment typically increased during shear. The presence of free gas in pore spaces damped pore pressure response during shear and reduced the strengthening effect of gas hydrate in sands.
Characterization of natural gas hydrate bearing formations is important in the exploration and development of gas hydrate resources in subsea sediments. Solid hydrates can fill the voids of the matrix formed by sand grains and change their cementation condition, which may have a great impact on the electrical resistance and sound velocity of the sand matrix. In this study, experiments have been conducted to measure the ultrasonic velocity and electrical resistance in a large sandpack simulating the conditions of hydrate formation in subsea sediments. The effects of hydrate on the resistivity and ultrasonic velocity of hydrate bearing sand matrix have been revealed and modeled. The data can be used in well logging to determine hydrate saturation and other properties of hydrate bearing formations.
An ultrasonic apparatus for measurements of the speed of sound in liquids and compressed gases has been constructed. The instrument has been tested in measurements on both water and a bottom-hole live reservoir crude oil sample. The speed of sound in the oil sample was measured at three temperatures between 335 and 402 K at pressures up to 70 MPa. Measurements made along an isotherm, starting in the single-phase region and proceeding with decreasing pressure, were shown to lead to a precise determination of the bubble point of the fluid. The prospects for obtaining the fluid density from sound speed measurements are discussed. We also describe the possibility of determining the oil viscosity from measurements of the sound absorption made with the same ultrasonic cell.
An equation was developed for estimating approximate and theoretical values of seismic impedance Z from acoustic logs, specifically in the absence of density data. This formula, which explicitly uses the effects of shale, matrix and fluid properties, describes pore-fluid effects in hydrocarbon-bearing reservoirs with an acceptable degree of accuracy. In the limit, when the pores are filled with low-density gas, this equation predicts unrealistically slow velocities (long transit times). Accordingly, better equations are routinely recommended for modeling fluid effects.Based on the equation, a suggested system for evaluating the fundamental elastic parameters, including Young's modulus (E), shear modulus (μ) and bulk modulus (K) of any rock material, is also introduced.The main advantages of the proposed approach are: (1) it is applicable for many shaly formations independently of the distribution of shales; (2) it allows the determination of seismic impedance and elastic parameters with a high degree of accuracy particularly in the absence of density information; and (3) it gives a quick-look interpretation of old wells, that suffer from an insufficiency of borehole data. Application of the equation is illustrated with field data in a shaly-sand formation of a Gulf of Suez example.
Oil-producing companies have shown increased interest in instrumenting their hydrocarbon fields with in situ pressure sensors. As opposed to standard bottom-hole permanent pressure gauges, in situ pressure sensors are deployed behind casing to remain in direct hydraulic communication with rock formations. Prototype deployments have been tested in field operations that included intelligent completions. In situ pressure sensors allow the possibility of monitoring real-time dynamic variations of reservoir conditions due to primary or enhanced recovery. In consequence, a feedback loop can be enforced to modify the production scheme in a way that optimizes the recovery of existing hydrocarbon assets. While a great deal of laboratory and field work has been undertaken to advance hardware prototypes, relatively little has been done to quantify the spatial resolution and reliability of in situ permanent pressure data to detecting hydrocarbon reservoir properties.
The paper presents a practical study of expertise in sedimentary petrography and its incorporation into a knowledge-based computing system, PetroGrapher. The study identifies features of expert geologists' essentially visual knowledge that limit the usefulness of traditional logic-oriented symbolic methods for developing relevant knowledge-based systems. In particular, the experts' expressions of knowledge differ significantly from what is taught through the literature about their subject. Also, the means (ontology) of describing the explicit objects of geological data are not well-suited to describe how experts combine such objects and make inferences about them. The paper indicates how to deal with those two different levels of ontology, proposes “knowledge graphs” as an effective medium for linking them and explains their place in a general descriptive model of how experts solve problems in interpretation based on visual evidence. The model is being validated through the use of PetroGrapher, for management of data and knowledge about reservoir rocks, in a petroleum company.
An analytical solution is presented for laminar flow across a gravel pack. THe solution was obtained by solving the three-dimensional (3-D) diffusivity equation. This solution describes the divergent flow in the gravel-packed annulus between screen and casing. The solution is in the form of an infinite Fourier-Bessel series.An electrical analog was constructed to verify the mathematical solution. The mathematical model compared very well with the experimental data. The analytical solution was then used to investigate the effects of several design parameters on the productivity of a gravel-packed well. The perforation size and shot density were identified as the most important parameters.
The main objective of this study was to determine the optimal conditions for application of acrylamide co- and terpolymers for water control in gas wells under various environmental conditions. Starting in February 1992, the limits of application of acrylamide co- and terpolymers were first defined in the laboratory through extensive tests. Based on the results of the comparative feasibility study, four field tests were performed in both gas reservoir and underground gas storage wells. This paper presents the latest results of field tests. Using a partially sulfonated acrylamide terpolymer, the first field test was performed in January 1993 on an abandoned gas-producing well with a BHT of about 130°C, an average matrix permeability of 0.01 μm2 and a produced brine salinity of more than 300 g/l TDS. The second test was performed in a well from a gas storage field with a temperature of about 87°C, an average permeability of 0.06 μm2 and a produced brine salinity of more than 270 g/l. Based on the information provided from the first field test and the feasibility study performed for this well, a lower molecular weight partially sulfonated acrylamide terpolymer was finally used for this test. Using a cationic acrylamide copolymer, the third field test was performed in a low-temperature, high-brine-salinity gas storage well with BHT of 30°C and brine salinity of 218 g/l. Based on the excellent results of the third field test, the same polymer was selected for the last water shut-off treatment in a low-temperature gas storage well with a matrix permeability ranging from 0.04 to 3.6 μm2. Since the treatment, the gas well and the gas storage wells have exhibited improved production performances.
Polyacrylamide are used extensively in enhanced oil recovery, drilling fluids, and in gels for profile control. This review enables drilling engineers or reservoir engineers to choose the most appropriate analytical method for measuring polyacrylamide concentration for their particular project. Seventeen groups of methods were reviewed for the determination of acrylamide copolymers, whereas eight groups of methods were reviewed for the measurement of degree of hydrolysis. In each case, a description of the method, advantages, limitations and interferences is provided.
Two primary methods are available for the measurement of polyacrylamide concentration in oilfield brines. One of these is a flow injection analysis (FIA) method based on the reaction of acrylamides with bromine (the starch–iodide method). The FIA method provides rapid sample throughput and high reproducibility, but may be sensitive to interferences or changes in the sample matrix. In this work, systematic optimization of the FIA method was conducted to improve analytical stability, reproducibility, and sensitivity. The effects of potential sources of interference from brines were examined in detail. These included Na+, Ca2+, Cr3+, Al3+, ZrIV, NH4+, Cl−, OH−, CO32− ions, sample coloration, and commonly used surfactants. Since the FIA method measures amide group concentration, the linearity of response for a series of partially hydrolysed polyacrylamides was measured. The range of the method is 2 to 1200 mg/l. Sample throughput is 30 samples/h with triplicate analysis. Relative standard deviations of 0.2% are readily obtained from standard solutions and 0.5% from complex samples (at 1000 mg/l).
Microbial enhanced oil recovery (MEOR) offers an economic alternative to enhanced oil recovery (EOR). In accordance to the source of the microorganisms used, microbial enhanced oil recovery can be categorized into two types: injected exogenous microorganisms or utilized indigenous microorganisms for enhanced oil recovery. Indigenous microorganisms for MEOR have greater advantages compared to injected microorganisms. For example, this technology does not need additional injection instruments for in situ inoculation and the indigenous microorganisms adapt, grow, and breed more easily in the oil reservoir.Laboratory studies show the existence of some species of indigenous microorganisms (mainly bacteria) in crude oil and formation water of S12 block in Shengli Oilfield, such as hydrocarbon degrading bacteria (HDB), denitrifying bacteria (DNB), methane producing bacteria (MPB), sulfate reducing bacteria (SRB), iron bacteria (IB), sulfur bacteria (SB), and total growth bacteria (TGB). These indigenous bacteria are the objective of investigations for the MEOR.The results of the chemical analyses, bacteriological analyses of the crude oil and water samples, and the growth and physical simulation experiments are presented. The results show that the indigenous bacteria beneficial to MEOR can be selectively stimulated by nutrient injection while the detrimental bacteria can be restricted to some extent, enabling oil recovery to be enhanced by 9.14% after the first waterflooding.
Three inorganic additives were tested for the restoration of damaged sandstone cores. Hydrochloric acid, aqueous sodium chloride, and aqueous calcium chloride were used on Saudi sandstone cors aswell as Berea Sandstone cores. Results showed that concentrated calcium chloride was the most successful of the three additives. Whereas hydrochloric acid was the least successful additive, sodium chloride showed moderate success. Injection with 15% aqueous CaCl2 solution was found to restore most of the damaged permeability characteristics and restored the recovery to its initial pre-damaged level.
The exploration and exploitation of hydrocarbon from the ocean dictate the use of environment friendly muds and mud additives to protect the existing wealths such as fishes, coastal areas and other habitats of the ocean. Hence, the preservation of the Australian as well as global ocean environments from the detrimental effects of muds and mud additives dictates the design of better environment friendly drilling mud systems using mud additives having no/negligible environmental impact. This paper describes the fluid loss characteristics of several starches and provides a comparative assessment with respect to a widely used modified starch.Experimental results indicate that some of the starches have static and dynamic fluid loss characteristics similar to or better than those of a widely used modified starch used by the mud industry. The static fluid loss properties measured after thermal treatment at different temperatures indicate that the newly developed starch products can be used as fluid loss additives for drilling boreholes having bottom hole temperature up to 150 °C.The products developed by gelatinization using a reactive extrusion technique have negligible impurities, need no solvent during gelatinization, produce no waste water as a by-product and thus are suitable for environment sensitive areas. The products have been developed from local resources and have lower manufacturing cost and thus expected to decrease the cost of drilling mud significantly.
Water production from oil and gas reservoirs is increasing worldwide, as more reservoirs are becoming mature. In order to control water production, polymers and gels are often injected into the formation to reduce the water permeability. These systems are known as relative permeability modifiers. Although these methods sometimes lead to significant cost savings, and many successful treatments have been reported, a wider application is hindered by the lack of understanding of the basic mechanisms of permeability modification by polymers.This paper presents some pore-level and basic studies on polymers, with the aim of providing a better understanding of these systems. Experiments have been performed in micro-scale glass flow models, and atomic force microscopy was used to validate the flow observations. The role of adsorption and flow of polyacrylamides in the formation of thick layers is described. The size of statically adsorbed polyacrylamide layers depends on the polymer characteristics (molecular weight, degree of hydrolysis, salinity, etc.), but is less than 250 nm for all the systems studied. On the other hand, dynamically formed polymer layers can reach several thousands of nanometres. The existence of these thick polymer layers is shown here, to our knowledge for the first time, through flow experiments and AFM measurements. While mechanical retention cannot occur under our experimental conditions, the mechanism of adsorption–entanglement gives a reasonable mechanistic description of the dynamic formation of thick layers. The implications of these mechanisms in the modelling of the flow and selection of polymer systems are discussed.
Chemical-flooding schemes for recovering residual oil have been in general less than satisfactory due to loss of chemicals by adsorption on reservoir rocks, precipitation, and resultant changes in rock wettability. Adsorption and wettability changes are determined mainly by the chemical structure and mix of the surfactants, surface properties of the rock, composition of the oil and reservoir fluids, nature of the polymers added and solution conditions such as salinity, pH and temperature. The mineralogical composition of reservoir rocks plays an important role in determining interactions between reservoir minerals and externally added reagents (surfactants/polymers) and their effects on solid–liquid interfacial properties such as surface charge and wettability. Some of the reservoir minerals can be sparingly soluble causing precipitation and changes in wettabilty as well as drastic depletion of surfactants/polymers.Most importantly, the effect of surfactants on wettability depends not only how much is adsorbed but also on how they adsorb. A water wetted rock surface that is beneficial for displacement of oil can be obtained by manipulating the orientation of the adsorbed layers. New surfactants capable of tolerating harsh conditions created by extremes of pH, temperature or inorganics and capable of interacting favorably with inorganics and polymers are promising for enhanced oil recovery. In this regard, such surfactants as sugar based ones and pyrrolidones are attracting attention, as they are also biodegradable. In many cases, mixed surfactants perform much better than single surfactants due to synergetic effects and ability to alleviate precipitation. Also, addition of inorganics such as silicates, phosphates and carbonates and polymers such as lignins can be used to control the adsorption and the wettability. In this paper, use of specialty surfactants and their mixtures is discussed along with the mechanisms involved.
Wettability control by methods that are of practical relevance to oil recovery is an ongoing problem in wettability research. The preparation of mixed-wettability cores by adsorption from an asphaltic crude oil at elevated temperature and pressure has been investigated. After aging, crude oil was displaced by flow of decalin, an intermediate solvent that was compatible with the crude oil with respect to asphaltene precipitation but not likely to cause undue desorption of polar components of crude oil from pore walls. The decalin was in turn removed by flow of refined oil.
The effects of asphaltenes on the particle size, and the surface charge of two montmorillonite clays having in water various particle sizes, flow behaviours, and cationic exchange capacities (CEC) are investigated. The aim of this work is to contribute to the comprehension of the mechanism by which the asphaltenes alter the mineral wettability in an oil reservoir. Thus, adsorption of asphaltenes onto clays was made from water-saturated toluene, and the resulting asphaltenes covered clays were dried to remove trace of solvent and then dispersed in water. Upon adsorption of asphaltenes onto various clays, the mineral surface charge is reduced and the aggregation of the clay particles is enhanced, as observed, respectively, by microelectrophoresis and scanning electronic microscopy (SEM). Further, the samples aqueous dispersion properties such as the natural pH and the electrical conductivity were found, in all instances, to be lower for the asphaltenes covered clays as compared to the bare minerals, indicating reduction by asphaltenes of the clay's CEC. It is shown that the asphaltenes adsorption from water-saturated toluene onto clay is higher for the solid mineral having in water and at natural pH, the lower surface charge, the highest particle size and presenting the highest yield point for flowing.
A matrix-fracture transfer function for multi-species gas flow with adsorption behavior is presented. This transfer function is developed from the extended Fick's law and therefore the coupling effect of mutual-diffusivity is included in the representation. The transfer function is formulated based on an exact formal solution of a set of linear partial differential equations for matrix blocks with regular geometry, and is expressed in the form of a series expansion with history-dependent integrals. This series, at first order, reduces to a simple algebraic expression that is of an equivalent computational efficiency in comparison with the extended Warren–Root model in which the mutual-diffusion effect is not present.The presented transfer function is compared with the Warren–Root relationship and it is shown that the Warren–Root model is a limiting case of the new model. It is also shown how the new model can be applied to reservoirs where gas is stored within the porosity rather than as an adsorbed phase.
The adsorption behaviour of a petroleum sulfonate (TRS10-410) on Saudi Arabian limestone has been studied as a function of salinity, surfactant concentration and pH. The adsorption data on limestone exhibit the significant effect of mineral solubility in controlling the surfactant depletion. Release of Ca2+ ions from the semi-soluble limestone matrix produces precipitation of the surfactant followed by its redissolution at concentrations exceeding the critical micelle concentration (CMC). This characteristic behaviour generates an apparent adsorption maximum which is of considerable interest in surfactant flooding. The precipitation tolerance of TRS10-410 has also been investigated in the presence of Na+ and Ca2+ ions to quantitatively describe the precipitation behaviour of this surfactant. The adsorption and precipitation data are analyzed to elucidate the mechanism of surfactant adsorption on limestone and that of surfactant precipitation by inorganic ions.
Static adsorption of mixed ethoxylated surfactants, alkylryl sulfonates, C9-Ph-(EO)xSO3Na, and the corresponding alcohols, C9-Ph-(EO)xOH, (X = 2, 4, 5.5, 6 and 9), onto kaolinite and quartz has been studied using a 3.5 wt% NaCl solution. The commercial products were purified and enriched in the sulfonate (70 to 96 mol% of total surfactant content) prior to the experiments. The isometric pure 4EO-sulfonate was used as a reference surfactant. The surfactant mixtures were strongly polydisperse in ethoxylation degree. The critical micelle concentration, CMC, in a 3.5 wt% NaCl solution decreases as the number of EO-groups increases. The plateau adsorption on kaolinite decreases also as the number of EO-groups increases.
The goal of this research was to study the effect of advancing velocity and liquid viscosity on the dynamic contact angle between a solid surface and various hydrocarbons. The Wilhelmy plate technique was used to measure the dynamic contact angle at advancing velocities between 20 and 264 μm/s. In addition to hydrocarbons, two silicon oils were also tested for comparison purposes. The results indicate that advancing velocity and oil viscosity have a significant effect on the dynamic contact angle for both hydrocarbon and silicon oils. For example, the advancing contact angle for viscous (1540 mPa s at 15 °C) oils was up to 2 times higher at 200 μm/s than at 20 μm/s. As a result, it is recommended that when values for dynamic contact angles are reported, the advancing velocity at which they were measured be indicated. This will ensure correct data interpretation, meaningful comparison between various studies, and better prediction of multiphase flow or adhesion processes that depend on the dynamic contact angle.
Mixed-wet crude oil/brine/mineral systems typically show a large contact angle hysteresis between the water-receding angle during primary drainage and the water-advancing angle during imbibition. Also, the water-advancing angle may have values that range from 50° to 180°. This investigation uses atomic force microscopy (AFM) to characterize mica surfaces that have first been equilibrated in 0.01 M NaCl, pH 6 brine and then aged in crude oil at elevated temperature. The wettability of the aged surfaces was measured with brine and crude oil. The mica surfaces that were to be examined by AFM were washed with cyclohexane to remove the bulk crude oil. The wettability of the surfaces washed with cyclohexane was measured with brine and decane. Two crude oils were used in this investigation. They were either used as the stock tank oil (STO) or diluted to 40% with n-heptane. This particular dilution was used because it is close to the asphaltene precipitation point of one of the crude oils. The AFM images show the mixed-wet surface to be patches of bare mica and patches of asphaltene with a characteristic areal dimension of about 200 nm. The elevations of the asphaltene patches are about 20 nm for the STOs but increase to above 200 nm when the crude oil is diluted to 40% with n-heptane. These mica surfaces equilibrated with crude oil diluted with heptane have larger advancing contact angles (e.g., 140°) compared to the surfaces equilibrated with STO (e.g., 75°). From this, we infer that the advancing contact angle becomes larger as the asphaltene solvency decreases because of increased coverage of the mica surface with larger asphaltene aggregates.
The crude oil properties governing the wettability of crude oil and brine on mica were investigated. Deposition of polar asphaltenes from oil causes mineral wetting to alter from strongly water-wet to less water-wet. The degree of alteration depends on the hydrophobicity of asphaltene and the amount of deposition, which depends on factors such as asphaltene content and solvency of the oil, acid and base content of the oil, brine pH and salinity, aging condition, and mineral type.Physico-chemical properties of the constituent phases that affect mineral wetting were examined. An adhesion test was applied to test water film stability governed by electrostatic interactions between oil/water and water/mineral interfaces. The effect of asphaltene solvency of oil on adhesion was also demonstrated.Statistical analysis was performed on the parameters affecting wettability. When the candidate parameter set was properly chosen, two dominant factors (asphaltene content and base number/acid number) that affect wetting emerge from the analysis. The correlation trend from statistical analysis is consistent with the knowledge and experience obtained from past and current wettability studies.
A large number of grid cells are needed to simulate very large field reservoirs such as those in the Middle East. Pseudo relative permeability curves are used to reduce the dimensionality of reservoir simulation models and also to account for intra-cell rock property variations. Identifying the parameters affecting pseudo relative permeability curves is very important so that the model cells can be grouped in different categories in which appropriate pseudo relative permeabilities are generated for each group. The objective of this study is to identify the factors affecting pseudo relative permeability curves. Different reservoir rock and fluid properties were studied for an homogeneous 2D reservoir model. Validation of some curves is also done. The most pronounced effect on pseudo relative permeability curves was found to be caused by the reservoir dip angle. Layer thickness and PVT properties have some effect. Production rate and vertical to horizontal permeability ratio have no significant effect within the parameter ranges studied. While absolute permeability on low dip angle cases has no effect, absolute permeability effects on high dip angle cases needs consideration.
Much attention has been devoted to the study of the improved oil recovery (IOR) method(s). However, it still remains a challenge to evaluate the reservoir wettability quantitatively using actual core samples. Contact angle is considered as one of the most common methods to measure the preferential affinity of reservoir rocks. The main objectives of this study are to investigate the influence of droplet volume, brine salinity, liquid saturated rocks, oil acid number, and temperature on rock wettability of carbonate reservoir rock using sessile droplet method. Sixteen runs were undertaken using oil droplet volumes of 10, 15, 20, and 25 ml with different brine salinities of zero, 50,000, 100,000, and 150,000 ppm of NaCl, respectively. This has been done to study the effect of droplet volume and salinity on contact angle. In three runs, different crude oils having acid numbers of 0.374, 0.561, and 0.986 mg KOH/g samples were performed to investigate the influence of acid number on the contact angle. Three runs were carried out using brine, crude oil, and polymer solutions to study the effect of liquid-type saturated rock on contact angle. Finally, two runs were used to study the effect of temperature on contact angle. In all experiments, actual rock and crude oil samples were used.
Analyzing data from well logs and seismic is often a complex and laborious process because a physical relationship cannot be established to show how the data are correlated. In this study, we will develop the next generation of “intelligent” software that will identify the nonlinear relationship and mapping between well logs/rock properties and seismic information and extract rock properties, relevant reservoir information and rules (knowledge) from these databases. The software will use fuzzy logic techniques because the data and our requirements are imperfect. In addition, it will use neural network techniques, since the functional structure of the data is unknown. In particular, the software will be used to group data into important data sets; extract and classify dominant and interesting patterns that exist between these data sets; discover secondary, tertiary and higher-order data patterns; and discover expected and unexpected structural relationships between data sets.