Project

Oil and Gas Migration

Goal: Geophysics and Geochemistry of Oil and Gas Migration and its TIMING.

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Project log

Roger N. Anderson
added 2 research items
Kuwaiti Oil Fields set afire by fleeing Iraqi army. Fires put out by likes of Boots and Coots and Red Adair.
Eugene Island 330 in offshore Gulf of Mexico is recharging via natural Hydrofracturing along a feeder Growth Fault.
Roger N. Anderson
added a research item
The production of oil and gas is not ordinarily thought of as a manufacturing process. However, in recent years technological advances have produced a wonderful explosion of improvements that make the oil and gas "factory" run more efficiently. Individual exploitation improvements such as 3D and 4D seismic, full tensor gradiometry, FPSO, and multilateral completions, to name a few, have driven the growth in production that accounted for impressive earnings growth improvements for the whole industry in the 1990's, independent of price swings.
Roger N. Anderson
added a research item
NRMI is a new and unique reservoir management company focused on improving production for the good of your business, not solely for technology sake. NRMI evaluates existing production performance from an above-ground, business perspective, then identifies, designs and executes those below-ground technological improvements that are appropriate for increasing production and better meeting business goals for select fields that can really make a difference to a business unit’s bottom line. NRMI is unique in the marketplace because of its Affiliation of the very best, highest quality, advanced technology companies in the production business.
Roger N. Anderson
added a research item
MY VITA as of June 1, 2020, with newest Patent Numbers issued for 5 new Continuation Patents.
Roger N. Anderson
added 3 research items
How much oil is under the Gulf of Mexico and how did it get there? Columbia University geophysicist Roger Anderson, an expert in deepwater exploration and drilling, explains how the oil formed millions of years ago, and how companies go about finding and extracting it.
Roger N. Anderson
added 3 research items
This technology is a method for better managing oil extraction through seismic analysis of the underlying oil before and during rig operation. Oil extraction induces underlying flow patterns that marginalize the efficiency of extraction at the site of the well and can force operations to move around and follow the most oil rich location. As a result, additional operating costs are incurred, extraction prolongs, and profitability is reduced. Spatiotemporal monitoring of oil flow patterns during extraction called 4D Monitoring technology enable intelligent management of oil fields by analyzing oil flow patterns via time lapsse seismic data and producing a time dependent model to predict future oil movement. This technology contains an algorithm for reservoir flow modeling that can rapidly interpret and analyze seismic data, yielding a dynamic feedback protocol that provides managers with the ability to precisely control resources and generate time-apse images depicting current and future flow of the oil and gas to the surface.
This paper on the search for hydrocarbons which has been one of the costliest enterprises of the 20th Century, yet there is still no sure-fire method for accurately predicting the specific location of oil and gas without drilling. This is because there remains a poor understanding of how, why, and where oil and gas migrate within a sedimentary basin. Addressing this issue, the Global Basins Research Network (GBRN) has constructed a data cube of the Pilo-Pleistocene U.S. Gulf Coast that contains internally consistent geophysical, geochemical, and geological data relevant to fluid flow within a 60 km {times} 40 km {times} 10 km volume of gulf Coast sediments. Using a parallel supercomputer, the network is constructing a three dimensional (3D) model of the fluid flow history within the data cube, which will lead to the reconstruction of the fluid flow history of the volume. New dynamic technologies resulting from this method will perhaps predict the locations of vast quantities of undiscovered oil and gas.
Roger N. Anderson
added 5 research items
We present a relatively simple technique to constrain in-situ stress and effective rock strength from observations of wellbore failure in inclined wells. Application of this technique in the Global Basins Research Network (GBRN)/DOE "Pathfinder" well demonstrated that (1) the azimuth of Shmin is N42 E, perpendicular to a major growth fault penetrated by the well; (2) the magnitude of SHmax is relatively close to the vertical stress; and (3) the effective in-situ compressive rock strength is 3,500 to 4,000 psi. We show that once we have estimated in-situ stress and rock strength, it is possible to compute the mud pressure required to inhibit failure for wells of any azimuth and inclination. Finally, we show how it is possible to estimate the magnitudes of both Shmin and SHmax in cases where independent knowledge of stress orientation is available (for example, from wellbore breakouts in nearby vertical boreholes). Introduction Improved knowledge of in-situ stress and effective rock strength in hydrocarbon reservoirs is important in a number of problems ranging from borehole stability and sand production to hydrocarbon migration and hydraulic fracturing. We have conducted a comprehensive series of calculations of the occurrence of compressive failures and drilling-induced, tensile wall failures in arbitrarily inclined boreholes1 and showed how such observations can be used to determine stress orientation and magnitude, effective rock strength and the optimal mud weight for borehole stability. In this paper, we present application of this theory to observations of compressive wellbore failures in the GBRN/DOE Pathfinder well, an inclined well drilled in conjunction with Pennzoil Co. in Block 330 of the South Eugene Island field of the Gulf of Mexico. Stress-induced compressive failures of wellbores are commonly known as stress-induced wellbore breakouts and can be observed with either four-arm, magnetically oriented calipers (such as with dipmeter logs) or borehole televiewers. Drilling-induced, tensile wall failures in inclined boreholes also can be used to constrain in-situ stress magnitudes. In contrast to drilling-induced hydraulic fractures that propagate away from the borehole and are associated with lost circulation, tensile wall failures occur only in the wellbore wall and are detected only through careful inspection of the borehole wall with Formation MicroScanner/MicroImager logs (FMS/FMI). In this study, we focus on stress-induced wellbore breakouts as they are commonly observed in oil and gas wells, and numerous studies have shown that breakouts in near-vertical wells accurately reflect in-situ stress orientations when care is taken to distinguish stress-induced wellbore breakouts from other processes that change the cross-sectional shape of a borehole.4 In this analysis, we use the following observations in inclined wellbores.The orientation at which breakouts occur around the wellbore.Leakoff data to constrain the magnitude of the least principal horizontal stress, Shmin, in the case study presented.Estimates of the vertical stress and pore pressure. These observations are used to constrain (a) the values of the unknown components of the in-situ stress tensor (in the case study presented, these are the orientation of the horizontal principal stresses and the magnitude of SHmax), (b) the maximum effective strength of the rock in situ, and (c) the mud weight necessary to inhibit failure. We illustrate this technique with some relatively simple diagrams that show how breakout orientations depend on the in-situ stress state and borehole orientation and how the tendency for failure further depends on rock strength, pore pressure, and mud weight. We also demonstrate that in cases where the orientation of the horizontal principal stress is already known (for example, from breakouts in vertical wells), the magnitudes of both Shmin and SHmax can be estimated. Mastin demonstrated that breakouts in inclined holes drilled at different azimuths are expected to form at various angles around a wellbore depending on both the stress state and exact hole orientation. In fact, for this very reason, observations of breakouts in inclined holes are not normally used to determine in-situ stress orientation. Qian and Pedersen and Aadnoy proposed complex nonlinear inversions of failures in multiple inclined boreholes to constrain the in-situ stress tensor. As illustrated later, the technique we propose can yield useful constraints on the stress field from observations in a single borehole. In addition, it does not depend on detailed knowledge of formation properties and basically assumes only that the formation behaves elastically up to the point of failure. Peska and Zoback described the mathematical basis for the technique in detail. In summary, to compute the likelihood of compressive failure around the wellbore, we need to estimate the maximum effective stress in the plane tangential to the borehole, stmax, (1) and the normal stress on the borehole, (2) In Eqs. 1 and 2, the stress state in a borehole coordinate system is given by (3a) (3b) (3c) where z is parallel to the borehole axis; r is radial distance; is the angle around the borehole wall measured from the bottom of the hole; is Poisson's ratio; and p is the difference between the borehole fluid pressure and the pore pressure in the rock, pp.15 In Eqs. 1 through 3, the effective stresses, ij, are given by (4) where Sij is a component of the "total" stress tensor defined in a local borehole coordinate system derived from the far-field stress state through a series of coordinate transformations and ij is the Kronecker delta. Eugene Island 330 Field and the Pathfinder Well The Pathfinder well is an extension (from 7,300 to 8,075 ft) of Production Well A-20ST in Eugene Island Block 330, offshore Louisiana. It was drilled in 1993 as part of a joint project between GBRN, the DOE, and private oil industry with the one objective of testing the hypothesis that an active growth fault can be conduit for oil and gas migrating to the reservoir.
The Pathfinder core, collected in the South Eugene Island Block 330 field, offshore Louisiana, provides an outstanding sample of structures asso- ciated with a major growth fault that abuts a giant oil field and that is thought to have acted as a con- duit for hydrocarbon migration into the producing reservoirs. Where cored, the growth-fault zone cuts semi-consolidated Pliocene–Pleistocene mudstone and is over 100 m wide. The fault zone in the core consists of three structural domains, each characterized by a distinct rock type, distribution of fault dips and dip azimuths, and distribution of spacing between adjacent faults and fractures. Although all of the domains contain oil-bearing sands, only faults and fractures in the deepest domain contain oil, even though the oil-barren fault domains contain numerous faults and fractures that are parallel to those containing oil in the deepest domain. The deepest domain is also distinguished from the other two domains by a greater degree of structural complexity and by a well-defined power-law distribution of fault and fracture spacing. Sediments in this domain behaved as competent rock with respect to fault and fracture spacing, whereas the departure from power-law distribution of fault and fracture spacing in the other two domains may reflect deformation of unconsolidated sediment. This departure from a power-law spacing distribution in the upper two domains, combined with stable isotope data that indicate low-temperature water-rock interaction within a gouge zone that separates these two fault domains, indicates that the faults in those domains may have been active only early in the history of the growth fault zone, when the sampled sediments were at shallow burial depths. Thus, these faults may predate oil migration. In contrast, the faults in the oil-bearing domain appear to have been active later in the fault zone’s history, when the sediments faulted as competent rock and when geologic and organic geochemical investigations indicate oil migrated into the Block 330 reservoirs. Even though oil is present in sands throughout the core, its restriction to faults and fractures in the youngest sampled portion of the fault zone implies that oil migrated only through that part of the fault that was active during the time when oil had access to it. The absence of oil in fractures or faults in the other, probably older, fault domains indicates that the oil was never sufficiently pressured to flow up the fault zone on its own, either by hydraulic fracture or by increased permeability as a result of decreased effective stress. Instead, fluid migration along faults and fra tures in the Pathfinder core was enhanced by permeability created in response to relatively far-field stresses related to mini-basin subsidence.
Roger N. Anderson
added a research item
We report the first direct observation of a migrating fluid pulse inside a fault zone that, based on previous evidence, is suspected to be a conduit for fluids ascending from depth. We find that areas of high fault-plane reflectivity from a fault at the South Eugene Island Block 330 field, offshore Louisiana, systematically moved up the fault 1 km between 1985 and 1992. The updip movement can be explained by the presence of a high pressure fluid pulse ascending a vertically permeable fault zone. These fault burps play a central role in hydrocarbon migration. Faults have long stumped geoscientists by virtue of their split-personality as both impediments to fluid flow and, at times, preferential pathways for flow. Both behaviours are invoked in the petroleum industry to explain how hydrocarbons move from the location at which they are generated (e.g., by flowing along faults 1) into fault-bounded reservoirs where they are trapped (e.g., by a lack of flow across faults 2). Several lines of evidence from the South Eugene Island Block 330 field, offshore Louisiana, indicate that faults there have hosted significant vertical fluid flow over the last 250,000 years, continuing to the present day 3,4,5. We present an additional set of
Roger N. Anderson
added 4 research items
The gas industry and federal government face tremendous challenges to deliver the supply required by the increasingly gas-dependent electricity demand in the United States of the 21 st century. The U.S. will be hard pressed to build the large number of Liquid Natural Gas terminals that provide the only significant alternative to North American supply increases. Huge new reserves of gas must be brought to market to offset the natural exponential decline in known gas production from within the borders of the United States that coincides with this demand increase. We must explore, discover, appraise, develop, and exploit the vast new gas reserves discovered in waters deeper than 1500 meters in the ultra-deepwater Gulf of Mexico if we are to have any hope of meeting this demand increase. If we fail, gas will have to be rationed between heating and power, particularly in the Northeast, a choice for which no one will want to be responsible. Figure 1. Filling the ever increasing gap between U.S. supply and demand (Source EAI/DOE) will require voluminous production of hydrocarbons from the ultra-deepwater Gulf of Mexico, as well as from deep continental supplies, coal bed methane, and new Alaskan, Canadian, and Mexican pipelines. Each year's discoveries are tracked to show their depletion over time in the inlay above (each color is the decline in production from wells drilled that year and tracked for the rest of their productive life).
Roger N. Anderson
added a project goal
Geophysics and Geochemistry of Oil and Gas Migration and its TIMING.