Showing papers on "Petroleum reservoir published in 2005"

Characterisation of Gas Transport Properties of the Opalinus Clay, a Potential Host Rock Formation for Radioactive Waste Disposal

Abstract: The Opalinus Clay in Northern Switzerland has been identified as a potential host rock formation for the disposal of radioactive waste. Comprehensive understanding of gas transport processes through this low-permeability formation forms a key issue in the assessment of repository performance. Field investigations and laboratory experiments suggest an intrinsic permeability of the Opalinus Clay in the order of 10-20 to 10-21 m2 and a moderate anisotropy ratio 25 nm. The determined entry pressures are in the range of 0.4-10 MPa and exhibit a marked dependence on intrinsic permeability. Both in situ gas tests and gas permeameter tests on drillcores demonstrate that gas transport through the rock is accompanied by porewater displacement, suggesting that classical flow concepts of immiscible displacement in porous media can be applied when the gas entry pressure (i.e. capillary threshold pressure) is less than the minimum principal stress acting within the rock. Essentially, the pore space accessible to gas flow is restricted to the network of connected macropores, which implies a very low degree of desaturation of the rock during the gas imbibition process. At elevated gas pressures (i.e. when gas pressure approaches the level of total stress that acts on the rock body), evidence was seen for dilatancy controlled gas transport mechanisms. Further field experiments were aimed at creating extended tensile fractures with high fracture transmissivity (hydro- or gasfracs). The test results lead to the conclusion that gas fracturing can be largely ruled out as a risk for post-closure repository performance.

Transient fan architecture and depositional controls from near-surface 3-D seismic data, Niger Delta continental slope

Abstract: A near-surface, three-dimensional seismic data set from the Niger Delta continental slope, offshore Nigeria, reveals important stratigraphic and architectural features of channel and fan systems in intraslope basins and permits the development of predictive models for application to deeper reservoir systems. Synsedimentary extensional faulting and mud diapirism control slope gradient, but erosion and deposition from sediment gravity flows tend to smooth the depositional profile and establish an equilibrium profile that adjusts to the changing slope gradient. Architectural features and sediment deposits interpreted from seismic character and seismic stratigraphy, in the absence of borehole data, include mass-transport complexes, distributary channels, submarine fans, and hemipelagic drape complexes. Leveed channel complexes are absent in this study area. These architectural features reflect a combination of active (sediment input from channel systems) and relatively passive (slope failures and slumps) sediment supply systems. Deposition of sandy fans is caused by a hydraulic jump at an abrupt reduction of slope gradient. Channel incision results from knickpoint migration headward from an abrupt increase of slope gradient. Submarine fans that show evidence of channel incision and bypass are termed “transient,” whereas fans without channel incision and bypass are termed “terminal.” This distinction has implications for both exploration and reservoir management. The presence of incised channels in transient fans indicates bypass of significant sand volume to a basinward location. If the transient fan is a hydrocarbon reservoir, the incised channel, which commonly is shale filled, may compartmentalize the reservoir. Dayo Adeogba has had 11 years of experience as a petroleum geologist with ChevronTexaco, mostly in development geology and reservoir management. He earned a B.Sc. degree from the Obafemi Awolowo University (Nigeria) and an M.S. degree from Stanford University. He currently focuses on deepwater depositional systems, seismic geomorphology, seismic stratigraphy, and stratigraphic analysis to solve complex reservoir development and fluid-flow issues.Tim McHargue is a research consultant at ChevronTexaco and a consulting faculty at Stanford University. He received his B.S. and M.A. degrees from the University of Missouri and his Ph.D. from the University of Iowa. His research interests are in sequence stratigraphy, seismic stratigraphy, exploration, and reservoir characterization. Currently, Tim is coordinating geological research on turbidite reservoirs at ChevronTexaco. Steve Graham is a professor in the School of Earth Sciences, Stanford University. He teaches courses in sedimentary geology, seismic interpretation, sedimentary basin analysis, and petroleum reservoir characterization. His current research projects include studies of sedimentary basins in eastern Asia, South America, and the western United States, as well as studies of the sedimentology and stratigraphic architecture of deepwater deposits.

Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations

Abstract: Very low in situ permeability gas reservoirs (Kgas<0.1 mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

Incidence and Importance of Tectonics and Natural Fluid Migration on Reservoir Evolution in Foreland Fold-And-Thrust Belts

Abstract: Integrated structural-petrographic-magnetic-basin modeling case studies in numerous foreland fold-and-thrust belts provided key information on the critical parameters and processes controlling reservoir evolution from the end of the passive margin phase to the post-orogenic collapse of the tectonic pile. Fluid-rock interactions in reservoir rocks are intensified during tectonic events, as tectonic compaction in the foreland and development and re-opening of fracture systems in the allochthon help remobilizing basinal fluids, to squeeze-out host-rock buffered fluids as well as to reinject exotic fluids in reservoir sandstone or carbonate layers. For instance, quartz cementation in Sub-Andean foothills is dominantly controlled by Layer Parallel Shortening (LPS/tectonic compaction) in the footwall of frontal thrusts. LPS can also be inferred to cause in situ recrystallisation of mesodolomite in the Canadian Cordilleran Foreland Belt. In contrast, secondary hydrothermal dolomitization of limestone strata usually accounts for lateral migration in stratigraphic conduits in the foreland and for vertical migration of mineralizing fluids in open fractures in the allochthon, respectively. Alternatively, vuggy porosity observed in allochthonous carbonate strata in the North American Cordillera can also be interpreted to result from reservoir cooling operating in a dominantly closed fluid system during tectonic uplift and coeval erosion. Basin models can provide realistic estimates of burial-temperature history that can be compared to paleo-thermometers, such as fluid inclusions or stable isotopes, and thus provide a means to determine the relative age of cementation or dissolution episodes. Basin models can also provide fluid velocities, that can be subsequently used as critical constraints on diagenetic models at reservoir scale. Natural fluid-rock interactions induced by exotic tectonic fluids are short, no longer than one million years. As such, they constitute very good models of the long term effects of CO2 and H2 S injection and storage in natural reservoirs. The integrated quantitative appraisal approach proposed here for petroleum evaluation and reservoir prediction, also provides useful information on the overall changes in fluid flow regime and fluid velocities trough time in natural open systems, that should be used as regional boundary conditions for future reservoir storage and monitoring of acid gases in natural reservoirs.

Natural Geochemical Analogues for Carbon Dioxide Storage in Deep Geological Porous Reservoirs, a United Kingdom Perspective

Abstract: Elevated concentrations of atmospheric CO2 are implicated in global warming. Mitigation of this requires capture of CO2 from fossil fuel power sources and storage in subsurface aquifers or depleted hydrocarbon fields. Demonstration projects and financial analysis suggest that this is technologically feasible. CO2 must retained below ground for 104 y into the future to enable the surface carbon cycle to reduce atmospheric CO2 levels. To provide robust predictions of the performance of disposal sites at the required timescale, one approach is to study natural CO2 accumulations, which give insight into rock-CO2 -brine interactions over timescales of 103 - 5.106 y. In contrast to geochemical modelling predictions, natural CO2 fields in the North Sea (Brae, Miller, Magnus, Sleipner), at 4.0 km and deeper, do not show the mineral products which are predicted to form. Calcite and feldspar still comprise 5-20% of the rock, and dawsonite is absent. SE Australian and Arizona reservoir sandstones also do not fit to geochemical predictions. A state of disequilibrium possibly exists, so that existing geochemical modelling is not capable of accurately predicting kinetic-controlled and surface-chemistry controlled mineral dissolution or precipitation in natural subsurface sandstones on the required timescales. Improved calibration of models is required. Geochemical evidence from laboratory experiments (months to years duration), or from enhanced oil recovery (30 y duration) are again too short in timescale. To help to bridge the 104 y gap, it may be useful to examine natural analogues (103-106 y), which span the timescale required for durable disposal. The Colorado Plateau is a natural CO2 system, analogous to an hydrocarbon system, where 100 Gm3 CO2 fields occur, sourced from 0-5 Ma volcanics. Deep erosion has exposed the sediments which formed CO2 source, CO2 carrier, CO2 reservoir, CO2 trap, CO2 seal. Some very large CO2 traps are now exhumed, and some are currently leaking to form cool travertine springs at the surface. Natural examples at Salt Wash Green River, and at Moab Fault are briefly described. These show extensive bleaching of haematite which may be locally redeposited, carbonate cementation ?13C -70 around point sources, and silica precipitation, which may seal leak-off on buried anticline crests. Accurate geochemical modelling of the long-term performance of CO2 storage sites, requires improved understanding of CO2 reaction paths and reaction rates with aquifer reservoirs and with overlying seals. Robust prediction of disposal site performance is not possible without this.

Seismic time-lapse effects and stress changes: Examples from a compacting reservoir

Abstract: Compaction of unconsolidated reservoir rock represents a major drive mechanism in many oil and gas reservoirs. Significant volumes of produced hydrocarbons may be credited to this effect. However, compaction might also result in surface subsidence, a dynamic overburden, and local permeability losses in the reservoir.

The upper continental crust, an aquifer and its fluid: hydaulic and chemical data from 4 km depth in fractured crystalline basement rocks at the KTB test site

Abstract: Detailed information on the hydrogeologic and hydraulic properties of the deeper parts of the upper continental crust is scarce. The pilot hole of the deep research drillhole (KTB) in crystalline basement of central Germany provided access to the crust for an exceptional pumping experiment of 1-year duration. The hydraulic properties of fractured crystalline rocks at 4 km depth were derived from the well test and a total of 23100 m3 of saline fluid was pumped from the crustal reservoir. The experiment shows that the water-saturated fracture pore space of the brittle upper crust is highly connected, hence, the continental upper crust is an aquifer. The pressure–time data from the well tests showed three distinct flow periods: the first period relates to wellbore storage and skin effects, the second flow period shows the typical characteristics of the homogeneous isotropic basement rock aquifer and the third flow period relates to the influence of a distant hydraulic border, probably an effect of the Franconian lineament, a steep dipping major thrust fault known from surface geology. The data analysis provided a transmissivity of the pumped aquifer T = 6.1 × 10−6 m2 sec−1, the corresponding hydraulic conductivity (permeability) is K = 4.07 × 10−8 m sec−1 and the computed storage coefficient (storativity) of the aquifer of about S = 5 × 10−6. This unexpected high permeability of the continental upper crust is well within the conditions of possible advective flow. The average flow porosity of the fractured basement aquifer is 0.6–0.7% and this range can be taken as a representative and characteristic values for the continental upper crust in general. The chemical composition of the pumped fluid was nearly constant during the 1-year test. The total of dissolved solids amounts to 62 g l−1 and comprise mainly a mixture of CaCl2 and NaCl; all other dissolved components amount to about 2 g l−1. The cation proportions of the fluid (XCa approximately 0.6) reflects the mineralogical composition of the reservoir rock and the high salinity results from desiccation (H2O-loss) due to the formation of abundant hydrate minerals during water–rock interaction. The constant fluid composition suggests that the fluid has been pumped from a rather homogeneous reservoir lithology dominated by metagabbros and amphibolites containing abundant Ca-rich plagioclase.

Origin and reservoir rock characteristics of dolostones in the early triassic feixianguan formation, ne sichuan basin, china: significance for future gas exploration

Abstract: Major discoveries of natural gas have recently been made in the oolitic dolostones of the Early Triassic Feixianguan Formation in NE Sichuan Province, Southern China. These dolostones were formed by three facies-controlled dolomitization processes: (i) meteoric mixing zone dolomitization with dolomites having a relatively high degree of crystalline order (δ13C:−1.0 to 2.5%PDB; δ18O:−6.5 to −2.5%PDB); (ii) seepage-reflux dolomitization associated with evaporative brines; the corresponding dolomite crystals are relatively ordered and were formed in tidal flat environments and platform-margin oolitic shoals adjacent to lagoons; (iii) burial dolomitization (shallow to moderate burial depths, ca. 1,000 to 4,000m), whereby seawater-derived brines were present in the host rock and the resultant water/rock reactions played a major role in dolomitization. The three dolomitization processes were controlled by the arid climate prevailing during the Early Triassic, and also by fourth-order relative sea-level changes, especially with respect to the reflux dolomitization. Burial dolomitization, which is of second-order of importance for porosity development, was strongly dependant on the presence of sufficient original porosity to facilitate water-rock reactions within the carbonates. The best reservoir rocks formed as oolitic banks and bars in the vicinity of evaporative lagoonal-tidal complexes which experienced optimal conditions for dolomitization. Dolostones with a dolomite content of 80% to 90% form good vuggy reservoir rocks at the present day, indicating that the intensity of dolomitization influences the quality of reservoir rocks. According to our results, future gas exploration in the Feixianguan Formation dolostone reservoirs should focus on locating oolitic banks associated with evaporative lagoon and tidal flat complexes and delineating the best structural/lithological traps.

Analysis of petroleum system criticals of the Matruh–Shushan Basin, Western Desert, Egypt

Abstract: A systematic analysis of petroleum system criticals can provide a robust review of a basin9s hydrocarbon potential through time and space. The ten essential petroleum system criticals that express the extensive and intensive variables are: source generation volume (S gv ), source-rock richness (S gr ), source-rock quality (S rq ), source-rock maturity (S rm ), reservoir rock volume (R rv ), reservoir rock quality (R rq ), reservoir rock hydrocarbon type (R rhct ), reservoir rock seal and closure (R rsc ), flux migration path (F mp ) and petroleum system timing (PS t ). The Matruh–Shushan Basin of the Western Desert, Egypt, forms the basis for an example of the application of this technique. Modelling and empirical data of source-rock criticals reveal that the Mesozoic source generation megasequence is restricted in the Matruh–Shushan Basin. Presently, these areas lie buried at their maximum experienced temperatures. Potential reservoirs in portions of the north and central Western Desert were dependent upon lateral migration path criticals for their charge. Progressive uplift and basin inversion since the middle Palaeozoic provided favourable conditions for lateral migration in the Mesozoic. The main potential source rocks in the present basins are the Lower Cretaceous Alam El Bueib (AEB) and the Jurassic Khatatba. Although both share mixed kerogen types (II/III), they attained their highest levels of thermal maturity at different times. Basin modelling suggests the Lower Cretaceous AEB entered the oil window in the Late Cretaceous, while the Jurassic Khatatba of the deeper part of the basin entered the oil window in the Turonian. Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower post-Late Cretaceous structured reservoirs. Basin modelling incorporating an analysis of the petroleum system criticals has outlined the spatial and temporal extent of the different petroleum systems in the Matruh–Shushan Basin and can help guide the next exploration phase. While oil exploration is now focused appropriately along Late Cretaceous and Tertiary migration paths, these results suggest deeper sections may have reservoirs charged with significant unrealized gas potential.

Basic Characteristics and Concentration of the Puguang Gas Field in the Sichuan Basin

Abstract: The Puguang Field is the biggest and deepest gas field recently found in the Sichuan Basin of southern China with a proved gas reserve of 1144×108 m3 of the Feixianguan Formation reported to the National Mining Reserves Committee. Reserves of the three degree proved is 3500×108 m3. The reservoir rock of the Lower Triassic Feixianguan Formation is pure dolomite with oolitic dolomite and remnant oolitic dolomite. The reservoir has a high quality with medium to high porosity and permeability. The porosity may be related to the dissolution of deep thermal water. Closeness to the main hydrocarbon-producing sag, high-quality reservoir rock and timely uplifting are the favorable geological conditions to form this gas field.

A typical Cambrian oil reservoir: Origin of oil reservoir in Well TZ62, Tarim Basin

Abstract: The distribution of the Silurian asphaltic sandstones is very widespread in Tarim Basin. After the oil derived from Cambrian entered into the Silurian reservoir, the regional uplift of the crust destroyed the oil reservoir. It is not sure whether the Cambrian source rocks or the Middle and Upper Ordovician ones or both of them made contributions to the organic matters in the Silurian asphaltic sandstones. The chemical compositions of oil and oil-source rock analysis from Well TZ62 show that its sterane and terpane compounds possess the characteristics of Cambrian source rocks, indicating the oil from Well TZ62 was derived mainly from Cambrian. On the other hand, the sandstone lens in Well TZ62 was well trapped by the Silurian mudstone; therefore the oil reservoir in Well TZ62 has a good preservation condition, and was difficult to be filled by the later formed Middle and Upper Ordovician hydrocarbons. Accordingly, the Silurian oil reservoir in Well TZ62 is an ancient reservoir that was degraded slighter and preserved better than others. Among the reservoirs discovered in Tarim Basin, the oil reservoir in Well TZ62 is the first integrally preserved Silurian oil reservoir.

Oil Reservoirs and Oil Production

Abstract: This chapter introduces the world of petroleum. This is done as follows: first, a description of the reservoir object, which could be compared to the setting for a play; second, a presentation of fluids in the reservoir, which is like a presentation of the characters of this play; third, a description of production mechanisms, which could be compared to the history of the play; and fourth, a quick look at drilling, completion, and surface facilities, which are like methods of technical assistance for the smooth running of the play. Three classical steps are distinguished in oil recovery. Primary recovery corresponds to natural drive. It is obtained simply by reduction of the pressure in the reservoir. Secondary recovery consists of the injection of another fluid, water or gas, to maintain the reservoir pressure and to produce more oil. Tertiary recovery includes different and more sophisticated techniques aimed at increasing microscopic efficiency or sweep efficiency.

Pervasive Tight-gas Sandstone Reservoirs: An Overview

Abstract: The objectives of this chapter are threefold: (1) to provide a historical perspective on considerations of pervasive tight-gas accumulations, (2) to provide some observations on the present understanding of these accumulations, and (3) to anticipate where the industry is headed in the future. From 1979 to about 1987, various workers (industry, government, and academe) discussed pervasive tight-gas accumulations and established important relationships for source rock, maturity, expulsion and migration, pressures, rock quality, and fluid content. Their main conclusion was that the hydrocarbons in these reservoir systems were dynamic and not static as in conventional structural and stratigraphic traps. The paradigm shift made by 1987 concluded that these accumulations were continually adjusting to existing conditions in both time and space. In more recent years, additional examples have been documented, and questions have arisen about the validity of the original model, noting the presence of more water in some systems than the model would predict. The close proximity of the mature, gas-generating, and gas-expelling source rock to the reservoirs is critical. The amount and richness of mature source rock has to be adequate for the volume of reservoir rock being charged. The proper combination of these circumstances produces more gas than can be contained under normal pressure. The quantity of this gas charge relative to available pore space in the reservoir system will dictate the reservoir pressure. Pervasive tight-gas accumulations have now been documented in more than 20 North American basins and are the targets for major ongoing exploration and development programs. The average reservoir porosity for these producing units is in the 8–9% range, with average in-situ permeabilities of hundredths of a millidarcy. We believe the industry will likely move forward in four directions: (1) revisit older mature basins, (2) expand into new basins, (3) move into carbonate reservoirs, and (4) continue to develop tighter and tighter rock. With continuing technology improvements (especially in drilling and completing) and robust gas prices, the industry will access vast new reserves farther down into the resource pyramid.

Geophysical Well Log Study on the Paleoenvironment of the Hydrocarbon Producing Zones in the Erchungchi Formation, Hsinyin, SW Taiwan

Abstract: Gamma ray log facies of nine wells were used to reflect the vertical profile of grain size and were combined with well sample data to deduce the paleoenvironment of the Erchungchi ”A” Member in the Hsinyin and Pachanchi areas. Four log facies were recognized in the studied intervals: a thick funnel-shaped facies representing a prograding delta; a thin funnel-shaped facies representing a crevasse splay; a boxcar-shaped fades representing a distributary channel; a bell-shaped facies representing a fluvial or deltaic channel. The paleoenvironment of the Erchungchi ”A” Member in the Hsinyin area is mainly an imbricated delta system whose thickest lobe is located in Well S-1. The delta was first deposited in the headstreams of the submarine channels, followed by mudstones as cap rocks which seal hydrocarbons in stratigraphic traps. There are many submarine channels in southwestern Taiwan, so similar stratigraphic hydrocarbon trap conditions may occur elsewhere in southwestern Taiwan.

Egret-Hibernia(!), a significant petroleum system, northern Grand Banks area, offshore eastern Canada

Abstract: Egret-Hibernia(!) is a well-explored petroleum system (3.25 billion barrels oil equivalent [BOE]) located in the Jeanne d'Arc Basin on the Labrador–Newfoundland shelf. Rifting and sediment fill began in the Late Triassic. Egret source rock was deposited in the Late Jurassic at about 153 Ma. After this time, alternating reservoir rock and seal rock were deposited with some syndepositional faulting. By the end of the Early Cretaceous, faults and folds had formed numerous structural traps. For the next 100 m.y., overburden rock thermally matured the source rock when it reached almost 4 km (2.5 mi) burial depth. For 2 km (1.25 mi) below this depth, oil and gas were expelled, until the source was depleted. The expelled petroleum migrated updip to nearby faulted, anticlinal traps, where much of it migrated across faults and upsection to the Hibernia Formation (44% recoverable oil) and Avalon Formation (28%). Accumulation size decreased, and gas content increased from west to east, independent of trap size. These changes correspond to a decrease in source rock richness and quality from west to east.Almost all (96%) of the discovered petroleum resides in the Lower Cretaceous or older reservoir rock units. All accumulations found to date are normally pressured in structural traps. Fifty-two exploration wells found eighteen discoveries. Their size ranges from 1.2 to 0.01 billion BOE. Most discoveries were made between 1979 and 1991. The discovery cycle began with larger accumulations and progressed to smaller accumulations. The estimated sizes of the larger accumulations have grown since 1990. Estimated mean value for undiscovered hydrocarbons is 3.8 billion BOE, thereby raising the ultimate size of Egret-Hibernia(!) to 6.19 billion BOE.

Optimization of carbon dioxide sequestration and improved oil recovery in oil reservoirs

Abstract: Publisher Summary The vast majority of industrialized countries, irrespective of their position regarding the Kyoto Protocol, have started to take actions toward reducing the emission of carbon dioxide (CO2) and other gases, such as methane (CH4) and nitrous oxide (N20), into the atmosphere. However, application of CO2 storage or enhanced oil recovery (EOR) in carbonate reservoirs is more challenging due to their extreme heterogeneity of both porosity and permeability. Past injection/production practices, aquifer strength, reservoir heterogeneity, and CO2 injection schemes, such as injecting CO2 at the top or bottom of the reservoir or using horizontal wells instead of vertical wells for injection and production purposes are among the main factors affecting both oil recovery and CO2 storage capacity. It discusses the effects of different injection schemes and the timing of injection on optimization of oil recovery/CO2 storage capacity for a partially depleted oil reservoir.

Method for treating underground formations or cavities with microgels

Abstract: The invention concerns a method for treating porous and permeable underground formations or cavities, of the reservoir rock or backfill type. The method consists in injecting a liquid composition comprising microgels into the formations so as to reduce production of water, gas or sand, and/or zone abandonment.

The IEA Weyburn CO2 monitoring and storage project : integrated results from Europe

Abstract: The IEA Weyburn CO2 Monitoring and Storage Project has analysed the effects of a miscible CO2 flood into a carbonate reservoir rock at an onshore Canadian oilfield. Anthropogenic CO2 is being injected as part of an enhanced oil recovery operation. The European research was aimed at analyzing long-term migration pathways of CO2 and the effects of CO2 on the hydrochemical and mineralogical properties of the reservoir rock. The long term safety and performance of CO2 storage was assessed by the construction of a Features, Events and Processes (FEP) database which provides a comprehensive knowledge base for the geological storage of CO2. The pre-CO2 injection hydrogeological, hydrochemical and petrographical conditions in the reservoir were investigated in order to recognise changes caused by the CO2 flood and assessing the fate of the CO2. The Mississippian aquifer has a salinity gradient in the Weyburn area, where flows are oriented SW-NE. The baseline gas fluxes and CO2 concentrations in groundwater and soil were also researched. The dissolved gas in the reservoir waters has allowed potential transport pathways to be identified. Experimental studies of CO2-porewater-rock interactions in the Midale Marly unit have indicated slight dissolution of carbonate and silicate minerals, but relatively rapid saturation with respect to carbonate minerals. Equivalent studies on the overlying and underlying units show similar reaction processes, but secondary gypsum precipitation was also observed. Carbon dioxide flooding experiments on samples of the Midale Marly unit demonstrated that porosity and gas permeability increased significantly and calcite and dolomite were shown to have undergone corrosion. Hydrogeological modelling indicates that if any dissolved CO2 entered the main aquifers, it would be moved away from Weyburn in an E-NE direction at a rate of c. 0.2 m/year due to regional groundwater flow. Analysis of reservoir fluids proved that dissolved CO2 and CH4 increased significantly in the injection area between 2002 and 2003 and that solubility trapping accounts for the majority of the injected CO2, with little apparent mineral trapping. Twelve microseismic events were recorded and these are provisionally interpreted as being possibly related to small fractures formed by injection-driven fluid migration within the reservoir. Pre- and post-injection soil gas data are consistent with a shallow biological origin for the measured CO2. Isotopic (δ13C) data values are higher than in the injected CO2 and confirm this interpretation. No evidence for leakage of the injected CO2 to ground level has so far been detected.

Hydrologic and geochemical controls on soluble benzene migration in sedimentary basins

Abstract: The effects of groundwater flow and biodegradation on the long-distance migration of petroleum-derived benzene in oil-bearing sedimentary basins are evaluated. Using an idealized basin representation, a coupled groundwater flow and heat transfer model computes the hydraulic head, stream function, and temperature in the basin. A coupled mass transport model simulates water washing of benzene from an oil reservoir and its miscible, advective/dispersive transport by groundwater. Benzene mass transfer at the oil–water contact is computed assuming equilibrium partitioning. A first-order rate constant is used to represent aqueous benzene biodegradation. A sensitivity study is used to evaluate the effect of the variation in aquifer/geochemical parameters and oil reservoir location on benzene transport. Our results indicate that in a basin with active hydrodynamics, miscible benzene transport is dominated by advection. Diffusion may dominate within the cap rock when its permeability is less than 10 m. Miscible benzene transport can form surface anomalies, sometimes adjacent to oil fields. Biodegradation controls the distance of transport down-gradient from a reservoir. We conclude that benzene detected in exploration wells may indicate an oil reservoir that lies hydraulically up-gradient. Geochemical sampling of hydrocarbons from springs and exploration wells can be useful only when the oil reservoir is located within about 20 km. Benzene soil gas anomalies may form due to regional hydrodynamics rather than separate phase migration. Diffusion alone cannot explain the elevated benzene concentration observed in carrier beds several km away from oil fields.

Acid gas injection in the Brazeau Nisku Q carbonate reservoir: Geochemical reactions as a result of the injection of an H2S-CO2 waste stream

Abstract: Publisher Summary Storage of greenhouse gases in geological media is regarded as a potential option for reducing release of CO2 emissions to the atmosphere. Industrial analogues are found in acid gas injection which injects mixtures of waste streams of H2S and CO2 (derived from gas processing of sour gas) into spent oil and gas reservoirs and aquifers for disposal. This is currently occurring at over forty sites in western Canada. To date no leakage has been reported. A review of these acid gas operations has been undertaken in the chapter with a view to evaluating their storage security. The reservoir temperature and pressure, before injection of an acid gas stream of 85% H2S and 15% CO2, was 110°C and 11 MPa. Geochemical mass transfer modeling using GAMSPATH.99 under these conditions predicts that the iron containing minerals in the reservoir will break down rapidly to form iron sulphide minerals. This was verified experimentally in the laboratory at much lower pressures through observation of significant reaction of siderite to iron sulphide at 54°C and 0.5 MPa in a CO2-H2S atmosphere in two weeks. Solubility trapping and ionic trapping are significantly larger, by approximately 10%, if the acid gas-charged fluids react to equilibrium with the reservoir rock, compared to no reaction with the reservoir minerals. In Brazeau, mineral trapping of H2S by iron sulphide minerals dominates due to the high H2S content of the injected gas, reaching trapping levels exceeding 20 moles of H2S per 1000 cc of pore space. In the absence of H2S, mineral trapping of CO2 by carbonate minerals would have dominated.

When 4D seismic is not applicable: Alternative monitoring scenarios for the Arab-D reservoir in the Ghawar Field

Abstract: Ghawar, the largest oilfield in the world, produces oil from the Upper Jurassic Arab‐D carbonate reservoir. The high rigidity of the limestone–dolomite reservoir rock matrix and the small contrast between the elastic properties of the pore fluids, i.e. oil and water, are responsible for the weak 4D seismic effect due to oil production. A feasibility study was recently completed to quantify the 4D seismic response of reservoir saturation changes as brine replaced oil. The study consisted of analysing reservoir rock physics, petro‐acoustic data and seismic modelling. A seismic model of flow simulation using fluid substitution concluded that time‐lapse surface seismic or conventional 4D seismic is unlikely to detect the floodfront within the repeatability of surface seismic measurements. Thus, an alternative approach to 4D seismic for reservoir fluid monitoring is proposed. Permanent seismic sensors could be installed in a borehole and on the surface for passive monitoring of microseismic activity from reservoir pore‐pressure perturbations. Reservoir production and injection operations create these pressure or stress perturbations. Reservoir heterogeneities affecting the fluid flow could be mapped by recording the distribution of epicentre locations of these microseisms or small earthquakes. The permanent borehole sensors could also record repeated offset vertical seismic profiling surveys using a surface source at a fixed location to ensure repeatability. The repeated vertical seismic profiling could image the change in reservoir properties with production.