Elk Hills Research Articles

Assessing potential effects of oil and gas development activities on groundwater quality near and overlying the Elk Hills and North Coles Levee Oil Fields, San Joaquin Valley, California

Groundwater resources are utilized near areas of intensive oil and gas development in California’s San Joaquin Valley. In this study, we examined chemical and isotopic data to assess if thermogenic gas or saline water from oil producing formations have mixed with groundwater near the Elk Hills and North Coles Levee Oil Fields in the southwestern San Joaquin Valley. Major ion concentrations and stable isotope compositions were largely consistent with natural processes, including mixing of different recharge sources and water-rock interactions. Trace methane concentrations likely resulted from microbial rather than thermogenic sources. Trace concentrations of benzene and other dissolved hydrocarbons in three wells had uncertain sources that could occur naturally or be derived from oil and gas development activities or other anthropogenic sources. In the mid-1990s, two industrial supply wells had increasing Cl and B concentrations likely explained by mixing with up to 15 percent saline oil-field water injected for disposal in nearby injection disposal wells. Shallow groundwater along the western margin of Buena Vista Lake Bed had elevated Cl, B, and SO4 concentrations that could be explained by accumulation of salts during natural wetting and drying cycles or, alternatively, legacy surface disposal of saline oil-field water in upgradient ephemeral drainages. This study showed that groundwater had relatively little evidence of thermogenic gas or saline water from oil and gas sources in most parts of the study area. However, the evidence for groundwater mixing with injected disposal water, and possibly legacy surface disposal water, demonstrates produced water management practices as a potential risk factor for groundwater-quality degradation near oil and gas fields. Additional studies in the San Joaquin Valley and elsewhere could improve understanding of such risks by assessing the locations, volumes, and types of produced water disposal practices used during the life of oil fields.

Mapping aquifer salinity gradients and effects of oil field produced water disposal using geophysical logs: Elk Hills, Buena Vista and Coles Levee Oil Fields, San Joaquin Valley, California.

The effects of oil and gas production on adjacent groundwater quality are becoming a concern in many areas of the United States. As a result, it has become increasingly important to identify which aquifers require monitoring and protection. In this study, we map the extent of groundwater with less than 10,000 mg/L TDS both laterally and vertically near the Elk Hills, Buena Vista and Coles Levee Oil Fields in the San Joaquin Valley, California and note evidence of effects of produced water disposal on salinity within the Tulare aquifer. Subsurface maps showing the depth at which groundwater salinity is less than 10,000 mg/L (or Base 10K) in the Tulare aquifer are generated using geophysical logs and verified by comparison to water sample analyses. The depth to Base 10K ranges from 240 m (800 ft) in Elk Hills to 800 m (2650 ft) in the adjacent Buena Vista syncline and is 670 m (2,200 ft) deep in the Coles Levee area to the east. Log-calculated salinities show a relatively smooth increase with depth prior to disposal activities whereas salinities calculated from logs collected near and after disposal activities show a more variable salinity profile with depth. The effect of produced water injection is represented by log resistivity profiles that change from low resistivity at the base of the sand to higher resistivity near the top due to density differences between the saline produced water and the brackish groundwater within each sand. Continued post-disposal logging in new wells in the 18G disposal area on the south flank of Elk Hills shows that injected water has migrated approximately 1,200 m (4,000 ft) downdip (south) over a period of 20 years since the inception of disposal activity.

Front End Engineering Design Study for Carbon Capture at a Natural Gas Combined Cycle Power Plant in California

The Electric Power Research Institute (EPRI), California Resources Corporation (CRC), and Fluor Corporation are conducting a Front-End Engineering Design (FEED) study to determine the technical and economic feasibility of a retrofit, post-combustion, carbon capture technology on a commercially operating, natural gas-fired, combined cycle (NGCC) power plant in California. Fluor’s Econamine FG PlusSM (EFG+) process is being designed to capture CO2 from the flue gas produced by CRC’s 550 MWe Elk Hills Power Plant (EHPP), a NGCC unit located in the Elk Hills Oil Field near Tupman, Kern County, California. The design basis is to route about 79% of the flue to Fluor’s EFG+ plant with the remaining 21% vented as normal through the stack. Steam is supplied to the capture plant from a gas-fired package boiler whose flue gas is combined with the EHPP flue gas as it’s routed to the EFG+ process. The EFG+ process then captures 90% of the total combined inlet CO2. Overall, about 4,000 tonne (t) CO2/day will be captured and delivered at 97+ mol% purity and 160 bar pressure for use by CRC for CO2 enhanced oil recovery (EOR) or CO2 storage in nearby reservoirs. CRC is one of the largest oil producers in California (132,000 barrels oil equivalent/day) and is pursuing CO2-EOR to increase oil output from California’s Elk Hills field. EHPP is unique in that CRC owns and operates the NGCC power plant, provides its natural gas fuel supply, uses much of its steam and electrical output, and will use the captured CO2 for either CO2 enhanced oil recovery or CO2 storage. The regulatory and tax incentives at the California State level and at the U.S. Federal level combined with the use of CO2 for enhanced oil recovery by CRC, provide a significant commercial interest in using the captured CO2 for enhanced oil recovery in California’s Elk Hills region. Permitting work around CCS with EOR in Elk Hills was initiated in 2010, including an expansive Monitoring, Reporting and Verification (MRV) plan. Regulatory outreach and execution for the current CCS-EOR project were initiated in early 2018 via direct engagement with multiple state and federal agencies. Assuming the FEED study results are favourable, this project could lead to deployment of one of the world’s largest carbon capture processes on a power plant – coal- or gas-fired.

Production-induced fault compartmentalization at Elk Hills field, California

Mature and aging clastic-dominated hydrocarbon fields commonly become increasingly difficult to produce, causing lower economic return than initially forecast. A major cause of this reduced economic viability is compartmentalization, defined as limitation on the ability to produce hydrocarbons resulting from permeability barriers within a field. Three primary causes of compartmentalization are structural variations in permeability, stratigraphic variations in permeability, and permeability reduction resulting from compaction adjacent to producing wellbores. Recognition and delineation of compartmentalization permit formulation of development and depletion plans to maximize recovery and economic value. Here, we examine one of 52 reservoir-scale faults that compartmentalize the eastern shallow oil zone (ESOZ), Elk Hills field, California. Using well-log, stratigraphic, structural, and pressure data, we apply standard fault seal analyses to the selected fault. Results are compared with known pressure conditions across the fault and show the fault capable of supporting pressure differentials two to three times those expected from standard static fault seal measures. Although this observation could be used as a basis for local calibration of standard fault seal measures for a dynamic seal, such an approach assumes that these fault seal mechanisms are in fact the cause of sealing behavior. Alternatively, one of the most significant changes in ESOZ reservoir conditions over the production lifetime of the field is the reduction of fluid pressure from approximately 1500 to approximately 200 psi (from ∼10.27 to ∼1.37 MPa). Decreasing fluid pressure would have driven stress states acting on faults in the reservoir from critical (near or at slip) to stable (nonslipping) conditions. Critically stressed faults and fractures are more transmissive than those that are noncritically stressed. We propose that decreasing fluid pressure can cause faults to become less leaky, causing production-induced reservoir compartmentalization.

Overview: Reservoir Simulation and Visualization (June 2007)

This year I was in undated with quality papers relating to the topic of reservoir simulation. A quick look at the titles of the papers presented in this area over the past year showed a clear trend. "History matching" is far and away the number one topic of interest in the reservoir-simulation community. In fact, 25% of the papers available for review this year contained the term "history match" or "history matching" in the title. In light of this trend, all the papers presented for review and recommended reading this month relate to algorithms, modeling guidelines, and case studies involving history matching. Gone are the days when reservoir-simulation history-match studies were allowed to take several months or longer to complete. Fewer simulation engineers are trying to manage more reservoir-simulation projects. The natural outcome is a need for automation. There is the danger of automatic processes generating simulation results that are not feasible from an engineering perspective. As several of the authors point out, there is a caveat to automated history matching—engineering judgment is still required to guide the process. However, in addition to matching history, the automation procedure also must quantify the measure of the uncertainty of the reservoir. With this new-found capability to generate numerous models with similar quality of history match, the real test of a history-matched model is the predictability it provides. In addition, a secondary trend emerged from the stack of SPE papers on my desk. Not only is there a need to produce history-matched results faster, there is a need to produce these results for more-complex reservoirs. Increased energy is being spent on enhanced characterization of naturally fractured reservoirs and those with more-complex fluid systems. The need to automate the history-matching process of these complex reservoirs tends to be even greater because of the inherent computer times required for each simulation run. In searching for a third trend among the papers on my desk, the subject of visualization jumped out at me. Actually, the subject jumped out at me by its absence, because there were no papers that specifically addressed the subject. Yet, in a way, all the papers on automated history matching addressed it. In each of the reviewed papers, there are charts, figures, and diagrams that attempt to graphically uncover the key results from a set of hundreds or thousands of reservoir-simulation runs. As we invent new processes to automatically create more data, we need to continue to develop innovative ways to "see" the results. Reservoir Simulation and Visualization additional reading available at the SPE eLibrary: www.spe.org SPE 99578 "Efficient History Matching in Naturally Fractured Reservoirs" by T. Gang, SPE, University of Tulsa, et al. SPE 100489 "Soft Computing Algorithms Accelerate and Improve the History-Matching Process: Elk Hills, California—29R Reservoir" by T. Firincioglu, Nitec LLC, et al. SPE 102676 "Compositional and Grid-Orientation Effects in History Matching" by D. Eydinov, University of Bergen, et al. SPE 106044 "Event-Targeting Model Calibration Used for History Matching Large Simulation Cases" by Stig Selberg, SPE, Scandpower Petroleum Technology, et al.

Identifying Applications for Turbodrilling and Evaluating Historical Performances in North America

Abstract As gas reserves at shallower depths are depleted and the decline rate of producing reservoirs accelerates, the search for economically viable reservoirs in North America now focuses on drilling to greater depths. Deeper drilling creates added challenges: harder, more abrasive rock, elevated temperatures, higher pressures and higher costs to drill and operate. These operations will narrow the margin for error and create opportunities to add significant value through the drilling and completion process. Therefore, it is imperative to evaluate all available technology when selecting the optimum drilling equipment through a more technically stringent economic model. Through this evaluation, applications in which turbodrilling can be economically beneficial will be evident. Turbodrills have been used in the oil and gas industry since the 1920's, yet they remain relatively obscure. This paper examines the history of turbodrilling and describes a number of the harshest and most complex drilling environments in which turbodrills have been notably successful. Through a historical analysis of turbodrilling, the evolution of the technology, including the most recent technological advancements, is detailed. Finally, recent case histories in North America are evaluated for application and performance. Introduction to Turbodrilling The use of turbine power in drilling was introduced in the United States over a century ago, in 1873. The first patent, a single-stage, impulse turbodrill, was issued to C. Cross. In 1884, the turbodrill design was rethought and a second patent was issued to M. Baker for a single-stage, axial flow turbodrill. Over the next 40 years, few advancements were made to the technology of turbodrilling. Most design emphasis during this period was directed to the development of the rotary drilling rig, which, in 1901, was used to drill the Spindletop discovery well. This discovery proved to mark the beginning of the modern petroleum industry. It was not long until better, more efficient methods for drilling were considered essential. Turbodrill developments resumed in the US in 1922. In 1924, the multi-stage, axial flow turbodrill was patented by Scharpenburg. The Scharpenburg design was tested in Elk Hills, California in 1926 with mixed results. During the following 10 years, the design was improved with the addition of rubber radial bearings and the removal of specific internal seals with which it was originally equipped(1). At about the same time, in 1923, Russian engineers began development work on a single-stage turbodrill for oil and gas drilling applications. In 1924, the Russians developed the first geared turbodrill in conjunction with a single-stage, axial flow design. These developments were motivated by an interest in modifying one of the main turbodrill characteristics: high rotational velocity (RPM). The hope was to increase the nominal drive shaft torque, while reducing drive shaft speed. The planned modification hoped to reduce turbodrill output RPM, then ranging between 2,000 and 3,000 RPM to 15–60 RPM at the drill bit. Since drill bit technology of the day was in its infancy, and the only drill bits available in Russia were roller cone bits, this entire development was an attempt to lower the output RPM to a range in which a roller cone bit could endure.

Mechanical and stratigraphic constraints on the evolution of faulting at Elk Hills, California

To unravel the four-dimensional evolution of the Elk Hills oil field, Kern County, California, we integrated seismically interpreted fault surfaces, stratigraphic units, and stratigraphic features with mechanical models. Correspondence of synthetic stratigraphic surfaces, deformed by modeled vertical-displacement fields, to seismically interpreted stratigraphic surfaces represented on structure contour maps suggests that the tectonic history described here is structurally, stratigraphically, and mechanically consistent, placing constraints on the regional deformation mechanism and local structure. During the period investigated, middle Miocene to present, the eastern and the western parts of the Elk Hills anticline developed in response to a regional horizontal shortening oriented at about 35. The apparent bend in the trend of the anticline, from northwest-southeast in the western part of the field to east-west in the eastern part of the field, is generated by the intersection of two distinct fault systems. In both fault systems, north-dipping fault surfaces are backthrusts of older south-dipping faults. These results have direct implications for the migration and emplacement of hydrocarbons at Elk Hills, suggesting that the upper Miocene Stevens turbidite oil pools were derived from sources to the south. Additionally, this study indicates that the method by which stratigraphic and structural interpretations are incorporated into a sequence of forward mechanical models represents an effective means of constraining the structural evolution of a fault network that developed within a syndepositional tectonic setting.

Implications of a freshwater radiocarbon reservoir correction for the timing of late Holocene settlement of the Elk Hills, Kern County, California

Uncertainties regarding the magnitude of freshwater radiocarbon reservoir effects can introduce random errors into dates on archaeological freshwater carbonates. As a result, many archaeologists avoid dating freshwater shells unless no other datable materials are available. The chronology of prehistoric occupation of the former Naval Petroleum Reserve No. 1 (NPR-1) at Elk Hills, Kern County, has been established with 50 radiocarbon dates on freshwater mussels ( Gonidea and Anodonta sp.). Characterization of any freshwater radiocarbon reservoir effect is crucial for the accurate interpretation of inferred settlement and subsistence changes on the Elk Hills. Paired charcoal and freshwater mussels sampled from closely associated contexts were dated to identify a freshwater reservoir effect. Paired Anodonta and Gonidea sp. shells were dated to investigate interspecific differences in fractionation. Results indicate that a 340 ± 20 14C yr correction should be applied to conventional 14C dates on freshwater carbonates in the Buena Vista Basin before calendar calibration. Evidence of interspecific differences is inconclusive. Dates recalibrated with the reservoir correction indicate that widespread occupation of the Elk Hills is correlated with increasing precipitation towards the end of the Medieval Climatic Anomaly and during the Little Ice Age, suggesting that slough resource exploitation may have been driven by regional population pressure rather than drought-related declines in aquatic productivity.

Charging of Elk Hills reservoirs as determined by oil geochemistry

Crude oils from Miocene and Pliocene reservoirs from the Elk Hills field in California's San Joaquin basin were analyzed for stable carbon isotopes and biomarkers. Cluster analysis of geochemical variables defines five principal oil families, all derived from different organic-rich facies of the Miocene Monterey Formation. Carbon isotope analysis indicates no contribution from the basin's other major source rock, the Eocene Kreyenhagen Formation. Oil families show a strong correspondence to stratigraphic intervals. Oils from pre-Monterey reservoirs were probably generated from the lowermost organic-rich facies of the Monterey and are the most thermally mature. Upper Miocene Stevens zone turbidite reservoirs contain oils of various thermal-maturity stages, but mature light ends are abundant and are likely generated from the floors of the adjacent subbasins located north and south of Elk Hills. The relatively minor presence of low-thermal-maturity biomarkers that are typically characteristic of Monterey oils may indicate that Stevens traps did not form until after the source intervals were at a higher level of thermal maturity. All oils in Stevens porcelanite reservoirs contain a higher concentration of low-maturity biomarkers, which may indicate derivation from more localized areas on the flanks of the Elk Hills anticlines. The shallow Pliocene oils have suffered biodegradation to different degrees, and the lowest API gravities occur on the flanks of the anticline. The carbon isotopic composition of these oils suggests yet another Monterey source facies that charged the Pliocene reservoirs and is not simply the result of vertical leakage from the older Miocene reservoirs. John E. Zumberge has been vice president and cofounder of GeoMark Research in Houston since 1991. He was manager of geochemical and geological research for Cities Service–Occidental, general manager for Ruska Laboratories, and director of geochemical services for Core Laboratories. He has global experience in petroleum geochemistry, focusing on crude-oil biomarkers. He obtained a B.S. degree in chemistry from the University of Michigan and a Ph.D. in organic geochemistry from the University of Arizona.Judy A. Russell is a senior geological advisor for Occidental and works on worldwide exploration and production, with an emphasis on the integration of geochemistry. She has extensive experience in many of Occidental's projects in Latin America, Far East, the United States, and the Middle East. She has a B.S. degree from Phillips University and an M.S. degree from the New Mexico Institute of Mining and Technology. Stephen Anthony Reid is a senior geological advisor for Occidental and works on international exploration, with an emphasis on deep-water projects. He has extensive experience in California's San Joaquin basin, including the Elk Hills field, where he conducted studies on Stevens turbidite and Monterey porcelanite reservoirs. He has B.S. and M.S. degrees from California State University, Northridge.

Value of In-Situ Seismic Waves - Regain Lost Reserves, Increase Oil Cut

When Occidental of Elk Hills (Oxy) opted to explore a new enhanced-oil-recovery (EOR) method—in-situ seismic stimulation—to increase oil recovery in declining reservoirs, liberating residual oil was but one outcome. Oxy’s seismic-stimulation project offered improved oil recovery and increased flow, positive impact on relative phase permeability, and an understanding of the magnitude and extent of the stimulated area. This technology and project results are based on and can be correlated to oil response resulting from natural earthquakes. It is the first departure from variants on conventional stimulation methods (thermal, polymer, chemical, microbial) to be introduced commercially since the 1970s. While efforts were made in the 1980s to duplicate earthquake effects by use of vibrators above a targeted zone, these attempts had disadvantages that limited commercial viability. Hydro-Impact stimulation services developed by Applied Seismic Research Corp., currently in use in the U.S. in California and Texas, involve the placement of tools to generate subsurface shockwaves that mimic primary waves generated by earthquakes. These shockwaves, generated every 10 seconds, produce power ranging from ≈1 to 10 million watts with pressure at the wave front that can be in excess of 4,000 psi. The waves, traveling at approximately 1½ miles/sec, generally are noticeably felt on the surface only in close proximity to the wellbore, but they have a significant measured seismic signal at distances of ¾ mile from the source (Fig. 1). Historically, effects from sonic stimulation could reach only 20 ft. The waves affect oil-bearing strata and increase the potential for oil flow by inducing coalescence of residual oil. The effect of the seismic shock: oil droplets are dislodged from the pore wall and coalesce into larger droplets that become mobile and move into flow streams that then begin to move into any existing flow system such as fractures. In some cases, reservoirs exhibit a permanent increase in oil cut as a result of a permanent fieldwide improvement in injectivity when deployed on injectors, but this is unpredictable. Other fields return to the original decline soon after seismic stimulation is stopped and require stimulation on a continuous basis. Because the seismic wave passes through the wellbore casing and cement within microseconds, it does not damage the wellbore or formation. The wave, propagating in all directions to eventually become an elastic wave, also can be used simultaneously with ongoing injection processes and considerably increases injectivity both in the injection well in which the tool is installed and other injection wells within the affected area.

Lessons Learned: Obtaining Value from Federal Asset Sales

If the government decides to sell assets, how can it obtain full value? Four case studies provide valuable lessons: (1) sale of the Elk Hills oil field by the U.S. Department of Energy, (2) sales of loans and property by the Resolution Trust Corporation (RTC) after the savings and loan debacle, (3) loan asset sales by the Small Business Administration (SBA), and (4) excess property sales by the Defense Reutilization and Management Service (DRMS). The federal government should create an office to assist agencies that seek to develop effective asset sales programs.

Fracture Stimulation Optimization in a Mature Waterflood Redevelopment

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 76723, "Fracture Stimulation Optimization in the Redevelopment of a Mature Waterflood, Elk Hills Field, California," by Tom Walker, SPE, Shawn Kerns, SPE, Dick Scott, SPE, and Paul White, SPE, Occidental of Elk Hills Inc.; John Harkrider, SPE, Apex Petroleum Engineering; Craig Miller, SPE, BJ Services Co.; and Tarlochan Singh, SPE, Pinnacle Technologies Inc., originally presented at the 2002 SPE Western Regional/AAPG Pacific Section Joint Meeting, Anchorage, 20-22 May.

Waterflood Surveillance: Behind Casing Resistivity Measurement at Elk Hills

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 76730, "Next Generation Waterflood Surveillance: Behind Casing Resistivity Measurement Successfully Applied in the 'A3-A6' Waterflood at Elk Hills Field, Kern County, California," by Mark Starcher, SPE, Dave Mut, SPE, and Mike Fontanarosa, Occidental of Elk Hills, Inc., and Bob Davis, SPE, and Chris Presmyk, SPE, Schlumberger, originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October.

Monterey Formation porcelanite reservoirs of the Elk Hills field, Kern County, California

Oil and gas production from Monterey Formation porcelanite at the Elk Hills field in California's San Joaquin basin occurs from intervals that have quartz-phase mineralogy. However, characteristics differ from chert and porcelanite reservoirs of the coastal California Monterey Formation in that matrix porosity is more typical of the opal-CT phase, petroleum storage is mostly in the matrix, and natural fracture patterns are dominantly small scale. Several Elk Hills reservoirs located on two large anticlines produce from porcelanite. The 29R AB and 31S D are the most productive porcelanite reservoirs, each having cumulative oil production of about 40 million bbl. Although interbedded with siliceous shale, sandstone, and dolomite, most of the porous reservoir rock is laminated porcelanite. Porosity averages between 20 and 25% and is evenly distributed throughout the porcelanite as extremely small pores ranging in size from 1 to 10 µm. Matrix permeability averages 0.8 md, but flow of oil and gas is enhanced through fractures parallel with and perpendicular to bedding. Higher than anticipated porosity may be in part due to migration of hydrocarbons into the porcelanite reservoirs while still in opal-CT-phase mineralogy. The dissolution of opal-CT and precipitation of quartz occurs in place, and the resulting quartz-phase mineral structure mimicks the porous opal-CT framework.

ABSTRACT: Geostatistical Modeling of the Elk Hills 26R, 31S, and Northwest Stevens Reservoirs, California

ABSTRACT: Geostatistical Modeling of the Elk Hills 26R, 31S, and Northwest Stevens Reservoirs, California

ABSTRACT: Silica Phase and Compositional Controls on Pore Throat Distributions--Porcelanite and Siliceous Shale of the Elk Hills Field, California

ABSTRACT: Silica Phase and Compositional Controls on Pore Throat Distributions--Porcelanite and Siliceous Shale of the Elk Hills Field, California

Improved Oil Recovery from a Mature Monterey Formation Sandstone Reservoir Using Low Cost Intermediate Radius Horizontal Producers at Elk Hills, Kern County, CA

Improved Oil Recovery from a Mature Monterey Formation Sandstone Reservoir Using Low Cost Intermediate Radius Horizontal Producers at Elk Hills, Kern County, CA

Temblor Formation Stratigraphy and Depositional Systems, NPR-2 and Elk Hills Areas, Kern Co., California

Temblor Formation Stratigraphy and Depositional Systems, NPR-2 and Elk Hills Areas, Kern Co., California

Stratigraphy and Depositional Systems of the Miocene Carneros Sandstone Member of the Temblor Formation, Southwest Elk Hills Area, California

Stratigraphy and Depositional Systems of the Miocene Carneros Sandstone Member of the Temblor Formation, Southwest Elk Hills Area, California

Selling Elk Hills: The Political Economy of US Federal Divestment

Click to increase image sizeClick to decrease image size Additional informationNotes on contributorsJerome HinkleJerome Hinkle is a Senior Planner in the US Department of Energy.