Lost Hills Oil Field Research Articles

Monitoring and analysing long-term vertical time-series deformation due to oil and gas extraction using multi-track SAR dataset: A study on lost hills oilfield

The Lost Hills oilfield, located ∼70 km northwest of Bakersfield in the San Joaquin Valley, has a long history of oil/gas extraction, and it suffers from long-term ground deformation. Many SAR datasets include information about the Lost Hills oilfield over the past two decades. This study focused on calculating and analysing the long-term vertical ground deformation due to oil and gas extraction in the Lost Hills oilfield and proposed a new strategy inspired by the “Small Baseline Subset” idea for jointly processing multi-track SAR images to obtain long-term time-series deformations. The experimental results showed a maximum vertical deformation rate of 20 mm/year in the uplift region and –90 mm/year in the subsidence region of the Lost Hills field from August 1995 to September 2010, and the long-term vertical time-series deformations had a precision of 5 mm. In addition, a multivariate polynomial regression model was used to quantify the relationship between surface deformation volume changes and water, oil, and gas injection-production data. The results demonstrated that the relationship between the ground volume change and injection/production dataset in the subsidence region followed a multivariate linear model, whereas the uplift region satisfied a multivariate quadratic polynomial model. The modelling results provided a new perspective on interpreting ground deformation due to oil/gas extraction.

Lost Hills Solar Project: Powering an Oil and Gas Field with California Sunshine

Summary This paper outlines one of the first efforts by a major oil and gas company to build a net-exporting, behind-the-meter solar photovoltaic (PV) plant to lower the operating costs and carbon intensity of a large, mature oil and gas field. The 29 MWAC (35 MWDC) Lost Hills solar plant in Lost Hills, California, USA, commissioned in April 2020, covers approximately 220 acres on land adjacent to the oil field and is designed to provide more than 1.4 TWh of solar energy over 20 years to the field’s oil and gas production and processing facilities. The upgrades to the electrical infrastructure in the field also include new technology to reduce the risk of sulfur hexafluoride emissions, another potent greenhouse gas (GHG). Before the solar project, the Lost Hills field was importing all its electricity from the grid. With the introduction of the Innovative Crude Program as part of California’s Low Carbon Fuel Standard (LCFS) and revisions to the California Public Utilities Commission Net Energy Metering program, Lost Hills was presented with a unique opportunity to reduce its imported electricity expenses and reduce its carbon intensity, while also generating LCFS credits. The solar plant was designed to power the field during the day and export excess power to the grid to help offset nighttime electricity purchases. It operates under a power purchase agreement (PPA) with the solar PV provider and, initially, will meet approximately 80% of the oil field’s energy needs. Future plans include incorporating 20 MWh of lithium-ion batteries, direct current (DC)–coupled with the solar inverters. This energy storage system will increase the amount of solar electricity fed directly into the field and reduce costs by controlling when the site uses stored solar electricity rather than electricity from the grid. The battery system will also increase the number of LCFS credits by 15% over credits generated by solar alone. Together, solar power and energy storage provide a robust renewable energy solution. This project will generate multiple cobenefits for the Lost Hills oil field by lowering the cost of power, reducing GHG emissions, generating state LCFS credits and federal Renewable Energy Certificates, and demonstrating a commitment to energy transition by investing in renewable technology. Conceivably, the Lost Hills solar project can be a model for similar future projects in other oil fields, not only in California, but across the globe.

Tracing enhanced oil recovery signatures in casing gases from the Lost Hills oil field using noble gases

Enhanced oil recovery (EOR) and hydraulic fracturing practices are commonly used methods to improve hydrocarbon extraction efficiency; however, the environmental effects of such practices remain poorly understood. EOR is particularly prevalent in oil fields throughout California where water resources are in high demand and the disposal of large volumes of produced water may affect groundwater quality. Consequently, it is essential to better understand the fate of injected (EOR) fluids in California, and other subsurface petroleum systems, as well as any potential effect on nearby aquifer systems. Noble gases can be used as tracers to understand hydrocarbon generation, migration, and storage conditions, as well as the relative proportions of oil and water present in the subsurface. In addition, a noble gas signature diagnostic of injected (EOR) fluids can be readily identified. We report noble gas isotope and concentration data in casing gases from oil production wells in the Lost Hills oil field, northwest of Bakersfield, California, and injectate gas data from the Fruitvale oil field, located within the city of Bakersfield. Casing and injectate gas data are used to: 1) establish pristine hydrocarbon noble-gas signatures and the processes controlling noble gas distributions, 2) characterize the noble gas signature of injectate fluids, 3) trace injectate fluids in the subsurface, and 4) construct a model to estimate EOR efficiency. Noble gas results range from pristine to significantly modified by EOR, and can be best explained using a solubility exchange model between oil and connate/formation fluids, followed by gas exsolution upon production. This model is sensitive to oil–water interaction during hydrocarbon expulsion, migration, and storage at reservoir conditions, as well as any subsequent modification by EOR.

Data Assimilation of Coupled Fluid Flow and Geomechanics Using the Ensemble Kalman Filter

Summary In reservoir history matching or data assimilation, dynamic data, such as production rates and pressures, are used to constrain reservoir models and to update model parameters. As such, even if under certain conceptualization the model parameters do not vary with time, the estimate of such parameters may change with the available observations and, thus, with time. In reality, the production process may lead to changes in both the flow and geomechanics fields, which are dynamically coupled. For example, the variations in the stress/strain field lead to changes in porosity and permeability of the reservoir and, hence, in the flow field. In weak formations, such as the Lost Hills oil field, fluid extraction may cause a large compaction to the reservoir rock and a significant subsidence at the land surface, resulting in huge economic losses and detrimental environmental consequences. The strong nonlinear coupling between reservoir flow and geomechanics poses a challenge to constructing a reliable model for predicting oil recovery in such reservoirs. On the other hand, the subsidence and other geomechanics observations can provide additional insight into the nature of the reservoir rock and help constrain the reservoir model if used wisely. In this study, the ensemble-Kalman-filter (EnKF) approach is used to estimate reservoir flow and material properties by jointly assimilating dynamic flow and geomechanics observations. The resulting model can be used for managing and optimizing production operations and for mitigating the land subsidence. The use of surface displacement observations improves the match to both production and displacement data. Localization is used to facilitate the assimilation of a large amount of data and to mitigate the effect of spurious correlations resulting from small ensembles. Because the stress, strain, and displacement fields are updated together with the material properties in the EnKF, the issue of consistency at the analysis step of the EnKF is investigated. A 3D problem with reservoir fluid-flow and mechanical parameters close to those of the Lost Hills oil field is used to test the applicability.

Electromagnetic traveltime tomography: Application for reservoir characterization in the Lost Hills oil field, California

Electromagnetic (EM) traveltime tomography has been applied for reservoir characterization at the Lost Hills oil field, California. Four data sets at frequencies of 24, 90, 370, and 1000 Hz were obtained along a pair of monitoring boreholes located 80.5 m apart. Traveltime information was first extracted from these EM data sets using a wavefield transform with a ray series approximation. The conductivity contrast of each layer is no greater than two in the region of interest, so the first arrivals can be estimated within 5% error by the approximate scheme. A nonlinear traveltime tomography algorithm adopting a Fresnel zone concept was then applied to obtain the conductivity model between the boreholes. The resultant conductivity image represents the conductivity structure between the boreholes. This image is consistent with the results of both a finite-difference inversion and the induction log obtained prior to waterflooding. Comparing the two conductivity images with the induction logs, we observe major differences in the fracture-dominant resistive reservoir layer, which may have been caused by changes in reservoir condition before and after waterflooding.

Tube‐wave suppression in single‐well seismic acquisition

Single‐well seismic imaging is significantly hampered by the presence of borehole tube waves. A tube‐wave suppressor has been tested using single‐well seismic equipment at the Lost Hills (California) oil field. The suppressor uses a gas‐filled bladder kept slightly above borehole fluid pressure. Field tests show a measurable reduction in tube‐wave energy as compared to body waves propagating in the surrounding reservoir rock. When using a high‐frequency (500–4000 Hz) piezoelectric source, the P‐wave–tube‐wave amplitude ratio was increased by 33 dB. When using a lower frequency (50–350 Hz) orbital vibrator source, the S‐wave–tube‐wave amplitude ratio was increased by 21 dB while the P‐wave–tube‐wave amplitude ratio was increased by 23 dB. These reductions in tube‐wave amplitudes significantly improve single‐well data quality.

Efficient Crosswell EM Tomography for Monitoring Geological Sequestration of CO2

ABSTRACT Carbon dioxide (CO2) sequestration in oil reservoirs can be one of the most effective strategies for long-term removal of greenhouse gas from atmosphere. This paper presents an advantage of the localized nonlinear approximation of integral equation solutions for inverting crosswell electromagnetic data, which are observed as a part of pilot project of CO2 flooding at the Lost Hills oil field in central California, U.S.A. To monitor the migration of CO2, we have used two-dimensional (2D) cylindrically symmetric and 2.5D tomographic inversion methods. These two schemes produce similar images if the borehole separation is large enough compared with the skin depth. However, since the borehole separation is much less than five skin depths in this CO2 injection experiment, the 2.5D model seems to be more reliable than the 2D model. In fact, the 2.5D image derived from pre-injection data is more successfully compared with induction logs observed in the two wells than the 2D image. From the time-lapse crosswell imaging, we can confirm that the replacement of brine with CO2 makes a decrease of conductivity.

米国カリフォルニア州ロストヒルズ油田で実施した，坑井間電磁および弾性波トモグラフィーによる貯留層モニタリングの試み

Reservoir monitoring is the key issue to design the optimum plan for recovery enhancements of hydrocarbon production. The Technology Research Center of Japan National Oil Corporation has conducted extensive field measurements to validate the current cross-hole technologies at the Lost Hills Oil Field, California in the first quarter of 2000. The experiments were composed of cross-hole electromagnetic surveys between fiberglass cased boreholes in both frequency domain and time domain methods together with seismic tomography. The time domain electromagnetic survey was designed to test the newly developed time domain down-hole transducer. However, the tool was broken down during the measurement. For the frequency domain electromagnetic method, we conducted three kinds of experiments, which are time lapse analysis with previously measured data, multi-frequency survey for higher resolution analysis, and measurement with setting up transducer in a steel cased hole. Multi-stage multi-disk borehole seismic source, which has been developed in collaboration between JNOC and OYO corporation was employed for seismic tomography.The subsurface velocity profile from seismic tomog raphy was utilized to calculate the formation porosity. Since the standard calculation procedure of sonic porosity is not adequate to apply for the diatomite reservoir because of its nature of high porosity despite very low permeability, a correction function was developed and employed. Then the resistivity profile was incorporated into estimation of fluid saturation in the reservoir by Archie's equation. The resultant values of porosity and water saturation are quite reasonable in comparison with reported ranges for this field.Assuming that the regional compaction being related to reduction of reservoir porosity has not been significant from 1997 to 2000 based on the ground subsidence in the area, we calculated a fluid saturation profile since the beginning of water flooding. We revealed the manners of fluid saturation change in the reservoir during water flooding through the time lapse analysis.

Integrating reservoir engineering and satellite remote sensing for (true) continuous time-lapse reservoir monitoring

The poem “The Blind Men and the Elephant” is based on an ancient Indian fable in which each man described rather differently what he sensed about an elephant. A similar situation can, and sometimes does, occur in reservoir description. Evidence shows that a reasonably thorough understanding of a reservoir is not very likely without viewing it from many angles and perspectives. This paper will show how two different perspectives of a reservoir—reservoir engineering and satellite remote sensing—can improve reservoir description and even allow (true) continuous time-lapse reservoir monitoring. The idea is simple. If subsidence occurs over an oil field, satellite remote sensing can detect the subsidence, and reservoir engineering can model the subsidence. By integrating reservoir engineering and satellite remote sensing, we can continuously monitor the hydrocarbon production. We use two examples, one from East Mesa Geothermal Field and one from Lost Hills Oil Field, to illustrate the idea. The principle of satellite synthetic aperture radar (SAR) is fairly straightforward. A microwave sensor, which can be on a spacecraft, passes a spot on the ground and takes a “shot” of it. After a certain period, the same sensor passes over the same spot and takes a second “shot” (Figure 1). By comparing the two shots with a reference elevation map, a detailed surface deformation map can be obtained for the period between the passes. Figure 1. Principles of SAR for measuring deformation (from http://www-star.stanford.edu/sar_group/). The image shows two passes of the same microwave sensor over the same location on earth. The difference between the two passes is determined by both earth topography and surface deformation. When data from a reference elevation map or a third pass is used for comparison, the topography effect can be eliminated. What remains is solely surface deformation. SAR can measure surface deformation at very high resolution (a …

Image appraisal for 2-D and 3-D electromagnetic inversion

Linearized methods are presented for appraising resolution and parameter accuracy in images generated with 2-D and 3-D nonlinear electromagnetic (EM) inversion schemes. When direct matrix inversion is used, the model resolution and a posteriori model covariance matrices can be calculated readily. By analyzing individual columns of the model resolution matrix, the spatial variation of the resolution in the horizontal and vertical directions can be estimated empirically. Plotting the diagonal of the model covariance matrix provides an estimate of how errors in the inversion process, such as data noise and incorrect a priori assumptions, map into parameter error and thus provides valuable information about the uniqueness of the resulting image. Methods are also derived for image appraisal when the iterative conjugate gradient technique is applied to solve the inverse. An iterative statistical method yields accurate estimates of the model covariance matrix as long as enough iterations are used. Although determining the entire model resolution matrix in a similar manner is computationally prohibitive, individual columns of this matrix can be determined. Thus, the spatial variation in image resolution can be determined by calculating the columns of this matrix for key points in the image domain and then interpolating between. Examples of the image analysis techniques are provided on 2-D and 3-D synthetic cross‐well EM data sets as well as a field data set collected at Lost Hills oil field in central California.

The Structure and Production of a New Fault Block Discovery, Fractured Monterey Shale Zone, Northwest Lost Hills Oil Field, Kern County, California

The Structure and Production of a New Fault Block Discovery, Fractured Monterey Shale Zone, Northwest Lost Hills Oil Field, Kern County, California

Abstract: An Investigation of Subsurface Fracture Distribution in the Monterey Formation, Lost Hills Oil Field, CA using Borehole Image Logs and Whole Core 

Abstract: An Investigation of Subsurface Fracture Distribution in the Monterey Formation, Lost Hills Oil Field, CA using Borehole Image Logs and Whole Core 

Shear-wave polarizations and subsurface stress directions at Lost Hills field : Winterstein, D F; Meadows, M A GeophysicsV56, N9, Sept 1991, P1331–1348

Two closely spaced nine-component VSPs recorded in the Lost Hills oil field in the southern San Joaquin Valley of California show that the polarization of the fast shear (S) wave is aligned with the direction of maximum horizontal compressive stress as determined from analysis of tiltmeter data. Tiltmeters monitored fractures that were hydraulically induced in or near the VSP wells. When fractures were induced in one of the VSP wells, fracture azimuths as determined from tiltmeter data were N53{degree}E and N56{degree}E, respectively, in two different depth zones; in the same zones the fast S-wave polarization directions were N58{degree}E and N59{degree}E. When fractures were induced in a well 537 ft from the second VSP well, tiltmeter data indicated a mean fracture strike of N59{degree}E, while the fast S-wave polarization direction in that case was N40{degree}E. S-wave polarization directions were determined by minimizing energy on off-diagonal components of the 2 {times} 2 S-wave data matrix, accomplished by computationally rotating sources and receivers by the same angle. S-wave polarizations from two concentric rings of offset VSPs were consistent in azimuth with one another and with polarizations of the near offset VSP. This consistency argues strongly for the robustness of the S-wave polarization techniquemore » as applied in this area. The S-wave polarization pattern in offset data fits a model of vertical cracks at N55{degree}E in a weakly transversely isotropic matrix with infinite-fold symmetry axis tilted at 10{degree} from the vertical toward N70{degree}E.« less

Shear-Wave Polarizations and Subsurface Stress Directions at Lost Hills Field

Two closely spaced nine-component VSPs recorded in the Lost Hills oil field in the southern San Joaquin Valley of California show that the polarization of the fast shear (S) wave is aligned with the direction of maximum horizontal compressive stress as determined from analysis of tiltmeter data. Tiltmeters monitored fractures that were hydraulically induced in or near the VSP wells. When fractures were induced in one of the VSP wells, fracture azimuths as determined from tiltmeter data were N53{degree}E and N56{degree}E, respectively, in two different depth zones; in the same zones the fast S-wave polarization directions were N58{degree}E and N59{degree}E. When fractures were induced in a well 537 ft from the second VSP well, tiltmeter data indicated a mean fracture strike of N59{degree}E, while the fast S-wave polarization direction in that case was N40{degree}E. S-wave polarization directions were determined by minimizing energy on off-diagonal components of the 2 {times} 2 S-wave data matrix, accomplished by computationally rotating sources and receivers by the same angle. S-wave polarizations from two concentric rings of offset VSPs were consistent in azimuth with one another and with polarizations of the near offset VSP. This consistency argues strongly for the robustness of the S-wave polarization techniquemore » as applied in this area. The S-wave polarization pattern in offset data fits a model of vertical cracks at N55{degree}E in a weakly transversely isotropic matrix with infinite-fold symmetry axis tilted at 10{degree} from the vertical toward N70{degree}E.« less

Petrophysical Evaluation of the Diatomite Formation of the Lost Hills Field, California

Renewed interest in the vast oil reserves of the Lost Hills field led to the evaluation of the petrophysical properties obtained from logs and cores. A method known as pattern recognition was used to gain insight into the properties of the diatomite beds, which are unlike those of most other formations. Introduction The Lost Hills oil field in California contains several producing horizons. The Etchegoin formation of the producing horizons. The Etchegoin formation of the Pliocene series consists of soft, massive diatomite beds of Pliocene series consists of soft, massive diatomite beds of very high porosity and exceptionally low permeability. In many ways, the matrix resembles a chalk formation. The depth of the Main Zone ranges from about 900 to 1,900 ft. The wells are usually completed with slotted liners across 600 to 1,000 ft, of which the net productive thickness is about 500 ft. All the more permeable beds within the Main Zone appear to be depleted and show signs of gas saturation, particularly in the structurally higher locations. Reservoir particularly in the structurally higher locations. Reservoir pressure varies from about 400 psi in tight beds to nearly pressure varies from about 400 psi in tight beds to nearly atmospheric in the more permeable beds. Oil is contained in diatomaceous earth that is mixed with very fine sand and clay at variable ratios. Most of the Main Zone has a permeability on the order of only a few millidarcies, despite a reservoir porosity that frequently exceeds 40 percent. There seems to be a relationship between the purity of the diatomite and its porosity and permeability - the cleaner the diatomite, porosity and permeability - the cleaner the diatomite, the higher the porosity and the lower the permeability. A number of wells were recently drilled in a test area in Lost Hills. The suite of logs run in five of the wells included the dual-induction laterolog with SP and the density-compensated neutron log combined with gamma ray and caliper. A type log is shown in Fig. 1. One well was cored through a zone of interest. The objective of the logging program was fluid-saturation determination, with emphasis on the detection of possible gas saturation that was considered deleterious to the outcome of a pilot test. The information collected from these and a few other wells and cores obtained several years earlier permitted some observations about the unusual nature of this reservoir. Standard laboratory core analysis with petrographic, X-ray, optical microscope, and scanning petrographic, X-ray, optical microscope, and scanning electron microscope examinations was compared with results obtained from log analysis using the "pattern recognition" approach. Diatomaceous Earth and Its Properties A diatomaceous deposit is a hydrous, noncrystalline form of silica or opal composed of microscopic shells of diatoms, which are microscopic, single-celled, aquatic plankton plants. It is light-colored and resembles chalk, plankton plants. It is light-colored and resembles chalk, but is much less dense and will not effervesce in acid as chalk does. The diatom forms can be distinguished under a high-power microscope. Thousands of varieties are known. Their skeletons accumulate at the bottom of marine environments. The empty shells are practically imperishable, and they accumulate to form very thick beds of "diatomite ooze." Ref. 4 gives a good description of the structure and the incredible variety of forms of the diatoms. It appears that, as small as the diatoms are, they contain some internal porosity detectable by a porosity device such as a density, sonic, or neutron log. JPT P. 1138