Lost Hills 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.

Characterization of five unconventional diatomaceous (opal-A) reservoirs, Monterey Formation, San Joaquin Valley, California

Unconventional opal-A and opal-CT diatomaceous reservoirs in the Monterey Formation of the San Joaquin Valley in California have produced for more than 30 yr. These opal-A reservoirs are characterized by high porosity (>50%) and low permeability ( 45% [Cymric and McKittrick fields]) or are very thick (>1000 ft thick [Lost Hills field]). These insights provide general guidance about characterization of unconventional diatomaceous reservoirs and the identification of factors that most dramatically influence performance.

Machine Learning Overcomes Challenges of Selecting Locations for Infill Wells

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190101, “Infill-Well Location-Selection Procedures in Lost Hills Using Machine Learning,” by T.H. Kim, SPE, D.J. Crane, and E.F. Grijalva, SPE, Chevron, prepared for the 2018 SPE Western Regional Meeting, Garden Grove, California, USA, 22–27 April. The paper has not been peer reviewed. For most conventional reservoirs, numerical simulation is successful in forecasting and extracting valuable information regarding optimal locations for new wells. The results of numerical simulations for the Lost Hills field, however, were not successful because of the special characteristics of its diatomite reservoirs—low permeability but high porosity, weak rock strength, and strong imbibition. Machine learning (ML) has been considered because it does not require specific physical models but can provide good estimations with enough data. Introduction The Lost Hills field is approximately 45 miles northwest of Bakersfield, California, USA. It was discovered in 1910, and hydraulic fracturing was introduced in the late 1970s. Waterflooding was introduced in 1992 and has become the main production method. The main reservoir rock type is diatomite, which is formed by the accumulation of diatoms, single-cell organisms. The aver-age pay thickness is approximately 800 to 1,000 ft, and depth to the reservoir base is approximately 2,000 ft. The estimated original oil in place is more than 2 billion bbl. ML Algorithms and Voronoi Diagram K-Means Clustering. K-means clustering is one type of unsupervised learning algorithm. As opposed to supervised algorithms, unsupervised learning algorithms do not need answers supplied. K-means clustering algorithms identify the members of each cluster by iterating the following steps: Generate the centroid of each of the clusters randomly. The number of clusters, K, is a user input. Each data point is assigned to its nearest centroid so that K clusters are created. The new centroid of each cluster is updated so that the Euclidian distances to the centroid are minimized. Repeat Steps 2 and 3 until convergence has been reached. Support Vector Machine (SVM). SVM is a supervised ML algorithm. For supervised learning algorithms, the answers must be supplied to train and build a predictive model. SVM has two main applications, classification and regression, and classification is used in this study. SVM builds a hyperplane or set of hyperplanes that separate data into groups (classification) or form a regression line; a hyperplane is a subspace of one dimension less than its ambient space (e.g., a plane in 3D space). Fig. 1 shows an example of classification in 2D space. The red line is a hyperplane set to have the maximum gap between two classes. Data vectors in circles are borderline members and are called support vectors. When building a hyperplane is difficult, data are mapped into a higher-dimensional space to facilitate finding a hyperplane.

Horizontal-Well Fracturing by Use of Coiled Tubing in the Belridge Diatomite: A Case History

Summary Coiled-tubing (CT) fracturing has been applied successfully in multistage vertical-well stimulation in the Belridge diatomite in the Lost Hills field. This same methodology was used to complete two northwest-trending horizontal wells drilled on the northeast flank of the Lost Hills anticlinal structure that targeted thinner, higher-oil-saturation strata separated by thicker lower-oil-saturation intervals. The target reservoir presents high-porosity, low-matrix-permeability, and low-Young's-modulus Opal A diatomite. The perforations were jetted by pumping sand slurry down the CT, and the fracture job was pumped down the annulus. The stages were isolated by setting sand plugs. Nine and twelve stages were pumped in the two wells, respectively. The perforation locations for different stages were selected in areas with high resistivity and inferred high oil saturations, an absence of hydraulic fractures from nearby wells, excellent cement bonding, and low intensity of natural fractures. These assessments followed logging-while-drilling (LWD) with gamma ray, induction-resistivity and azimuthally focused resistivity (AFR) (image) logs, and a cased-hole ultrasonic image tool (USIT) run with the aid of a tractor. The hydraulic fractures were monitored by use of surface tiltmeter sensors. Oil- and water-soluble tracers were pumped to determine the relative production contribution from the stages and fracture-fluid cleanup, respectively, from the stages. All the jobs could be pumped successfully without any screenouts. Challenges were faced in setting sand plugs and isolating stages. Large fracture widths and low leakoff into the formation led to difficulty in forming sand bridges at the perforations and concentrating sand in the wellbore for the plugs. Surface tiltmeters showed excessive fracture-height growth. Tracer results showed that 20 to 30% of the stages contributed to 50 to 60% of the production. Stages with higher treating pressures contributed less toward production. This could be attributed to near-wellbore tortuosity in these stages. Proppant flowback was encountered in one well, and after an effective cleanup, the production rose. The study illustrates how integration of various aspects, such as completion design, fracture-pressure analysis, and diagnostics, combined with geologic and reservoir information can help in identifying challenges and finding potential solutions for hydraulic fracturing. The findings highlight that the technology most suitable for vertical-well stimulation might not be favorable for horizontal-well stimulation.

Design and Life-Cycle Considerations for Unconventional-Reservoir Wells

Summary This paper provides an overview of design and life-cycle considerations for certain unconventional-reservoir wells. An overview of unconventional-reservoir definitions is provided. Well design and life-cycle considerations are addressed from three aspects: upfront reservoir development, initial well completion, and welllife and long-term considerations. Upfront-reservoir-development issues discussed include well spacing, well orientation, reservoir stress orientations, and tubular metallurgy. Initial-well-completion issues include maximum treatment pressures and rates, treatment diversion, treatment staging, flowback and cleanup, and dewatering needs. Well-life and longterm discussions include liquid loading, corrosion, refracturing and associated fracture reorientation, and the cost of abandonment. These design considerations are evaluated with case studies for five unconventional-reservoir types: shale gas (Barnett shale), tight gas (Jonah feld), tight oil (Bakken play), coalbed methane (CBM) (San Juan basin), and tight heavy oil (Lost Hills field). In evaluating the life cycle and design of unconventional-reservoir wells, "one size" does not fit all and valuable knowledge and a shortening of the learning curve can be achieved for new developments by studying similar, more-mature fields.

Extreme Multistage Fracturing Improves Vertical Coverage and Well Performance in the Lost Hills Field

Summary In an attempt to improve production response, fracturing designs in the Lost Hills field went from a standard three-to six-stage design to an extreme 15-to 18-stage design to stimulate approximately 1,000 ft of net pay. The previous standard designs were becoming borderline economic, and if development was to continue, then either production response had to improve or costs had to be reduced. Previous emphasis was placed on reducing fracture-treatment costs by pumping fewer stages and lower proppant volumes, but the cumulative production response decreased as a result. Previous tests using an increased number of fracture stages did not improve economics because of the increased fracturing costs and minimal production increases. When a new coiled-tubing fracturing technique was implemented to perform multistage jobs at reduced costs and the stage count per well was increased, production response and economics improved. This paper will discuss the differences in job execution, analysis of vertical fracture coverage using surface and downhole tiltmeter data, and cumulative production response from the different designs tested. Both treatment and stage design with this fracturing technique are being refined further as the performance and statistical analysis of previous design changes are completed.

Combination of well log and pore-scale data to predict petrophysical properties of diatomite

A fast and accurate method for distribution of multiphase flow functions across the productive interval of a reservoir volume is proposed. When coupled with artificial neural networks (ANN) to correlate pore-type data (pore size, shape, and roughness) with well log measurements, network modeling is useful to generate relative permeability and capillary pressure functions on the same spatial scale as log data. The technique combines measurements with inherently different length scales and is multiscale in this sense. A proof-of-concept exercise is reported using data from the Lost Hills field (Kern Co., CA, USA). Sensitivity of the predictions resulting from modern and “vintage” (late 1970's) logging suites is discussed as are the various quality control measures employed. It is observed that either gamma-ray or spontaneous-potential logs must be used for accuracy. A mapping of a pore-type attributes along a 10,000 ft south–north vertical transect reveals that the relative proportion of an individual pore type changes significantly within the field. Relative permeability and capillary pressure curves, as well as residual oil saturation, obtained from pore network runs agreed well with the range of published values. Nevertheless, significant variation within diatomite types is noted. A practical application of the method is to guide selection of reservoir zones with greater rock quality and/or remaining oil saturation when identifying candidate locations for infill drilling.

Invariance, groups, and non-uniqueness: The discrete case

Summary Lie group methods provide a valuable tool for examining invariance and non-uniqueness associated with geophysical inverse problems. The techniques are particularly well suited for the study of non-linear inverse problems. Using the infinitesimal generators of the group it is possible to move within the null space in an iterative fashion. The key computational step in determining the symmetry groups associated with an inverse problem is the singular value decomposition of a sparse matrix. I apply the methodology to the eikonal equation and examine the possible solutions associated with a crosswell tomographic experiment. Results from a synthetic test indicate that it is possible to vary the velocity model significantly and still fit the reference arrival times. The approach is also applied to data from crosswell surveys conducted before and after a CO2 injection at the Lost Hills field in California. The results highlight the fact that a fault cross-cutting the region between the wells may act as a conduit for the flow of water and CO2.

Field Surveillance and Well-Services Management in a Large Mature Onshore Field

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 99949, "Real-Time Field Surveillance and Well-Services Management in a Large Mature Onshore Field: Case Study," by L. Ormerod, SPE, Weatherford; H. Sardoff, SPE, J. Wilkinson, SPE, and B. Erlendson, Chevron; and B. Cox and G. Stephenson, SPE, Weatherford, prepared for the 2006 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 11–13 April. A real-time field-surveillance and well-services management system was deployed in an onshore mature field in California. The challenges of data management included automatic handling of very large quantities of real-time data, management of inventory, and integration of field-level data with corporate-level data. Technologies required for this project included software systems and integration of these with remote intelligent-field sensors and data-transmission systems. This project established that integrated intelligent remote devices, communications networks, and workflow-management software could be deployed successfully on large mature fields. Prior State of the Business Chevron's San Joaquin Valley Business Unit (SJVBU) is in the southern San Joaquin Valley in central California. The SJVBU operations encompass assets in seven oil fields, which before the merger of Chevron and Texaco were operated by those two companies. The earliest of these oil fields was developed in the early 1900s. Most of the development occurred in the 1960s and 1970s with the implementation of steamflood technology. Aggregate production from the SJVBU assets is approximately 200,000 BOPD. Approximately 15,000 active wells produce in the SJVBU, yielding an average production of approximately 13 BOPD/well. The SJVBU fields produce from relatively shallow reservoirs, including the Miocene/Pliocene Kern River, Tulare, Temblor, and Potter formations, which typically have porosities ranging from 20 to 30% and permeability in the range of 1 to 5 md. Oil gravity ranges from 13 to 20°API, and viscosity is approximately 50 cp. Reservoir depth of approximately 1,000 ft enables extremely rapid drilling. Oil-production revenue is more than 95% of total sales, and virtually all wells use sucker-rod pumps (SRPs). The key operational focus of these fields concerns the challenge of maintaining this very large number of wells at optimum production. An online system for well surveillance and well-services management was installed in the SJVBU, and the experience of implementing this system was used in the Cymric field. Cymric is typical of the SJVBU fields and contains approximately 800 SRP wells producing 16,000 BOPD. Cymric has another 500 huff ‘n’ puff cyclic-steam wells that flow after the steam cycle, adding another 24,000 BOPD, for a total field production of 40,000 BOPD. Automation History In the 1980s, a program to increase production in the Lost Hills field was based on finding the best method to fracture the wells. Field production rose from less than 3,000 BOPD to more than 20,000 BOPD. Managing this new production became a priority, and pump-off controllers (POCs) were installed throughout the field similar to that shown in Fig. 1.

3D waterflood monitoring at Lost Hills with crosshole EM

Producing oil and gas at the Lost Hills Field in central California has always been a challenge. Although the reserves are significant, production is hampered by low matrix permeability and unusual mechanical properties in the diatomite (marine mudstone/siltstone) reservoir. Since 1911 operators have struggled with methods to improve production, control local subsidence and well failure, and improve recovery that presently is projected to be less than 10%.

Seismic imaging of reservoir flow properties: Time‐lapse pressure changes

Time‐lapse fluid pressure and saturation estimates are sensitive to reservoir flow properties such as permeability. In fact, given time‐lapse estimates of pressure and saturation changes, one may define a linear partial differential equation for permeability variations within the reservoir. The resulting linear inverse problem can be solved quite efficiently using sparse matrix techniques. An application to a set of crosswell saturation and pressure estimates from a CO2 flood at the Lost Hills field in California demonstrates the utility of this approach. The pressure and saturation estimates are mapped into reservoir permeability variations between the boreholes. The resulting permeability estimates agree with a permeability log in an adjacent well and are in accordance with water and CO2 saturation changes imaged in the interwell region.

ABSTRACT: Sequence Stratigraphic and Diagenetic Controls on Trap Development of a Miocene Diatomite-Sandstone Reservoir, Lost Hills Field, San Joaquin Basin, California

ABSTRACT: Sequence Stratigraphic and Diagenetic Controls on Trap Development of a Miocene Diatomite-Sandstone Reservoir, Lost Hills Field, San Joaquin Basin, California

Linking oil production to surface subsidence from satellite radar interferometry

Land subsidence over the Belridge and Lost Hills oil fields, Southern California, was measured using spaceborne interferometric synthetic aperture radar (InSAR). During the 105‐day period between 11/5/95 and 2/17/96, the subsidence in the center of the Lost Hills field reached 15 cm. We assume that this surface subsidence resulted from the vertical shrinkage of the reservoir, which in turn was due to oil production and the resulting pore pressure drop. We model this mechanical effect using an elastic deformation theoretical solution with input constants taken from relevant experiments. The modeled surface deformation matches the InSAR measured values. This result indicates that it is possible, in principle, to monitor hydrocarbon production using satellite‐based measurements of earth deformation.

Antelope shale (Monterey Formation), Buena Vista Hills field: Advanced reservoir characterization to evaluate CO2 injection for enhanced oil recovery

Very large volumes of oil in developed siliceous shale reservoirs of the southern San Joaquin basin, California, may be recoverable through carbon dioxide (CO2) flooding. More than 7 billion bbl of oil, trapped in the Miocene Monterey Formation, are present at relatively shallow depths in a series of large and giant fields discovered during the early part of the 20th century yet that have typical recoveries of less than 6%. Such low recoveries are due to the unique nature of the reservoir and to early completion practices. Siliceous shales consist mainly of biogenic silica (original diatom frustules) and varying amounts of clay and silt/sand. These rocks are thinly laminated and typified by high porosities (> 30%), very low permeabilities (< 1 md), extremely small pore throats, and variable degrees of fracturing. Early well completions, up through the 1950s, employed slotted liners and commingled production at high rates, thereby preventing interval evaluation and also causing rapid loss of reservoir pressure. To better understand these reservoirs, and to establish baseline criteria for evaluating CO2 flooding as an option for enhanced recovery, a multiyear study sponsored by the U.S. Department of Energy and Chevron U.S.A. was performed in Buena Vista Hills field, focused on the Antelope shale zone (upper Monterey Formation). A combination of advanced reservoir characterization, three-dimensional earth modeling, and flow simulation was performed. Resulting data provide essential new insight into the detailed nature of these reservoirs, for which mostly vintage (Begin page 562) log data (pre-1966) was previously available. Criteria established for CO2 flood evaluation include current oil saturation levels, reservoir pressure, lithologic heterogeneity, degree of fracturing, and well spacing. On the basis of these criteria, a site was chosen for a CO2 pilot test in Lost Hills field. This pilot is encompassed within the present Chevron-DOE study and will be covered in a future E & P Notes article.

Stress Magnitudes from Logs: Effects of Tectonic Strains and Temperature

Summary An improved method of calibrating in-situ stress logs was validated with data from two wells. Horizontal stress profiles are useful for hydraulic fracture design, wellbore stability analysis, and sand production prediction. The industry-standard method of estimating stresses from logs is based on overburden, Poisson's ratio, and pore pressure effects and gives an estimate of minimum horizontal stress. The model proposed here adds effects of temperature and tectonics and outputs of minimum and maximum horizontal stress magnitudes, which are particularly important to the successful completion of horizontal and deviated wells. This method was validated using data collected from a GRI research well and a Mobil well. Seven microfrac stress tests in GRI's Canyon Gas Sands Well of Sutton County, Texas, provided a means of comparing the predictive capability of different methods. First, one of the seven stress tests was selected as a calibration standard for the stress log. Then the results obtained from the two calibration methods were compared to stress magnitudes from the other six stress tests. This process was repeated using each of the seven stress tests as a calibration standard and comparing predictions to the other six. In every case, the method incorporating tectonic strain and thermal effects produced significantly more accurate values. The Mobil well is located in the Lost Hills Field in California, and pre-frac treatment breakdown tests were used to calibrate a log-derived stress profile. All of the data were used simultaneously to get a best fit for the log-derived stress. The log and its fracture height growth implications compared favorably with available fracture diagnostic data, and maximum horizontal stress values were consistent with published values for a similar, nearby reservoir.

Abstract: A Comprehensive Three Phase Reservoir Characterization in the BeIridge Diatomite in Lost Hills Field, California: Unique Log Calibration, Mineral Modeling in Complex Lithology, and Permeability Transform Development&amp;nbsp;

Abstract: A Comprehensive Three Phase Reservoir Characterization in the BeIridge Diatomite in Lost Hills Field, California: Unique Log Calibration, Mineral Modeling in Complex Lithology, and Permeability Transform Development&amp;nbsp;

Field Evaluation of a Multiphase Meter in Well-Testing Operation

Summary This paper describes the evaluation results on the measurement accuracy and long-term operation of a multiphase meter used for well testing. The test was conducted by Chevron at its Lost Hills field in California. After many years of development work, several multiphase meter manufacturers have begun to offer their meters commercially for production operation. In this paper, commercial multiphase meters are first briefly reviewed based on the methods that those meters use to handle the fluid flow. The multiphase meter selected for this application was manufactured by Accuflow Inc. It uses the compact separation approach in handling the oil/gas/water flowstream by first separating the gas from the liquid stream and then measuring the gas and oil/water separately. The Accuflow system was installed at a gauge station in January 1996. It was designed to test wells that have productions ranging approximately from 100 to 400 bbl of fluid per day, with a high water cut (40 to 90%), and up to 200 Mcf/D of gas. For accuracy testing, the multiphase meter was piped in series with a test separator at the gauge station. Production from selected wells, covering a wide range of flow rates, water cuts, and gas volume fractions, flowed through the multiphase meter first and then through the test separator, which enabled comparison of the new meter's performance and accuracy with an existing reference. Additional tests also were conducted to compare results with a test tank at the site. The paper also discusses other operational aspects of the multiphase meter such as equipment maintenance and sand accumulation. Overall, satisfactory performance of this multiphase meter was observed, and additional units have been installed at the Lost Hills field.

Extending Rod-Pump Life During Proppant Flowback at the Lost Hills Field

Summary Proppant flowback from hydraulically fractured wells can lead to sand wear on the pump barrel and plunger and to increased pulling costs on rod-pumped wells. Two separate approaches for lengthening the run times of the pumps were tried and evaluated individually. One approach was to install pumps that allow production of a sand-laden fluid. Pressure-actuated plunger (PAP) pumps were field tested, and they showed an average increase of 81.6% in run time. These split ring wiper pumps clean the barrel of sand before the passing of the plunger. The other approach was to keep the sand from entering the pumps. When downhole filters were used, the run life of the pumps with the filters increases 135%. Well-pulling cost savings of U.S. $11.91 per well day and U.S. $9.24 per well day are documented for the PAP pumps and filters, respectively. Application guidelines based on the sand-loading rate and gross liquid production of the wells are presented, as well as some operational experiences.

Abstracts: Development of Marginal Fractured Siliceous Shale Reservoirs with Horizontal Wells in Lost Hills Field, California&amp;nbsp;

Abstracts: Development of Marginal Fractured Siliceous Shale Reservoirs with Horizontal Wells in Lost Hills Field, California&amp;nbsp;