Belridge Diatomite Research Articles

Predicting and Applying Wellhead Temperatures for Steamflood-Field Operation and Production-Performance Monitoring

SummaryProducer-flowline temperatures (FLTs) can be measured automatically with a thermistor on an emergency-shutdown system (ESD), or manually on a specified spot on flowline with a handheld unit. Measured FLTs can usually be mapped to represent the formation-temperature distribution for steamflood reservoir management purposes (Hong 1994; Nath et al. 2007). In addition to FLT, wellhead temperature (WHT) is another surface temperature. Predicting the long-term WHT trend in steamflood operation is necessary for designing surface facilities for both oil dehydration/separation and produced-water recycling. This predicted temperature will also be applicable for production-performance monitoring.To predict the wellhead temperature, Hasan et al. (2009) derived a steady-state analytical solution for calculating WHT from bottomhole temperature (BHT) under flowing conditions of a multisection slant wellbore for the isothermal primary-depletion process, with both WHT and BHT being time independent for a given gross rate (Igec et al. 2010). This steady-state analytical solution has been extended to calculate steamflood producer WHT from BHT (both are time dependent) by consecutively approximating the WHT and monthly average of FLT measurements to a steady-state solution. The monthly averaged FLTs are seasonally variable and higher in the summer months of July through September and lower in the winter months of December through February. Monthly averaged FLT measurements depend on an annual ambient-temperature cycle within the depth needed for reaching an undisturbed ground temperature (typically 30 to 50 ft) (Gwadera et al. 2017). WHT, if measured, should be comparable with FLT for their close typical distance of 5 to 10 ft. WHT prediction, however, is only process dependent and not seasonally variable because of the inability to describe seasonally undisturbed depth in the geothermal gradient. Therefore, WHT prediction can be validated with average summer-month FLT measurements when heat loss becomes minimal. BHTs in this analytical approach are predicted by the Lauwerier (1955) analytical model and improved by calibration with the available reservoir-simulation model or several years of FLT measurements for steamflood response time.The objective of this study is to develop an integrated production-monitoring approach using only the surface information, including WHT and FLT, oil/water-production rate, and injection-pressure/rate data, which can be applied to diagnose and optimize steamflood production performance. A field case study for the South Belridge Diatomite steamflood was investigated. WHT prediction is compared with FLT measurement for diagnosing and understanding the production performances, such as premature water or steam breakthrough, interference by the waterflood on the steamflood boundary producers, as well as the FLT variation related to the target rates for steam injection. This diagnostic analysis approach combined with the Buckley-Leverett theory-based displacement-efficiency analysis, and injection pressure and rate signal, will help to develop an improved understanding of the displacement detail and form a decision base to optimize the production performance.

Models of Thermal Enhanced Oil Recovery in Fractured Reservoirs

Summary Models for steam or hot-water injection into a fractured diatomite or shale reservoir are developed from existing analytic models of energy transport and countercurrent imbibition. Radial convective heat flow through a horizontal fracture system is modeled with conductive heat flow into the low-permeability matrix. The flow geometry approximates hot-fluid injection into a five-spot pattern. Recovery mechanisms accounted for in the models include capillary imbibition and thermal expansion. Temperature dependence of viscosity and interfacial tension (IFT) are included in the imbibition estimate. Laboratory data are needed to quantify the magnitude of the imbibition mechanism, which is usually the primary contributor to oil recovery. Reservoir properties representative of either the Belridge Diatomite or the Antelope Shale, two giant fractured oil reservoirs, are used for the model forecasts. Currently, however, only temperature-dependent imbibition data for diatomite reservoirs are available. The steamflood model has been partially validated against a large-scale project in the Belridge Diatomite. By use of public-domain information, a reasonable comparison was obtained between the model and the field project during a 4-year injection period. Comparison with conventional thermal simulation was also performed, and it indicated reasonable agreement with the steamflood analytical model. The models have been used to determine the key factors determining the success of thermal recovery in fractured, low-permeability reservoirs. Steam injection is shown to be superior to hot-water injection in heating the matrix. Key factors enhancing recovery include reduced fracture spacing, increased matrix permeability, and increased injection temperature. Model results indicate that steamflood recoveries of more than 40% of the original oil in place (OOIP) may be achieved by injection in diatomite containing light oil. Application to diatomites containing heavy oil also shows good performance. Successful application in diatomite reservoirs is forecast to be possible in the current low oil-price environment. Economic application in fractured shales, assuming similar imbibition behavior as in diatomites, would require a higher oil price because of the higher well costs and lower oil content relative to diatomite projects. Because of the significant volumes of remaining oil in place (OIP) in both the diatomite and shale reservoirs, the application of thermal enhanced oil recovery (EOR) to these resources represents the logical next step in steamflood development.

A Practical Approach to History Matching Premature Water Breakthrough in Waterflood Reservoir Simulation: Method and Case Studies in South Belridge Diatomite Waterflood

Summary Premature water breakthrough negatively affects waterfloods in low permeability, naturally fractured reservoirs such as the South Belridge Diatomite. Premature water breakthrough reduces the effectiveness of waterflooding by partially or entirely bypassing the reservoir matrix where most of the reservoir fluids are stored. Reservoir simulation is handicapped by the inability to accurately characterize the architecture of the natural and induced fractures that yield high conductivity flow paths between injectors and producers. Generally, reservoir simulation can only represent the effective fluid flow by ignoring the ineffective water production that bypasses the matrix. Detailed production performance analysis yields a practical approach to assist reservoir simulation in history matching the waterflood process under premature water breakthrough conditions. Basic reservoir and rock–fluid characterization parameters must be tuned by history match of primary production or before water injection related effects dominate fluid flow under waterflooding. The Y-function waterflood analytical method is used to diagnose premature water breakthrough on a well-to-well basis for the timing and duration. Effective water injection and production volumes are recalculated in reservoir simulation and used to achieve a history match that honors oil production, reservoir pressure level, and injection/production volume balance. A field-scale case study is presented to demonstrate the application and procedure of the proposed approach. The long-term waterflood prediction with the history match model has been validated by comparing with analytical method forecast as well as the up-to-date continuous waterflood field data (4.5 years after history match date in the last reservoir simulation project). The proposed practical approach makes reservoir simulation a meaningful predictive tool in waterflood reservoirs when premature water breakthrough is a significant issue.

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.

A New and Practical Oil-Characterization Method for Thermal Projects: Application to Belridge Diatomite Steamflood

Summary Most of the oil-characterization approaches for thermal recovery are designed for heavy oils at moderate temperatures, in which oil can be represented in very simplistic ways (such as “gas” and “oil”). However, when oil is exposed to very high steam temperatures (i.e., 550°F), and/or the oil is lighter than the classical range defined for heavy oils and is exposed to a wide spectrum of thermal effects, such as distillation of the lighter ends, the conventional methods of representing the interaction of steam and the in-situ fluids are not accurate. In many cases, we have to first evaluate the quality of the data, and then represent the average behavior with a single most likely fluid model per reservoir segment (plus other scenarios, as needed) to simulate the production performance. There is a need to develop a streamlined approach to bring such data into industrial simulators in a practical way. In this study, we have developed a fit-for-purpose approach to generate a consistent pressure/volume/temperature (PVT) model over the whole reservoir, reflecting both pressure and temperature changes through the entire oil accumulation. The model represents the oil viscosity for a wide spectrum of temperatures, from reservoir temperature to steam temperature (thermal-process range). A systematic lumping scheme enables conversion of the characterized PVT model for numerical simulators with the minimal number of pseudocomponents while still capturing the essence of thermal physics. To our knowledge, there is no systematic study of this nature available in the literature. We have tested this approach in the Belridge diatomite steamdrive project. The study confirmed that steamflood incremental oil production in a light-oil reservoir is sensitive to the component-lumping scheme because of distillation of the lighter ends. We also found that a five-component PVT model, representing the physics in “fit-for-purpose” dynamic simulation, best compromises between minimal number of components and physical description of the light-oil behavior.

Production-Performance Diagnostics Using Field-Production Data and Analytical Models: Method and Case Study for the Hydraulically Fractured South Belridge Diatomite

Summary Oil and water production data are regularly measured in oilfield operations and vary from well to well and change with time. Theoretical models are often used to establish the production expectation for different recovery processes. A performance surveillance understanding can be developed by comparing the field production data with the production expectation. This comparison generates quantitative or qualitative signals to determine whether the producer meets production expectations or the producer is underperforming and appropriate operational action is required to address the underperformance. The case study is for the South Belridge diatomite in California. This hydraulically fractured diatomite reservoir is currently under waterflood and steamflood. A methodology is proposed to establish the production expectation from historical production data. For primary depletion, the formation linear and bilinear flow models are applied to producers with vertical hydraulic fractures. For waterflood, an analytical method derived from the Buckley-Leverett displacement theory is used. Those analytical methods can predict production and provide surveillance signals for producers in the primary and waterflood recovery stages. For steamflood, a semiquantitative performance/surveillance criterion is proposed on the basis of understanding the mechanistic oil banking concept and reservoir simulation results for steamflood and waterflood. With those models representing expected production performance, an integrated flow regime diagram is proposed for production surveillance. A performance expectation can be developed for an individual producer. A significant overperformance relative to the expectation normally indicates changes in the recovery mechanism or improvement in sweep efficiency. A significant underperformance usually signifies an operational issue that requires correction to optimize the production performance. In the case study, the surveillance methodology for producers under primary depletion, waterflood, or steamflood is demonstrated by use of historical production data. In addition, water channeling between injectors and producers and its impact on production performance are discussed. On the basis of this surveillance methodology, some operational actions were proposed, and successful results are demonstrated. Examples of forecast for an individual producer in the primary depletion stage and field scale prediction in the waterflood stage are provided. Application indicates that the proposed methodology can serve as a convenient and practical tool for reservoir surveillance and operational optimization.

Large-Scale Three-Dimensional Geomechanical Modeling of Reservoirs: Examples from California and the Deepwater Gulf of Mexico

Cost-effective improvements in the technology needed to develop and manage reservoirs in challenging environments require an increase in our understanding of geomechanical behavior. The local stresses relevant to reservoir-scale processes are strongly affected by stratigraphic and structural features at that scale, and the relationship between hydrocarbon production and the mechanical behavior of the reservoir and/or overburden can be complicated and difficult to discern from field data directly. Numerical simulation provides a means to achieve critical insight into the behavior of complex geosystems and advance understanding of both the subsurface environment before drilling as well as the relationship between fluid flow and geomechanical behavior during production. This paper reviews our recent work aimed at utilizing large-scale geomechanical simulation as a reservoir management tool. We first describe the constitutive models developed specifically for two important classes of geomaterials that are implemented in the quasi-static largedeformation finite element code JAS3D that we use in our work. We then describe several field cases where we apply nonlinear finite element modeling to key problems in reservoir mechanics. The first field cases involve historical geomechanical simulations of primary and secondary recovery at the Belridge Diatomite and Lost Hills fields located in California's San Joaquin Valley. In this work, we apply nonlinear finite element modeling to investigate the causes of well casing damage experienced by the field operators and to identify mitigation strategies. Next, we describe an application that addresses potential well integrity issues associated with sub-salt and near-salt deepwater Gulf of Mexico reservoirs. In this work, we analyze hole closure behavior and quantify loading on casings for wells that penetrate thick salt formations to ensure that wells are designed to withstand salt loading over a service lifetime of 20-30 years. The field studies illustrate the difficult issues encountered in practical applications of large-scale three-dimensional nonlinear finite element geomechanical modeling and suggest areas where research advances could be beneficial. These areas include: development of solids models and finite element meshes from disparate geologic and/or numerical data, development of realistic constitutive models, robust and efficient implementation of these material models in finite element codes to achieve reasonable solution times, experimental rock mechanics data and the natural heterogeneity of geosystems, implementation of far-field (tectonic) stresses and stress initialization, and integration of geomechanical modeling results with other analysis tools.

Geomechanical Modeling of Reservoir Compaction, Surface Subsidence, and Casing Damage at the Belridge Diatomite Field

Summary Geologic, and historical well failure, production, and injection data were analyzed to guide development of three-dimensional geomechanical models of the Belridge diatomite field, California. The central premise of the numerical simulations is that spatial gradients in pore pressure induced by production and injection in a low permeability reservoir may perturb the local stresses and cause subsurface deformation sufficient to result in well failure. Time-dependent reservoir pressure fields that were calculated from three-dimensional black oil reservoir simulations were coupled unidirectionally to three-dimensional nonlinear finite element geomechanical simulations. The reservoir models included nearly 100,000 gridblocks (100 to 200 wells), and covered nearly 20 years of production and injection. The geomechanical models were meshed from structure maps and contained more than 300,000 nodal points. Shear strain localization along weak bedding planes that causes casing doglegs in the field was accommodated in the model by contact surfaces located immediately above the reservoir and at two locations in the overburden. The geomechanical simulations are validated by comparison of the predicted surface subsidence with field measurements, and by comparison of predicted deformation with observed casing damage. Additionally, simulations performed for two independently developed areas at South Belridge, Secs. 33 and 29, corroborate their different well failure histories. The simulations suggest the three types of casing damage observed, and show that, although water injection has mitigated surface subsidence, it can, under some circumstances, increase the lateral gradients in effective stress that in turn can accelerate subsurface horizontal motions. Geomechanical simulation is an important reservoir management tool that can be used to identify optimal operating policies to mitigate casing damage for existing field developments, and applied to incorporate the effect of well failure potential in economic analyses of alternative infilling and development options.

Case History of Reservoir Subsidence and Wellbore Damage Management in the South Belridge Diatomite Field

Summary Production of fluids from the shallow, thick, and low-strength Diatomite reservoir in the South Belridge Field has resulted in reservoir compaction, surface subsidence, and numerous well failures. The most severe subsidence problems occurred while the field was under primary recovery, prior to implementation of waterfloods for pressure support. Consequently, a significant number of wells in the field have incurred casing damage, which proportionately limits the utility of these wellbores for continued production and routine wellwork operations. The nature of casing damage varies significantly depending on the location in the field, however casing shear ("kinks") generally produces the most severe problems in retaining full wellbore utility since it limits tool passage (e.g., packers, scrapers, etc. ) and is not economical to repair using conventional milling tools. Since the mid-1980s, surveillance has been in place to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction, and wellbore damage in Exxon's operations of Section 19 in the South Belridge Field. The surveillance includes the use of ground elevation markers and a variety of production logs—several of which involve novel application and log interpretation. These data subsequently were used to develop and verify hybrid geomechanics and wellbore geometric models for assessing casing damage, identifying well operability and wellbore utility limits, and forecasting the remaining wellbore life from which a reservoir management plan and wellbore management operational strategies were established. A key ingredient in the implementation of this plan and operational strategies involved a cooperative tool development with a major oil tool service company to repair casing kinked wellbores as an alternative to re-drilling wells. In this article we provide a case history that describes the various synergistic reservoir and wellbore management activities designed to effectively mitigate subsidence-induced operational problems and the accompanying field benefits resulting from their implementation.

Lossy transmission line model of hydrofractured well dynamics

The real-time detection of hydrofracture growth is crucial to the successful operation of water, CO 2 or steam injection wells in low-permeability reservoirs and to the prevention of subsidence and well failure. In this paper, we describe propagation of very low frequency (1–10 to 100 Hz) Stoneley waves in a fluid-filled wellbore and their interactions with the fundamental wave mode in a vertical hydrofracture. We demonstrate that Stoneley-wave loses energy to the fracture and the energy transfer from the wellbore to the fracture opening is most efficient in soft rocks. We conclude that placing the wave source and receivers beneath the injection packer provides the most efficient means of hydrofracture monitoring. We then present the lossy transmission line model of wellbore and fracture for the detection and characterization of fracture state and volume. We show that this model captures the wellbore and fracture geometry, the physical properties of injected fluid and the wellbore-fracture system dynamics. The model is then compared with experimentally measured well responses. The simulated responses are in good agreement with published experimental data from several water injection wells with depths ranging from 1000 ft to 9000 ft. Hence, we conclude that the transmission line model of water injectors adequately captures wellbore and fracture dynamics. Using an extensive data set for the South Belridge Diatomite waterfloods, we demonstrate that even for very shallow wells the fracture size and state can be adequately recognized at wellhead. Finally, we simulate the effects of hydrofracture extension on the transient response to a pulse signal generated at wellhead. We show that hydrofracture extensions can indeed be detected by monitoring the wellhead pressure at sufficiently low frequencies.

Evaluation of Rock/Fracture Interaction: During Steam Injection Through Vertical Hydraulic Fractures

Summary The design, results, and analysis of a steamdrive pilot in the South Belridge diatomite, Kern County, California, are reviewed. Pilot results demonstrate that steam can be injected across a 1,000-ft-tall diatomite column using hydraulically fractured wells and that significant oil is produced in response to steaming. A computationally simple numerical model is proposed and used to analyze reservoir heating and volumetric sweep by steam. Results from the analysis show that hydraulic fractures undergoing steam injection can be dynamic and asymmetrical.

Land subsidence and well failure in the Belridge Diatomite Oil Field, Kern County, California. Part I. Experiments, model and verification : E. De Rouffignac & P. L. Bondor, in: Land subsidence. Proc. international symposium, The Hague, 1995, ed F.B.J. Barends & others, (IAHS; Publication, 234), 1995, pp 61–68

Land subsidence and well failure in the Belridge Diatomite Oil Field, Kern County, California. Part I. Experiments, model and verification : E. De Rouffignac & P. L. Bondor, in: Land subsidence. Proc. international symposium, The Hague, 1995, ed F.B.J. Barends & others, (IAHS; Publication, 234), 1995, pp 61–68

Land subsidence and well failure in the Belridge diatomite oil field, Kern County, California. Part II. Applications : P. L. Bondor & E. De Rouffinac, in: Land subsidence. Proc. international symposium, The Hague, 1995, ed F.B.J. Barends & others, (IAHS; Publication, 234), 1995, pp187–195

Land subsidence and well failure in the Belridge diatomite oil field, Kern County, California. Part II. Applications : P. L. Bondor & E. De Rouffinac, in: Land subsidence. Proc. international symposium, The Hague, 1995, ed F.B.J. Barends & others, (IAHS; Publication, 234), 1995, pp187–195

Passive Imaging of Hydrofractures in the South Belridge Diatomite

Summary We present the results of a seismic analysis of two hydrofractures spanning the entire diatomite column (1110-1910 ft or 338-582 m) in Shell's Phase II steamdrive pilot in South Belridge, California. These hydrofractures were induced at two depths (1110-1460 and 1560-1910 ft) and imaged passively using the seismic energy released during fracturing. The arrivals of shear waves from the cracking rock ("microseismic events") were recorded at a 1 ms sampling rate by 56 geophones in three remote observation wells, resulting in 10GB of raw data. These arrival times were then inverted for the event locations, from which the hydrofracture geometry was inferred. A five-dimensional conjugate-gradient algorithm with a depth-dependent, but otherwise constant shear wave velocity model (CVM) was developed for the inversions. To validate CVM, we created a layered shear wave velocity model of the formation and used it to calculate synthetic arrival times from known locations chosen at various depths along the estimated fracture plane. These arrival times were then inverted with CVM and the calculated locations compared with the known ones, quantifying the systematic error associated with the assumption of constant shear wave velocity. We also performed Monte Carlo sensitivity analyses on the synthetic arrival times to account for all other random errors that exist in field data. After determining the limitations of the inversion algorithm, we hand-picked the shear wave arrival times for both hydrofractures and inverted them with CVM. Finally, to correct for the areal inhomogeneity of the rock, we calculated the distortion of conical waves that were generated by air gun blasts in a remote observation well. This novel technique improved significantly the accuracy of the event locations in the shallow hydrofracture. The azimuth of both hydrofractures was N21° ±4°E. In each treatment well, there were two separate hydrofractures at two different depths that correspond to the diatomite layers with higher permeabilities. Both shallow hydrofractures were asymmetrical. Initially, the upper NE wing was 230 ft long, whereas the lower SW wing was only 30 ft long. The deep hydrofracture was symmetrical and the wings of its two parts were initially 130 and 10 ft long, respectively. These conclusions agree well with temperature surveys in the surrounding observation wells during steam injection.

Surface Geology of the Northern Midway-Sunset Field and Adjacent Temblor Range, Kern County, California: ABSTRACT

New surface mapping at a 1:12000 scale adjacent to the 2 billion barrel Midway Sunset Field has revealed complex intraformational stratigraphy within the upper Miocene Santa Margarita Formation (Tms). Locally known as the Potter and Spellacy Formations in the subsurface, these sandstone and conglomerate heavy oil reservoirs produce the majority of Midway Sunset daily production of 164,000 barrels of oil via thermal EOR processes. The Tms consists mostly of conglomerate inserted into the Belridge Diatomite (Tmb) interval. The stratigraphically lower intervals of the Tms clearly fill deeply incised valleys or submarine canyons cut into Tmb and locally into the underlying Antelope Shale (Tma). The basal intervals of Tms; are very coarse grained, containing boulders of granitic and metamorphic rock as large as 4 meters that were derived from the Salinian block west of the San Andreas Fault. The upper intervals of Tms are more sheet-like and interbedded containing clasts less than 50 cm in length. The incised valleys have a spacing of about one mile in outcrop, with a gap located in the area of the older Republic Sandstone (Tmr). Paleocurrents from Tms regionally suggest sediment transport to the northeast. The sedimentary structures of Tms suggest deposition in deep-water conditions,more » probably a slope (bathyal) setting. Shelf environments should have been present to the southwest (now stripped away by erosion) and submarine-fan and basin-floor environments to the northeast.« less

Oil Gravity Distribution in the Diatomite at South Belridge Field, Kern County, CA: Implications for Oil Sourcing and Migration: ABSTRACT

Understanding oil gravity distribution in the Belridge Diatomite has led to economic infill development and specific enhanced recovery methods for targeted oil properties. To date more than 100 wells have provided samples used to determining vertical and areal distribution of oil gravity in the field. Detailed geochemical analyses were also conducted on many of the oil samples to establish different oil types, relative maturities, and to identify transformed oils. The geochemical analysis also helped identify source rock expulsion temperatures and depositional environments. The data suggests that the Belridge diatomite has been charged by a single hydrocarbon source rock type and was generated over a relatively wide range of temperatures. Map and statistical data support two distinct oil segregation processes occurring post expulsion. Normal gravity segregation within depositional cycles of diatomite have caused lightest oils to migrate to the crests of individual cycle structures. Some data suggests a loss of the light end oils in the uppermost cycles to the Tulare Formation above, or through early biodegradation. Structural rotation post early oil expulsion has also left older, heavier oils concentrated on the east flank of the structure. With the addition of other samples from the south central San Joaquin area, wemore » have been able to tie the Belridge diatomite hydrocarbon charge into a regional framework. We have also enhanced our ability to predict oil gravity and well primary recovery by unraveling some key components of the diatomite oil source and migration history.« less

Active and Passive Seismic Imaging of a Hydraulic Fracture in Diatomite

Summary A comprehensive set of experiments including remote- and treatment-well microseismic monitoring, interwell shear-wave shadowing, and surface tiltmeter arrays, was used to monitor the growth of a hydraulic fracture in the Belridge diatomite. To obtain accurate measurements, an extensive subsurface network of geophones was cemented spanning the diatomite formation in three closely spaced observation wells around the well to be fracture treated. Data analysis indicates that the minifracture and main hydraulic fracture stimulations resulted in a nearly vertical fracture zone (striking N26E) vertically segregated into two separate elements, the uppermost of which grew 60 ft above the perforated interval. The interwell seismic effects are consistent with a wide process zone of reduced shear velocity, process zone of reduced shear velocity, which remote-well microseismic data independently suggest may be as wide as 40 ft. The experiments indicate complicated processes occurring during hydraulic fracturing that have significant implications for stimulation, waterflooding, infill drilling, and EOR. These processes are neither well understood nor included in current hydraulic fracture models. Introduction At the very close well spacings in the Belridge diatomite, reservoir performance is dominated by the fracture system, both natural and hydraulically induced. Fracture azimuth, height, extent, and possible existence of a wide process zone surrounding the main crack are all critical because, if neighboring fractures link up either laterally or vertically, undesirable bypassing will occur during waterflooding and other enhanced recovery operations. Thus, understanding the hydraulic fracture process in Belridge is essential for optimizing diatomite reservoir performance. Existing hydraulic fracture models depict a single, narrow (less than 1-in. thick), vertical, planar fracture with two symmetric wings radiating from the wellbore with an orientation orthogonal to the direction of least principal stress. With these models, leakoff of fracture fluids into the formation would suggest a leakoff-affected zone of several feet for the diatomite formation. This perception of the fracturing process may be too simplistic in light of many laboratory and field observations. laboratory experiments on manmade materials indicate that a process zone is created around the main crack. The details of the process zone vary from material to material. Depending on the conditions under which the fracture is created, the process zone would contain tensile and/or shear cracks, as well as other transformations of the original material. The growth of the main crack is accompanied by the evolution of the process zone that often controls the fracturing process. The process zone induced during process. The process zone induced during hydraulic fracturing manifests itself indirectly by "abnormal" net fracture treatment pressures much larger than can be simulated wiih classic single hydraulic fracture models. Field studies have provided evidence of multiply fractured, hydraulically communicating process zones in almost every case, especially when the material is heterogeneous. Examples include the Gas Research Inst. Second Staged Field Experiment, mineback and coring experiments after a hydraulic fracture, and geological analogs such as microfracturing around dikes. Green et al. using treatment-well vertical seismic profiles (VSP's) and interwell seismic surveys, reported an overlay between a low-velocity anomaly and the microseismic cloud in a hot, dry rock geothermal system.

South Belridge Field, Borderland Basin, U.S., San Joaquin Valley

South Belridge is a giant field in the west San Joaquin Valley, Kern County. Cumulative field production is approximately 700 MMBO and 220 BCFG, with remaining recoverable reserves of approximately 500 MMBO. The daily production is nearly 180 MBO from over 6100 active wells. The focus of current field development and production is the shallow Tulare reservoir. Additional probable diatomite reserves have been conservatively estimated at 550 MMBO and 550 BCFG. South Belridge field has two principal reservoir horizons; the Mio-Pliocene Belridge diatomite of the upper Monterey Formation, and the overlying Plio-Pleistocene Tulare Formation. The field lies on the crest of a large southeast-plunging anticline, sub-parallel to the nearby San Andreas fault system. The reservoir trap in both the Tulare and diatomite reservoir horizons is a combination of structure, stratigraphic factors, and tar seals; the presumed source for the oil is the deeper Monterey Formation. The diatomite reservoir produces light oil (20-32{degree} API gravity) form deep-marine diatomite and diatomaceous shales with extremely high porosity (average 60%) and low permeability (average 1 md). In contrast, the shallow ({lt}1000 ft (305 m) deep) overlying Tulare reservoir produces heavy oil (13-14{degree} API gravity) from unconsolidated, arkosic, fluviodeltaic sands of high porosity (average 35%)more » and permeability (average 3000 md). The depositional model is that of a generally prograding fluviodeltaic system sourced in the nearby basin-margin highlands. More than 6000 closely spaced, shallow wells are the key to steamflood production from hundreds of layered and laterally discontinuous reservoir sands which create laterally and vertically discontinuous reservoir flow units.« less

Reservoir Compaction of the Belridge Diatomite and Surface Subsidence, South Belridge Field, Kern County, California: ABSTRACT

Abstract Surface subsidence due to reservoir compaction during production has been observed in many large oil fields. Subsidence is most obvious in coastal and offshore fields where inundation by the sea occurs. Well known examples are Wilmington field in California and Ekofisk field in the North Sea. In South Belridge field the Belridge diatomite member of the late Miocene Reef Ridge Shale has proven prone to compaction during production. The reservoir, a high porosity, low permeability, highly compressive rock composed largely of diatomite and mudstone, is about 1000 ft thick and lies at an average depth of 1600 ft. Reservoir compaction within the Belridge diatomite due to withdrawals of oil and water in section 12, T28S, R20E, MDBM the estimated peak subsidence rate reached -7.50 ft/yr in July 1985, after 1 yrs of production from the Belridge diatomite reservoir. Since production from the Belridge diatomite reservoir commenced in February, 1984, the surface of the 160 acres producing area has subsided about 12.50 ft. This equates to an estimated reservoir compaction of 30 ft in the Belridge diatomite and an average loss of reservoir porosity of 2.4% from 55.2% to 52.8%. Injection of water for reservoir pressure maintenance in the Belridge diatomite began in June, 1987, and has been effective in mitigating subsidence and repressurizing the reservoir to near-initial pressure. An added benefit of water injection has been improved recovery of oil from the Belridge diatomite by waterflood. The operation of four other water injection projects in South Belridge Field in the Belridge diatomite reservoir suggests that reservoir compaction and surface subsidence is a common occurrence in the field.

Geology and Diagenesis of Belridge Diatomite and Brown Shale, San Joaquin Valley, California: ABSTRACT

End_Page 988------------------------------The late Miocene to Pliocene argillaceous and siliceous shales of the upper Monterey Formation (the Brown Shale and overlying Belridge Diatomite) represent laterally continuous deposits of nearshore, diatom-rich muds and open marine, argillaceous, diatom-bearing muds on a developing shelf and growing anticline which flanked the San Joaquin basin. These units are laterally equivalent to submarine fan and turbidite sedimentary rocks deposited into the basin from the west, south, and east. The lithology of the Brown Shale and Belridge Diatomite is controlled by original composition and subsequent burial diagenesis. The muds underwent diagenetic alteration with the development of silica phases in the sequence: (1) unaltered diatom frustules (biogenic amorphous silica or opal-A); (2) diagenetic amorphous silica (opal-A); and (3) diagenetic crystalline silica (opal-CT). In the oil field, the Belridge Diatomite grades downward from a massive or faintly laminated siliceous mudstone with diatom frustules and opal-A^prime, to a laminated and massive siliceous mudstone with opal-A^prime and some well-preserved diatoms. The Brown Shale grades from a massive or laminated siliceous mudstone with opal-A^prime and some diatoms to a well-laminated argillaceous, diatom-bearing mudston with opal-A^prime and some opal-CT. There is no distinct break in lithology between the Belridge Diatomite and Brown Shale reservoirs, but recrystallization and detrital clay increase downward across the boundary. Porosity in the best diatomite is about 62%, and permeability is about 1 md. End_of_Article - Last_Page 989------------