Reservoir Imaging Research Articles

Continuous wavelet transforms of spectral decomposition analyses for fluvial reservoir characterization of Miano Gas Field, Indus Platform, Pakistan

Fluvial depositional systems constitute diverse host for the hydrocarbons all over the globe. Nevertheless, predicting the hydrocarbon sands within these assorted sand systems is a challenge for the prospect generation. We apply the continuous wavelet transform of spectral decomposition technique to a 3D seismic data of the Miano Gas Field in the Indus Platform, Pakistan. Full spectrum seismic attributes like the amplitude and root mean square (RMS) detect the reservoir sands down to a restricted reservoir compartment. Nonetheless, the continuous wavelet transforms can be advantageous in imaging and enactment of these clastic reservoirs within the whole reservoir zone. Rock physics reveal high-quality reservoir with an average porosity ∼25% together with the discrimination of lithology/fluids, signifying the bright chances for ascertaining the potential stratigraphic reservoirs.

The influence of volcanic rocks on the characterization of Rosebank Field – new insights from ocean-bottom seismic data and geological analogues integrated through interpretation and modelling

Abstract During Late Paleocene–Early Eocene times, the modern Rosebank structure was located at the juxtaposition of the easterly advancing Flett volcanic system and the northerly prograding Flett delta. As a result, the Rosebank reservoir sandstones are interstratified with volcanic and volcaniclastic rocks, offering challenges for reservoir imaging, depth prediction and reservoir characterization. These challenges have driven the application of Ocean Bottom Node (OBN) seismic technology. OBN data have yielded improved velocity models for depth conversion, better reservoir definition and key insights to aid the modelling of sand distribution from seismic attributes. Spectral decomposition of the OBN seismic data has facilitated the extraction of distinct volcanic subunits, whilst spectral enhancement has enabled visualization of complex stacking patterns within individual igneous layers. To complement the seismic analysis, detailed geological analogue studies have been undertaken in volcanic provinces such as the Palaeogene volcanic district of SE Greenland and the Columbia River Flood Basalt Province, USA. No single outcrop provides a definitive analogy to Rosebank, but each offers insights that provide an important link to understanding and managing the main subsurface uncertainties associated with field development. Integration of these multiple workflows have improved the reservoir characterization and provided the foundation for the optimization of the field development plan.

The stability problem of reverse time migration for viscoacoustic VTI media

In real strata anisotropy and viscosity extensively exists. They degraded waveforms in amplitude, resulting in which reducing of image resolution. To obtain high-precision imaging of deep reservoirs, we extended the separated viscous and anisotropic reverse time migration (RTM) to a stable viscoacoustic anisotropic RTM for vertical transverse isotropic (VTI) media, based on single generalized standard and linear solid (GSLS) media theory.. We used a pseudo-spectral method to develop the numerical simulation. By introducing a regularization operator to eliminate the high-frequency instability problem, we built a stable inverse propagator and achieved viscoacoustic VTI media RTM. High-resolution imaging results were obtained after correcting for the effects of anisotropy and viscosity. Synthetic tests verify the validity and accuracy of algorithm.

Combining surface-wave phase-velocity dispersion curves and full microtremor horizontal-to-vertical spectral ratio for subsurface sedimentary site characterization

We compute seismic velocity profiles by a combined inversion of surface-wave phase-velocity dispersion curves together with the full spectrum of the microtremor horizontal-to-vertical (H/V) spectral ratio at two sediment-covered sites in Germany. The sediment deposits are approximately 100 m thick at the first test site and approximately 400 m thick at the second test site. We have used an extended physical model based on the diffuse wavefield assumption for the interpretation of the observed microtremor H/V spectral ratio. The extension includes the interpretation of the microtremor H/V spectral ratio observed at depth (in boreholes). This full-wavefield approach accounts for the energy contribution from the body and surface waves, and thus it allows for inverting the properties of the shallow subsurface. We have obtained the multimode phase velocity dispersion curves from an independent study, and a description of the extracted branches and their interpretation was developed. The inversion results indicate that the combined approach using seismic ambient noise and actively generated surface-wave data will improve the accuracy of the reconstructed near-surface velocity model, a key step in microzonation, geotechnical engineering, seismic statics corrections, and reservoir imaging.

Advanced seismic processing/imaging techniques and their potential for geothermal exploration

Seismic reflection imaging is a geophysical method that provides greater resolution at depth than other methods and is, therefore, the method of choice for hydrocarbon-reservoir exploration. However, seismic imaging has only sparingly been used to explore and monitor geothermal reservoirs. Yet, detailed images of reservoirs are an essential prerequisite to assess the feasibility of geothermal projects and to reduce the risk associated with expensive drilling programs. The vast experience of hydrocarbon seismic imaging has much to offer in illuminating the route toward improved seismic exploration of geothermal reservoirs — but adaptations to the geothermal problem are required. Specialized seismic acquisition and processing techniques with significant potential for the geothermal case are the use of 3D arrays and multicomponent sensors, coupled with sophisticated processing, including seismic attribute analysis, polarization filtering/migration, converted-wave processing, and the analysis of the diffracted wavefield. Furthermore, full-waveform inversion and S-wave splitting investigations potentially provide quantitative estimates of elastic parameters, from which it may be possible to infer critical geothermal properties, such as porosity and temperature.

Reducing the gap between seismic imaging and geology: Horizon consistent velocity analysis and modelling for pre-stack time and depth migrations

S eismic velocities and migration techniques have great impact in the reservoir imaging at any stage of the exploration for hydrocarbons. The effectiveness of a migration algorithm is commonly measured by the ability to boost the signal continuity, against noise and other disturbances such as diffractions from out-of-plane events (Jones, 2010). By contrast, migration is a process applied to reposition the energy from where it originated, to resolve the geometry and positioning of the events. The success of the process is heavily reliant on the velocity field used. The consistency between the velocity field and events is a quality indicator in seismic inversion exercises, for both the low frequency background and the high frequency intervals identified in velocity logs. The migration itself can be seen as an inversion procedure, with the velocity gradients required to be consistent with vertical trends and amplitude events (Guillaume et al., 2011; Benson et al., 2015). The understanding of geological velocities progresses with exploration and the increasing number of wells and geophysical data available, which gradually establish lithological and rock physics properties, together with tectonic and burial history. Several pre-stack algorithms are available for time migration (PSTM) as well as for depth migration (PSDM), which allow the velocity analysis and modelling sequence to more closely integrate geophysical and geological data. Nowadays, pre-conditioned migration velocities are common in the depth imaging, during the processing of PSDM. The approach is applied for complex geology and relies on seismic and non-seismic data, also combined through different joint inversion techniques (Droujinine et al., 2008; Foss et al., 2008; Houghton et al., 2014). We present a migration workflow, originally designed for regional 2D seismic and applicable to 3D, which links the velocity modelling for PSTM with PSDM, and allows geological constraints to be applied at the PSTM stage (Figure 1).

High-resolution facies modeling of presalt lacustrine carbonates reservoir analog: Morro do Chaves Formation example, Sergipe-Alagoas Basin, Brazil

Barremian lacustrine carbonates, mainly coquinas, are the reservoir rocks of the large presalt petroleum discoveries in deep to ultradeepwaters, at the southeast Brazilian margin, namely, the Santos, Campos, and Espirito Santo Basins. The complex geologic setting of those discoveries, with massive overburden of salt bodies, makes the seismic imaging of the carbonate reservoirs an expensive and challenging issue. In this setting, accurate facies models are a requirement to the predictability of the carbonate reservoir intervals. We have developed an analog high-resolution coquinas facies model based on an interpretation of a pseudo-3D ground penetrating radar survey. We relied not only on the trace amplitude analysis, but also on trace attributes to reduce the ambiguity of the interpretation due to possible visual biases, which may relate electromagnetic reflection amplitude to geologic relevance. We have used the dip and texture attributes to help us better understand the subsurface and to focus on the main stratigraphic features of the reservoir analog. We have applied the dip attribute to discriminate among distinct facies and to provide a dip-steered horizon-tracking tool, honoring the stratigraphic layering. We have also used a texture attribute to downgrade high-frequency noise in the amplitude cube and emphasize the main stratigraphic horizons separating reflections with a similar and consistent pattern. Then, we produced a joint interpretation, based on three trace attributes, that is, amplitude, dip, and texture, to highlight the main radar facies. That resulted in a facies model in which three southwest–northeast-striking coquina bars (reservoir facies), associated with transgressive systems tract interbedded with shales (nonreservoir facies) of highstand systems tract, are clearly marked.

Seismic characterization and monitoring of a deep CO2 storage reservoir with 3D VSP using direct shear waves

We show a low-cost option for shear wave imaging of CO2 storage reservoirs that utilizes seismic waves that have been ignored by reflection seismologists for decades. These overlooked waves are direct-S waves generated by vertical-displacement vibrators and explosive sources. Shear waves are known to be helpful for detecting fractures and subtle faults which is critical for evaluating of CO2 storage capacity and sealing properties of the caprock. Utilizing direct-S waves produced by P-wave sources provides these benefits with no need to deploy special shear-wave sources. In addition, the SV-P mode, which is the upgoing P-wave produced by SV-to-P conversion, makes it possible to utilize S-wave attributes with data recorded by vertical geophones only.We developed a processing workflow to extract SV-SV and SV-P seismic modes from 3D VSP data acquired over a CO2 storage reservoir at Decatur, Illinois and tested these modes for seismic imaging and monitoring of the reservoir. In addition, we inspected an SH-SH mode that appeared interpretable in our data. We observed that direct-S images were consistent with traditional VSP direct-P images and calibration synthetic seismograms. A joint analysis of all available seismic modes allowed a constrained interpretation of faults within the reservoir. Direct-S waves appeared to not be advantageous for CO2 plume growth monitoring in the Decatur project. The SV-P mode demonstrated low sensitivity to CO2 concentration. The time-lapse difference for the SV-SV mode was uninterpretable due to the low signal-to-noise ratio of that mode.

Geometry Matching Technology of Non-Repeating Acquired Time-Lapse Seismic Data Processing

Different from the normal time-lapse seismic technology, time-lapse seismic technology with non-repeating acquired data utilize existing multi-period seismic data with different geometries at different exploration period of the same area. Not only the change of reservoir parameters cause the property differences of two-period data but also the difference of geometries, this uncertainty has become a fundamental problem in application of time-lapse seismic technology. In order to solve this problem, this paper takes advantage of the 3D Gaussian beam simulating method for illumination analysis of reservoir model, then we analyzes the impacts of various parameters of geometry on receiving energy of reservoir, finally we put forward the main factors affecting imaging of reservoir : the distribution of offset and azimuth. Basing on this conclusion this paper established the work flow of geometry matching for non-repeating acquired seismic data. By processing real data in S block, this technology could effectively reduce the affects of geometry difference and obtain an obvious result, and also provide an idea to increase value of multi-period seismic data in old oil field.

Broadband Seismic Acquisition: Implications for Interpretation and Reservoir Models

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18075, “The Impact of Broadband Seismic Acquisition and Implications for Interpretation and Reservoir-Model Building,” by Carter Gehman and Andrew Spedding, Hess, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. This paper addresses the impact of acquiring a new 3D broadband seismic survey over an amplitude-supported, discovered gas field containing legacy 3D conventional towed-streamer seismic data. The new seismic data were acquired in shallow water depths by use of a dual-level streamer technique and were processed through prestack depth migration (PSDM). Five gas discovery/ appraisal wells existed before broadband acquisition, and two wells were drilled after acquisition was completed. These seven wells serve as control points that provide a valuable link between the seismic and reservoir properties. Introduction and Background Seismic imaging of hydrocarbon reservoirs with small impedance contrasts relative to bounding lithologies is challenging. Ideally, an infinite bandwidth wavelet would detect and resolve subsurface geology as observed in the resolution of a typical wireline log. Improvements in seismic acquisition and processing continue to strive toward this ideal condition, and recent advancements in seismic acquisition— namely, the broadband acquisition technique—have attempted an approximation of the infinite bandwidth wavelet through the removal of the receiver or source ghosts. This advancement is of particular interest in oil and gas development areas where known thin or poor-quality reservoirs that are difficult to detect on conventional seismic records have been penetrated by previous wells. The study area is located in the shallow (less than 200 ft) waters off peninsular Malaysia. Seven exploration and appraisal wells have targeted shallow and deep reservoirs, although only three wells have been drilled to deep targets. Generally speaking, seismic imaging of shallow reservoirs is good, while deep targets are more challenging to image. The primary motivation for acquiring a new broadband seismic survey stemmed from imaging difficulties of thin (less than 15 ft) deep gas reservoirs on conventional seismic data. Many of these reservoirs are vertically juxtaposed by coals, which tend to mask the acoustic response of the reservoir. Even after later reprocessing of legacy data through anisotropic PSDM, imaging difficulties remained.

Quantitative research on tight oil microscopic state of Chang 7 Member of Triassic Yanchang Formation in Ordos Basin, NW China

Abstract With nuclear magnetic resonance (NMR) and micrometer-nanometer CT Scanning technology, quantitative research was carried out of the micro-existing state of tight oil in the Chang7 Member of the Triassic Yanchang Formation in the Ordos Basin. The total reserves of the tight oil in the reservoirs were determined using NMR technology. The initial oil saturation was measured as 63.99%. The 2-D slice images of the tight oil reservoirs were obtained using CT Scanning technology, and the 3-D images were acquired after digital synthesis processing. Accordingly, the existence states of the tight oil in the reservoirs are divided into six types, namely thin film form, cluster form, throat form, emulsion form, particle form and isolation form. It is found by quantitative calculation of the contents of tight oil in different existence states of tight oil that the emulsion form and thin film form are the main existence states, which account for 70% of the total amount of the tight oil in the reservoirs, followed by the cluster and particle forms. The contents of isolation form and throat form tight oil are low. The contents of tight oil in various existence states are related to initial water saturation, clay mineral content and pores structure of the reservoirs.

3D surface‐wave estimation and separation using a closed‐loop approach

ABSTRACTSurface waves in seismic data are often dominant in a land or shallow‐water environment. Separating them from primaries is of great importance either for removing them as noise for reservoir imaging and characterization or for extracting them as signal for near‐surface characterization. However, their complex properties make the surface‐wave separation significantly challenging in seismic processing. To address the challenges, we propose a method of three‐dimensional surface‐wave estimation and separation using an iterative closed‐loop approach. The closed loop contains a relatively simple forward model of surface waves and adaptive subtraction of the forward‐modelled surface waves from the observed surface waves, making it possible to evaluate the residual between them. In this approach, the surface‐wave model is parameterized by the frequency‐dependent slowness and source properties for each surface‐wave mode. The optimal parameters are estimated in such a way that the residual is minimized and, consequently, this approach solves the inverse problem. Through real data examples, we demonstrate that the proposed method successfully estimates the surface waves and separates them out from the seismic data. In addition, it is demonstrated that our method can also be applied to undersampled, irregularly sampled, and blended seismic data.

Application of waveform tomography at the Campos Basin field

Campos Basin field has been continuously character¬ised at the Reservoir Characterization Project (RCP) in Colorado School of Mines. Past research includes poststack and prestack joint inversions of PP and PS data which increased the reservoir resolution and could predict a porosity map. To further improve characterisation of the Campos Basin field, waveform tomography (WT), or full waveform inversion (FWI), is performed for a 2D line from the 2010 ocean bottom cable (OBC) data under a 2D acoustic isotropic medium assumption. The goal is to bring high resolution and accuracy to the P wave veloc¬ity model for better-quality reservoir imaging. In order to achieve the best results the application of WT to the 2D dataset required defining the suitable parameters to these data, where the main options in the inversion are the type of objective function, the time domain damping, and the fre¬quency discretisation. Waveform inversion has improved the final velocity model, as verified by migrated images showing more continuous and focused horizons at the reservoir depth. The improved seismic image and velocity model are possible inputs, respectively, to a new geological interpretation and to acoustic/elastic attributes inversion. Waveform tomography (WT), or Full Waveform Inversion (FWI), has been the subject of studies and conceptual devel-opment over the past 30 years (Virieux and Operto, 2009). Furthermore, research groups and the oil industry around the world have shown the improvement that WT can bring to the velocity model, especially in terms of high resolution in comparison with conventional techniques, such as traveltime tomography (TT) or migration velocity analysis (MVA). These techniques can only build a smoothed version of the velocity model, containing the kinematics of the wavefield, even though they are able to generate a good quality seismic image. WT represents a more advanced approach that attempts to completely describe the complex interaction of the propagating waves and the earth, in which the phase of the whole waveform is used in the model reconstruction (Pratt, 2013).

E&P Notes (November 2014)

E&P Notes Testing the World’s First Modular Capture Vessels Trent Jacobs, JPT Technology Writer In response to the 2010 Deepwater Horizon incident that claimed the lives of 11 men and led to the worst oil spill in United States history, the offshore industry devised new technologies and methods that would allow for a quicker response if a similar event was to occur again in the US Gulf of Mexico. Among the newest response systems are the conversion of two Aframax lightering tankers into capture and containment systems capable of handling 100,000 BOPD of oil and 200 MMscf/D of gas. The company that designed the emergency-response vessels said they are the first production facilities to be built with the hope of never seeing first oil. “They are basically (floating production, storage, and offloading units) that are now available in the Gulf of Mexico for this application,” said Charles Miller, chief technology officer of Marine Well Containment Company (MWCC) at the recent SPE Deepwater Drilling and Completions Conference in Galveston, Texas. Saudi Aramco Displays Reservoir Research Priorities Stephen Rassenfoss, JPT Emerging Technology Senior Editor Saudi Aramco’s plan to create a global network of research centers is becoming a reality. It recently celebrated the opening of its Houston center that the company’s President and Chief Executive Officer Khalid Al-Falih described as “an upstream research center like no other.” The opening of the Aramco Research Center in the heart of the energy technology center in Houston offered a look at how the national oil company is bringing in expertise from around the world to bear on maximizing output from Saudi Arabian reservoirs. The new research center is an extension of Saudi Aramco’s research hub in Dhahran, with complementary groups working on reservoir monitoring and imaging, as well as sensors and drilling. But there is something unique in the Houston center: unconventional reservoir research and development.

Attenuation of post-critical acoustic basement events for improved far offset reservoir imaging

C.I. Bullock discusses methods for managing critical/post-critical basement events and their potential pitfalls.

Imaging and characterization of a shale reservoir onshore Poland, using full-azimuth seismic depth imaging

The exploration and development of shale plays in Europe show that the ‘statistical drilling’ approach used in some basins in recent years cannot be extend­ed to areas where local stress in rocks or fracture distribution varies both laterally and in depth. Moreover, drilling and fracturing practices confirm the presence of local geobodies resistant to hydraulic fracturing. This paper discusses the application of a new seismic data imaging method full-azimuth angle domain depth imaging, which is particularly useful when working with rich-azimuth seismic data. This innovative technology was applied to meet the challenges of imaging in a complex geological environ­ment, and is a pioneering solution in Polish shale gas geology. Results obtained in the study from the analysis of seismic data were in line with results of the geologic and geophysical analysis of the borehole data, as well as with information from microseismic monitoring of fracturing treatment. The technology delivered high-quality images of the reservoir and geomechanical characterization of rocks with the precision needed to steer horizontal drilling, detect sweet spots, and locate geobodies resistant to fracturing. The seismic imaging workflow is based on software spe­cifically developed to meet the challenges of shale gas seismic (Koren and Ravve, 2011, Koren et al., 2013, Canning and Malkin, 2013). One of the main advantages of this approach is that it works directly in the local angle domain (LAD) instead of the surface offset/azimuth domain. The use of in situ azimuth in LAD, visualized together with dedicated seis­mic attributes, provides information about the intensity and orientation of geological stress/fracture systems. Geothermal prospecting and seismic imaging of conventional hydrocar­bon plays can also profit from this method. This technique is particularly suitable for Poland, where conventional seismic migration of reflections from geology covered by a complex overburden has frequently resulted in improper imaging.

In Search of Better Reservoir Imaging Using Fiber Optic Receivers Downhole

Seismic Receivers After nearly 4 decades of work, Bjorn Paulsson has created a system using fiber optic seismic receivers so sensitive that he said it will be able to create much more accurate, detailed seismic images with features too small to be seen now, detect the sounds of fracturing never heard before, and stand up to temperatures exceeding 300°C and pressures of more than 30,000 psi. But he needs USD 12 million from companies interested in using it in their wells, which is nearly equal to the financial backing he has received from the United States Department of Energy (DOE) to get to this stage. Paulsson and the DOE’s Research Partnership to Secure Energy for America (RPSEA) were organizing a meeting in late May seeking the support of oil companies to develop a full-scale version of the system he describes as “more than an order of magnitude better than what we can do now. This is not a small step up, it is a huge step.” The plan is to build a system that can place 200 fiber optic seismic sensors, each of which has three channels (3C) allowing it to detect the direction of incoming signals along three axes, deep in a 30,000-ft deep well. There would be a receiver every 50 ft covered by a metal housing capable of standing up to the extreme pressures found in wells in the ultradeepwater US Gulf of Mexico, and clamped tightly onto a drilling pipe that can deliver it to the end of a long horizontal well.

Full‐wavefield migration of vertical seismic profiling data: using all multiples to extend the illumination area

ABSTRACTVertical seismic profiling data can provide a high‐resolution reservoir image because the receivers are located close to the reservoir and, hence, the wavefield encounters less distortion in the overburden compared to surface seismic data. However, conventional migration of vertical seismic profiling data using only upgoing primary wavefields often suffers from poor illumination, imaging artefacts and low image reliability, especially at image locations away from the well. We propose full‐wavefield migration to image vertical seismic profiling data using the primaries and all orders of surface multiples and internal multiples. The downgoing internal or surface multiples are treated as an additional source of illumination. In full‐wavefield migration, we aim to estimate a high‐resolution reflectivity image of the subsurface with this extended illumination. The algorithm is recursive in depth like conventional wavefield extrapolation‐based migration, however, it incorporates the non‐linear transmission and scattering effects at each depth level. Further, full‐wavefield migration is posed as a constrained least‐squares inversion problem that could be solved using a conjugate gradient method. We propose an iterative full‐wavefield forward modelling engine as the backbone of this inversion scheme. The parameter used in the modelling is subsurface reflectivity. Full‐wavefield modelling iteratively incorporates the non‐linearity of the wavefield due to multiple scattering, where every iteration utilizes one higher order of scattered wavefields to estimate the subsurface reflectivity. In addition, the constrained inversion helps in reducing the extrapolation artefacts and provides a high‐resolution image of the reservoir. In this paper, we discuss the concept of full‐wavefield migration and demonstrate its potential as an imaging tool for vertical seismic profiling data using synthetic examples.

Effect of Grafted Copolymer Composition on Iron Oxide Nanoparticle Stability and Transport in Porous Media at High Salinity

The transport of engineered nanoparticles in porous media is of interest in numerous applications including electromagnetic imaging of subsurface reservoirs, enhanced oil recovery, and CO2 sequestration. A series of poly(2-acrylamido-2-methyl-1-propanesulfonic acid-co-acrylic acid) (poly(AMPS-co-AA)) random copolymers were grafted onto iron oxide (IO) nanoparticles (NPs) to provide colloidal stability in American Petroleum Institute (API) standard brine (8 wt/wt % NaCl and 2 wt/wt %CaCl2, anhydrous basis). A combinatorial approach, which employed grafting poly(AMPS-co-AA) with wide ranges of compositions onto platform amine-functionalized IO NPs via a 1-ethyl-3-(3-(dimethylamino)propyl)carbondiimidecarbondiimide (EDC) catalyzed amidation, was used to screen a large number of polymeric coatings. The ratio of AMPS/AA was varied from 1:1 to 20:1 to balance the requirements of particle stabilization, low adsorption/retention (provided by 2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS)), and permanent atta...

Advantages of joint interpretation of P-P and P-SV seismic data in geothermal exploration

Conventional P-P seismic images of geothermal reservoirs are often of poor quality because P-P data tend to have a low signal-to-noise ratio across geothermal prospects. Fracture identification, fluid prediction, and imaging inside subsurface areas influenced by superheated fluids are some of the challenges facing the geothermal industry. We showed that multicomponent seismic technology is effective for addressing all of these challenges across geothermal reservoirs, even when P-P data are of low quality. Although multicomponent seismic technology has advantages in geothermal exploration, there are not many published examples of multicomponent seismic data being used to characterize geothermal reservoirs. We evaluated data examples that illustrate advantages of multicomponent seismic technology for imaging within and below zones having superheated fluids, estimating fracture attributes, analyzing reservoir trapping structures, differentiating lithologies, and predicting spatial distributions of pore fluids. All examples we tested are from the Wister geothermal field in Southern California.