Central Basin Platform Research Articles

A residual oil zone (ROZ) assessment methodology with application to the central basin platform (Permian Basin, USA) for enhanced oil recovery (EOR) and long-term geologic CO2 storage

Residual oil zones (ROZ) form due to various geologic conditions and are located below the oil/water contact (OWC) of main pay zones (MPZ). Since ROZs usually contain immobile oil, they have not typically been considered commercially attractive for development by conventional primary recovery methods used in the initial phases of oil production. However, during the last decade some operators of these viable fields that also contain ROZs have extended carbon dioxide enhanced oil recovery (CO2-EOR) to below the MPZ to commercially recover oil from the associated ROZ. Increased interest in ROZs is also due to the application of anthropogenic CO2 for oil recovery, leading to the subsurface sequestration of CO2, which can be part of the current net-zero carbon oil and climate change objectives.Several detailed studies of selected formations in the Permian Basin of the United States have shown that ROZs can be as common as traditional conventional oil reservoir traps, suggesting significant resources for potential additional hydrocarbon recovery and subsurface CO2 sequestration via CO2-EOR. However, applications of CO2-EOR to ROZs have been limited despite the estimation of significant oil resources considered recoverable through CO2-EOR, and the benefit of concurrent geologic CO2 storage that would help offset carbon emissions from the produced oil. The combination of insufficient economic incentives and technical reasons related to data scarcity, such as lack of penetration of wells and well logs, for locating ROZs has limited development of their resource potential when compared to known fields.This paper presents a probabilistic methodology for identifying and evaluating ROZ resources for CO2-EOR and CO2 sequestration potential with the use of public and proprietary data sources. The methodology was developed during a pilot study that focused on the ROZ in the San Andres Formation of a nine-county area in the Permian Basin in West Texas. The pilot study estimated a mean oil in place of 25 × 109 barrels (bbl) of oil and a mean potential incremental oil recovery and CO2 utilization of 2.6 × 109 bbl and 28.2 Tcf (1.46 × 109 tons), respectively, with 1 hydrocarbon pore volume (HCPV) of injection using the water alternating gas (WAG) method. The results of this pilot study are consistent with reported volumes in the literature for a similar area in the Permian Basin. The pilot study demonstrated that this methodology could be used to identify and assess the recoverable oil and coincident CO2 storage volumes of ROZs in other formations and regions.

Uncertainty quantification in the Permian Basin using conventional and modified bootstrap methodology

Various uncertainty quantification methodologies are presented using a combination of several deterministic decline curve analysis models and two bootstrapping algorithms. These probabilistic models are applied to 126 sample wells from the Permian basin. Results are presented for 12–72 months of production hindcast given an average well production history of 103 months. Based on the coverage rate and the forecast error (with the coverage rate being more significant in our choice of the best probabilistic models) and using up to one-half of the available production history for a group of sample wells from the Permian Basin, we find that the CBM-SEPD combination is the best probabilistic model for the Central Basin Platform, the MBM-Arps combination is the best probabilistic model for the Delaware Basin, the CBM-Arps is the best probabilistic model for the Midland Basin, and the best probabilistic model for the overall Permian Basin is the CBM-Arps when early time data is used as hindcast and CBM-SEPD for when one-quarter to one-half of the data is used as hindcast. When three-quarters or more of the available production history is used for analysis, the MBM-SEPD probabilistic model is the best combination in terms of both coverage rate and forecast error for all the sub-basins in the Permian. The novelty of this work lies in its extension of bootstrapping methods to other decline curve analysis models. This work also offers the engineer guidance on the best choice of probabilistic model whilst attempting to forecast production from the Permian Basin.

Seismic attribute and well-log analysis for channel characterization in the upper San Andres and Grayburg formations of the Midland Basin, Texas

The Permian Basin is one of the most prolific, and currently one of the most active, oil and gas basins in the USA. The Lower Permian strata in the Permian Basin have produced more than 14 billion barrels of oil (BBO), making it the largest volume of hydrocarbon in the basin. Sedimentation in the Midland Basin during late Leonardian through early Guadalupian (ca. 272–269 Ma) resulted in progradation of shelf edge and ultimately closure of the basin by Middle Permian time. We analyzed a merged seismic survey covering parts of the Permian Basin (i.e., Central Basin Platform and Midland Basin) in Andrews, Ector, and Midland Counties, Texas. The seismic survey and well logs show the presence of gently dipping (ca. 1°) clinoforms in the Upper San Andres and Grayburg Formations on the eastern edge of the Central Basin Platform and western Midland Basin. The seismic attributes, curvature, and spectral decomposition identify low sinuosity slope channels oriented north-south, but such channels do not appear beyond the slope. The shelf edge shifts from north to south during deposition of the Upper San Andres and Grayburg Formations. We identify five basinward shifts noted by the migration of the shelf edge toward the basin center and the presence of channel features along the depositional slope. The petrophysical analysis indicates that channels cut into carbonate rocks and are filled by siliciclastic sediments; this interpretation is supported by the most negative curvature anomalies along the channel axes caused by the differential compaction between the carbonate and siliciclastic rocks. There are a few channels with a northwest-southeast strike, which matches the direction of the Concho Lineament observed by satellite data. Such observations are consistent with previous interpretations of the northern Midland Basin closure during Middle-Late Permian time.

Angular unconformity in Pennsylvanian strata from 3-D seismic interpretation, Goldsmith Field, West Texas

The Pennsylvanian unconformity, which is a detrital surface, separates the beds of the Permian-aged strata from the Lower Paleozoic in the Central Basin Platform. Seismic data interpretation indicates that the unconformity is an angular unconformity, overlying multiple normal faults, and accompanied with a thrust fault which maximizes the region's structural complexity. Additionally, the Pennsylvanian angular unconformity creates pinch-outs between the beds above and below. We computed the spectral decomposition and reflector convergence attributes and analyzed them to characterize the angular unconformity and faults. The spectral decomposition attribute divides the broadband seismic data into different spectral bands to resolve thin beds and show thickness variations. In contrast, the reflector convergence attribute highlights the location and direction of the pinch-outs as they dip south at angles between 2° and 6°. After reviewing findings from RGB blending of the spectrally decomposed frequencies along the Pennsylvanian unconformity, we observed channel-like features and multiple linear bands in addition to the faults and pinch-outs. It can be inferred that the identified linear bands could be the result of different lithologies associated with the tilting of the beds, and the faults may possibly influence hydrocarbon migration or act as a flow barrier to entrap hydrocarbon accumulation. The identification of this angular unconformity and the associated features in the study area are vital for the following reasons: 1) the unconformity surface represents a natural stratigraphic boundary; 2) the stratigraphic pinch-outs act as fluid flow connectivity boundaries; 3) the areal extent of compartmentalized reservoirs' boundaries created by the angular unconformity are better defined; and 4) fault displacements are better understood when planning well locations as faults can be flow barriers, or permeability conduits, depending on facies heterogeneity and/or seal effectiveness of a fault, which can affect hydrocarbon production. The methodology utilized in this study is a further step in the characterization of reservoirs and can be used to expand our knowledge and obtain more information about the Goldsmith Field.

Permian Basin Earthquakes Rattling Up a Mess of Trouble in Texas

_ Few sounds in the American Southwest make the heart race like a rattlesnake’s warning. But lately it’s the rattle of glass windows and grandma’s dishes making hearts skip a beat across the Permian Basin as these tattletale signs indicate an earthquake is slithering through the subsurface. Two of the five largest earthquakes in Texas history—a magnitude (M) 5.4 on 16 November and a M 5.2 on 16 December—occurred in the Permian during the fourth quarter of 2022. In the 30 days following the December temblor, there were more than 230 lower-magnitude seismic events across the basin recorded by TexNet, the Texas state earthquake monitoring network managed by the Bureau of Economic Geology (BEG) at The University of Texas at Austin (UT). In 2017—the first year that TexNet began data collection—there were 46 M ≥2.5 earthquakes recorded in the Permian’s Delaware Basin and 26 in the Midland Basin. In 2022, there were 634 and 72 earthquakes recorded, respectively. This increase in the number of seismic events is troubling as the Permian is the nation’s leading oil and gas production basin. Roughly shaped like a butterfly—with the left wing the Delaware Basin, its body the Central Basin Platform, and the right wing the Midland Basin—the Permian Basin spans more than 75,000 square miles, with the breadth of the historic basin’s century of hydrocarbon production as equally wide. The first commercial oil well was completed in 1921, with oil production continuing through the decades before peaking at nearly 2 million B/D and natural gas production reaching almost 10 Bcf/D in the 1970s. The combination of directional drilling and hydraulic fracturing, along with the application of new technologies, returned the Permian to its perch as the nation’s top producer after many years of production declines. In 2022 the Permian accounted for more than 43% of all oil produced in the US, according to the Federal Reserve Bank of Dallas. December’s oil production surpassed 5.5 million B/D and natural gas exceeded 21 MMcf/D, the US Energy Information Administration reported. While Prosperity returned to the Permian, she did so with considerable produced water baggage that the industry and its regulators are working to address as the complexities of the basin’s geology are rattling dishes and nerves. Slippery When Wet Thirty billion barrels or 1.3 trillion gallons: that’s the volume of produced water disposed underground in the Permian over the past 10 years, according to Rob Bruant, director of product and research at B3 Insight. It’s the equivalent of 2 million Olympic-sized swimming pools. Therein lies the irony of the Permian’s expansive growth. For every 1 bbl of oil produced from formations so impermeable that explosive charges and sand are needed to open and prop up pathways for fluid to flow, there are anywhere from 2 to 15 bbl of brackish and saline formation water produced, requiring proper management and disposal by the operator. Historically, the most common way of managing this produced water was through disposal into EPA Class II injection wells. It was estimated in 2012 that 99% of produced water in Texas was managed through injection, either for disposal or enhanced oil recovery, according to a Groundwater Protection Council report, with about 53%, or 5.3 billion bbl, disposed that year.

Bayesian Framework Helps History Matching of Permian EOR Field With Data Uncertainty

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200807, “Closing the Loop on a History Match for a Permian EOR Field With Relative Permeability Data Uncertainty,” by Usman Aslam, Emerson, and Jorge Burgos, SPE, and Craig Williams, Occidental Petroleum, et al. The paper has not been peer reviewed. _ Reservoir production forecasts are inherently uncertain because of the lack of quality data available to build predictive reservoir models. Traditionally, a best estimate for relative permeability data is assumed during the history-matching process despite significant uncertainty. Performing sensitivities around the best-estimate relative permeability case will cover only part of the uncertainty space. In the complete paper, the authors present an application of a Bayesian framework for uncertainty assessment and efficient history matching of a Permian carbon-dioxide (CO2) enhanced oil recovery field for reliable production forecasting. Field Details Regional and Structural Geology. The Central Basin Platform (CBP) is a positive tectonic feature that separates the Delaware and Midland sub-basins of the Permian. The study field is located on the northeastern end of the CBP, with the Permian (Guadalupian) -aged reservoir composed of San Andres Formation dolostone. The total thickness of the unit is approximately 1,500 ft, with the main reservoir within the middle 600 ft. Structural Framework. The area of interest features 270 wells that have a total depth in the San Andres formation or deeper. Of these, 234 have digital open- or cased-hole logs that were used to correlate formation tops. After reviewing all well logs, it became clear that, historically, the zones were primarily identifiable from porosity picks, which are more subjective than markers identified with gamma ray methods. A new sequence stratigraphic framework was developed based on core descriptions and outcrop analogs. This correlation framework was then extrapolated to well logs. After a grid of north/south and west/east cross sections was correlated across the field and a series of loop ties was made for quality-control purposes, structure and isopach maps were created for each zone. Reservoir Description. At the time of discovery, natural gas was trapped at the structural high point of the study field. Above the gas/oil interface is the gas cap. Below the gas was an oil accumulation, which extended to the producing oil/water contact (POWC). The POWC was defined by early drilling as the maximum depth where water-free oil was produced. The base of the transition zone is the top of the residual oil zone (ROZ); this reservoir interval extends to the free-water level and is an interval believed to have been waterflooded naturally. The ROZ is the target for CO2 injection. Grid Construction and Property Modeling. A full-field detailed 3D reservoir characterization was modeled at 50-ft × 50-ft grid increments and an approximate 2-ft average layer thickness. The reservoir model consists of 114,222,528 cells. A total of 235 wells in the unit area was correlated and used to constrain the structural framework of the model. Quantitative porosity log suites were available in 233 of the wells in the model area, which were used to create the full-field porosity property in the 3D model. The logs were normalized to the core data and upscaled.

Diagenesis of the San Andres Formation in the Seminole unit in Central Basin platform, western Texas

Diagenesis of the San Andres Formation in the Seminole unit in Central Basin platform, western Texas

The value of very low frequencies and far offsets for seismic data in the Permian Basin: Case study on a new dense survey from the Central Basin Platform

The depth of penetration and multidimensional characteristics of seismic waves make them an essential tool for subsurface exploration. However, their band-limited nature can make it difficult to integrate them with other types of ground measurements. Consequently, far offsets and very low-frequency components are key factors in maximizing the information jointly inverted from all recorded data. This explains why extending seismic bandwidth and available offsets has become a major industry focus. Although this requirement generally increases the complexity of acquisition and has an impact on its cost, improvements have been clearly and widely demonstrated on marine data. Onshore seismic data have generally followed the same trend but face different challenges, making it more difficult to maximize the benefits, especially for full-waveform inversion (FWI). This paper describes a new dense survey acquired in 2020 in the Permian Basin and aims to objectively assess the quality and benefits brought by a richer low end of the spectrum and far offsets. For this purpose, we considered several aspects, from acquisition design and field data to FWI imaging and quantitative interpretation.

Tectonic controls on the evolution of mixed carbonate‐siliciclastic systems: Insights from the late Palaeozoic Ouachita‐Marathon Foreland, United States

AbstractSea level is thought to be the primary driver of alternating deposition of carbonate and siliciclastic sediment in shelf settings, with carbonates dominating during transgressive/highstands and siliciclastics during lowstands. Although sediment supply is critically important for shelf‐margin growth in siliciclastic systems, few studies demonstrate its impact on mixed carbonate‐siliciclastic systems. The Permian Basin in Texas, United States, provides an opportunity to investigate the basin evolution regarding the source, sediment routing and particularly shelf/slope growth from syn‐ to postorogenic phases during alternating carbonate and siliciclastic sedimentation. Published detrital zircon data show that the proportion of orogen‐related sources decreased significantly from an earliest Permian synorogenic phase (ca. 298 Ma) to a Leonardian (ca. 280–271 Ma) postorogenic phase, in concert with a grain‐size change from fine‐ to medium‐grained sand to silt. Although along‐strike lateral variabilities exist on the shelf margin, the shelf‐margin evolution characteristics show a significant difference among the Northern Shelf, Eastern Shelf and Central Basin Platform. The synorogenic Eastern Shelf exhibits a significant higher progradation rate than does the postorogenic Northern Shelf. The progradation and aggradation ratio of siliciclastic‐rich intervals in the Eastern Shelf is significantly higher than those of carbonate‐rich intervals in the Eastern Shelf and carbonate‐ or siliciclastic‐rich intervals in the Northern Shelf. In contrast, the Central Basin Platform, with no siliciclastic sediment supply, records almost no progradation regardless of orogenic phases. There is an increase in slope gradient with decreasing sediment supply during this second‐order sequence from the Permian Cisuralian Series to the end of the Guadalupian Series. This study demonstrates that tectonically driven siliciclastic sediment supply was the main mechanism controlling the shelf and slope evolution in alternating siliciclastic and carbonate deposition.

Probabilistic Decline Curve Analysis in the Permian Basin using Bayesian and Approximate Bayesian Inference

Summary In this work, a probabilistic methodology for decline curve analysis (DCA) in unconventional reservoirs is presented using several Bayesian model-fitting algorithms and deterministic models. The deterministic models considered are the power law exponential (PLE) model, the stretched exponential production decline (SEPD) model, Duong’s model, and the logistic growth analysis (LGA) model. Accurate production forecasting and uncertainty quantification were the primary objectives of this study. The Bayesian inferencing techniques described in this work utilize three sampling vehicles, namely the Gibbs sampling (implemented in OpenBUGS, an open-source software), the Metropolis-Hastings (MH) algorithm, and approximate Bayesian computation (ABC) to sample parameter values from their posterior distributions. These different sampling algorithms are applied in conjunction with DCA models to estimate DCA parameter prediction intervals. Using these prediction levels, production is forecasted, and uncertainty bounds are established. To examine its reliability, the methodology was tested on over 74 oil and gas wells located in the three main subplays of the Permian Basin, namely, the Delaware play, the Central Basin Platform, and the Midland play. Results show that the examined DCA-Bayesian models are well calibrated, result in low production errors, and narrow uncertainty bounds for the production history data sets. Also, the LGA model is best in terms of prediction errors for all algorithms except MH. The Gibbs algorithm is nearly the best algorithm in terms of prediction error for all DCA models except the Arps model. Prediction errors are the highest in the Central Basin Platform. The methodology was also successfully applied to unconventional reservoirs with as low as six months of available production history. Depending on the amount of production history data available, the probabilistic model that provides the best fit can vary. It is therefore recommended that all possible combinations of the deterministic and Bayesian model-fitting algorithms be applied to the available production history. This is to obtain more confidence in the conclusions related to the production forecasts, reserves estimate, and uncertainty bounds. The novelty of this methodology relies on using multiple combinations of DCA-Bayesian models to achieve accurate reserves estimates and narrow uncertainty bounds. This paper can help assess shale plays because some of the shale plays are in the early stages of development when productivity estimations are carried out.

Seismic features of the Permian Basin Region from receiver function analysis

We used receiver function (RF) analysis to derive new seismic models of Moho depth, crustal Vp/Vs ratio, depth of sedimentary velocity discontinuity, and corresponding sedimentary Vp/Vs ratio in the Permian Basin region from the seismic waveform data of 260 moment magnitude (Mw) ≥ 6 teleseismic events. We obtained the optimal models by searching one- and two-layer models and comparing similarity between the synthetic and observed RFs. We find the first-order velocity discontinuity in sedimentary basins is shallower than the basin basement. The Delaware Basin (DB) exhibits a bowl-shaped sedimentary velocity discontinuity, with depths ranging from 1.7 km to 5.8 km, whereas the Central Basin Platform (CBP) has a shallow sedimentary velocity discontinuity, with 0.2 km to 2.7 km depths. Moho depth ranges from 36 km to 46 km in the Permian Basin region. The median Vp/Vs ratios of the crust are 1.75, 1.79, and 1.78 in the DB, CBP, and the Diablo Platform (DP), respectively. Our interpretation of the different Vp/Vs ratio in the three subregions is that the crust in the DB includes more low-Vp/Vs-ratio felsic rocks, and the crust in the CBP and DP contains more high-Vp/Vs-ratio gabbroic and basaltic rocks from the Proterozoic and Phanerozoic mafic intrusion.

Comparing Resource Plays in the Texas and New Mexico Permian Basin – Implications for Exploration Research

The Permian Basin in Western Texas and North Eastern New Mexico is an energy powerhouse. With three sub-basins i.e., Delaware, Central Basin Platform and Midland Basin producing hydrocarbons from both conventional and unconventional plays, the Texan Permian has been a focus of more interest from energy companies than the North-Western Shelf of the basin in New Mexico. However, the less explored North Western shelf of the basin in New Mexico furnishes equal opportunity for oil and gas exploration companies for further exploration research and subsequent discoveries. This research is an attempt to showcase the exploration significance and highlight the gaps for in exploration research in the New Mexico Permian Basin. We compare the oil plays in both Texas and New Mexico Permian based on reservoir geology and basin architecture. Overall, The Permian Basin is dominated by carbonate reservoirs. They account for 75% of all oil production followed by clastics, which contribute 14%; then come the mixed clastics and carbonates accounting for 8%; and lastly cherts make up around 3%. The leading growing production zone is the San Andres platform (Northwest shelf) carbonate play (4.0 billion bbl) followed by the Leonard restricted platform carbonate play (3.3 billion bbl). The Lower Permian Horseshoe and Pennsylvanian plays are next (2.7 billion bbl) and lastly by the San Andres platform carbonate play contributes to the overall production (2.2 billion bbl). With known potential of shelf plays we determine that North Western Shelf has similar stratigraphy and extensive hydrocarbon potential yet to be researched and explored.

The early Paleozoic structures and its influence on the Permian strata, Midland Basin: Insights from multi-attribute seismic analysis

The Permian Basin is one of the most important petroleum-producing regions in the United States. The structural history of the Permian Basin is extremely complex. Most of the structural traps in the Permian Basin are associated with the strike-slip fault system, which presented challenges for past structural interpretation completed primarily using well log and 2D seismic data. We utilized a 3D seismic survey, a part of the Midland Basin and eastern margin of the Central Basin Platform (CBP), to identify the Early Paleozoic structural elements to study its influence on the HC production from the Permian strata. We computed volumetric seismic attributes including, coherence which can identify faults with a significant amount of throw, along with curvature which can detect flexure and folds. We also used, recently developed aberrancy attribute, which illuminates subtle faults and flexures. We observed several strong lineations on seismic attributes extracted along the Woodford surface. Lineations have three different trends. Trend 1 lineations are drag folds associated with the Andrews shear zone (ASZ). Trend 2 lineations, which show a left-lateral strike-slip motion, are R’ Riedel Shear, are oriented N 65° W truncating against the CBP. The trend 2 lineations continue upward to the shallower surfaces, as well as they are parallel to the surface lineations identified on the satellite images, which indicates the continued movement of the pre-existing faults. The trend 3 lineations, which show a right-lateral strike-slip motion, are R Riedel Shear and align with the ASZ. The formation micro image (FMI) shows the fracture orientations in trend 2 and trend 3 directions. The aberrancy lineation anomalies are indicative of highly fractured areas; wells drilled in these areas display lower oil-water ratio, as well as a higher amount of production, which may be due to the increase in permeability due to the fractures.

Spatiotemporal and stratigraphic trends in salt-water disposal practices of the Permian Basin, Texas and New Mexico, United States

Subsurface disposal of salt water coproduced with oil and gas has become a critical issue in the United States because of linkages with induced seismicity, as seen in Oklahoma and northcentral Texas. Here, we assess the spatiotemporal and stratigraphic variations of salt-water disposal (SWD) volumes in the Permian Basin. The results of this analysis provide critical input into integrated assessments needed for handling of produced water and for emerging concerns, such as induced seismicity. Wellbore architecture, permits, and disposal volumes were compiled, interpreted for disposal intervals and geologic targets, and summarized at formation, subregion, a 100-mi2 (260-km2) area, and monthly volumes for the years 1978–2016. Geologic targets were interpreted by intersecting the disposal intervals with gridded stratigraphic horizons and by reviewing well logs where available. A total of 30 billion bbl (∼5 trillion L) were disposed into 73 geologic units within 6 subregions via 8201 active SWD wells for 39 yr. Most disposal occurred in the Midland Basin and Central Basin Platform (CBP) over the first 34 yr but shifted from the CBP to the Delaware Basin over the last 5 yr (2011–2016) with the expansion of unconventional oil and gas production. Approximately half of the salt water is disposed above the major unconventional reservoirs into Guadalupian-aged formations, raising concerns of overpressuring and interference with production. Operators are exploring deeper SWD targets; however, proximity to crystalline basement poses concerns for high drilling costs and the potential for induced seismicity by reactivation of deep-seated faults.

Spatial variability of produced-water quality and alternative-source water analysis applied to the Permian Basin, USA

Interest in both environmental impact and potential beneficial uses of produced water (PW) has increased with growth in unconventional oil and gas production, especially in semi-arid regions, e.g. the Permian Basin, the most productive tight-oil region in the USA. Characterization of PW compositional variability is needed to evaluate environmental impact, treatment, and reuse potential. Geochemical variability of PW from Guadalupian (Middle Permian) to Ordovician formations was statistically and geostatistically evaluated in the western half of the Permian Basin (Delaware Basin, Central Basin Platform, and Northwest Shelf) using the US Geological Survey’s Produced Waters Geochemical Database and the New Mexico Water and Infrastructure Data System. Mean total dissolved solids (TDS) of PW increased with depth in the Delaware Basin and Central Basin Platform to the Delaware and Wolfcamp formations (Guadalupian age). Mean TDS decreased with further increases in depth. In contrast, the mean salinity of PW was significantly higher within the shallow, younger formations (largest mean TDS in the Artesia Formation); TDS decreased with depth below Guadalupian age formations in the Northwest Shelf. Kriged contour maps of TDS and major ions illustrated spatial variability across the three geo-structural regions as a function of depth. The occurrence of meteoric waters in upper and deeper formations across the three regions was significant, and was attributed to Laramide Orogeny and Basin and Range extension uplifting and tilting effects and recent water flooding. These results quantify PW composition variability, and suggest that upon treatment, PW would support some uses such as onsite reuse and mining.

The significance of karst unconformities on overlying resource shales: Lessons learned from the Devonian Woodford Formation applied to the Permian Wolfcamp Shale

We have summarized the threefold significance of karst unconformity boundary: (1) The development of a sequence stratigraphic model for the Devonian Woodford Shale Formation is transferable to the Upper Wolfcamp in the Permian Basin, (2) demonstration of the more general application of that model beyond the Woodford to other resource shales, and (3) illustration of a modification of common sequence stratigraphy models specifically to unconventional resource shales. During early transgression, marine encroachment into the paleolows created anoxic, hypersaline marine “pockets” conducive to the preservation of organic matter. The result is deposition of thick, laterally discontinuous, organic-rich strata stratigraphically at or near the unconformity surface. This pattern of deposition and distribution of the organic-rich shale has been well-documented in the Devonian Woodford Shale and is applicable to other resource shales, in this case to the Permian Upper Wolfcamp Formation in the Central Basin Platform of the Permian Basin. The stratigraphy of the distribution of the Upper Wolfcamp on top of the Upper/Middle Wolfcamp Unconformity is similar to that of the Woodford, suggesting a similar origin and distribution. The resulting stratigraphy in both cases resembles that of the classical Exxon sea slug model except that rather than a single organic-rich deposit defining the condensed section and maximum flooding surface, a second organic-rich deposit occurs stratigraphically lower, at or near the unconformity surface. This theoretical summary can support the discovery of potential drillable target zones in the Woodford Shale and the Wolfcamp Shale.

State of stress in the Permian Basin, Texas and New Mexico: Implications for induced seismicity

Since the 1960s, the Permian Basin of west Texas and southeast New Mexico has experienced earthquakes that were possibly triggered by oil and gas activities. In recent years, seismicity has been concentrated near Pecos, Texas; around the Dagger Draw Field, New Mexico; and near the Cogdell Field, Snyder, Texas. We have collected hundreds of measurements of stress orientation and relative magnitude to identify potentially active normal, normal/strike-slip, or strike-slip faults that might be susceptible to earthquake triggering in this region. In the Midland Basin and Central Basin Platform, the faulting regime is consistently normal/strike slip, and the direction of the maximum horizontal compressive stress (SHmax) is approximately east–west, although modest rotations of the SHmaxdirection are seen in some areas. Within the Delaware Basin, however, a large-magnitude clockwise rotation (∼150°) of SHmaxoccurs progressively from being nearly north–south in the north to east-southeast–west-northwest in the south, including the western Val Verde Basin. A normal faulting stress field is observed throughout the Delaware Basin. We use these stress data to estimate the potential for slip on mapped faults across the Permian Basin in response to injection-related pressure changes at depth that might be associated with future oil and gas development activities in the region.

Carbonate platform-margin architecture and its influence on Cambrian-Ordovician reef-shoal development, Tarim Basin, NW China

Six types of carbonate platform marginal slope have been identified in the Cambrian-Ordovician of Tarim Basin. These include a progradational carbonate ramp platform, a progradational carbonate rimmed platform, an aggradational rimmed carbonate platform, a retrogradational rimmed carbonate platform, an aggradational margin on an isolated carbonate platform and a retrogradational margin on a submerged carbonate platform. Various platform margin architectures and reef-shoal characteristics occur in different areas of the Tarim basin. A progradational carbonate ramp platform margin began in the Early Cambrian in the Tarim basin. A progradational rimmed platform margin developed in the Middle Cambrian time in the northern Tarim basin, whereas contemporaneously a progradational ramp platform margin developed in the southwestern and central Tarim basin. A retrogradational rimmed carbonate platform developed in the northern Tarim basin, whereas an aggradational rimmed carbonate platform occupied the central Tarim basin in the Early Ordovician time. An aggradational margin on an isolated platform and a retrogradational margin on a submerged platform developed mainly during the Late Ordovician in the central Tarim basin. Platform margin-slopes migrated continually throughout the Cambro-Ordovician. The broad platform area (western Tarim Platform) that occupied most of the northwestern and central Tarim Basin in the Early Cambrian time was split by an east-west oriented shelf seaway that began to develop along the eastern and western margins of the platform in the Early Ordovician time and completely transected the platform by Late Ordovician time. The resultant central Tarim Basin platform area was much reduced, elongate east-west around the Central Tarim paleo-uplift, and terminated eastward towards region of the Late Ordovician basinal deposition across the eastern Tarim Basin. Affected by platform margin structure, Climate and paleodepth, algal reefs and shoals developed mainly in the Cambrian, and intraclastic shoals developed mainly in the Early Ordovician, followed by reef-building of framestone or bafflestone in the Late Ordovician.

Eustatic controls on stratigraphy, chemostratigraphy, and water mass evolution preserved in a Lower Permian mudrock succession, Delaware Basin, west Texas, USA

Bone Spring (Leonardian) mudrock successions in Delaware Basin vary between silica- and carbonate-rich facies marking depositional responses to sea-level changes. Increased Mo, [Formula: see text], and total organic carbon (TOC) record reduced oxygenation during sea-level lowstands. In a 91.4-m (300 ft) core from Sun No. 1 Houssels well and a 39.6-m (130 ft) core from Shell No. 1 Marsden well (Reeves Co., Texas), lower Bone Spring cycles comprised siliceous-calcareous mudrock couplets. The Marsden core was correlative to the upper part of the Houssels core. Cyclicity was interpreted from mineralogical calculations at numerous core horizons using energy-dispersive X-ray fluorescence (ED-XRF) measurements of elemental content. Elemental abundances enabled predicting mineralogy based on the stoichiometric relationships between elements and dominant minerals (calcite and quartz), and from average values of Si and K in published illite analyses. The average sample spacing for ED-XRF measurements was 0.24 m (0.8 ft) for the Houssels core and 0.15 m (0.5 ft) for the Marsden core. The measurements and interpretations provided: (1) information regarding comparisons in stratigraphic and geographic development of facies over the 10-km (6.2-mi) distance between wells and (2) guidance for petrographic, scanning electron micrograph, and organic matter analyses that address processes that produced different facies. Greater carbonate abundance in the Houssels core reflected the proximity to carbonate shelves on the Central Basin Platform (CBP); the greater siliciclastic abundance in the Marsden core was thought to reflect the greater distance from the CBP. Redox element (S and Mo) and TOC concentrations were greater, and [Formula: see text] values were higher in some siliciclastic-dominated intervals, suggesting that anoxia characterized sea-level lowstands when normal marine water flowing from the Panthalassa Ocean was inhibited through narrow interbasin channels or over sills. Carbon isotope ([Formula: see text]) variations suggested changes in organic matter characteristics, whereby greater [Formula: see text]-depleted organic matter was deposited during sea-level lowstands, marking: (1) reduction of shallow-marine sources or (2) increased terrigenous organic carbon contributions.

Techniques and best practices in multiattribute display

All color monitors display images by mixing red, green, and blue (RGB) components. These RGB components can be defined mathematically in terms of hue, lightness, and saturation (HLS) components. A fourth alpha-blending (also called opacity) component provides a means to corender multiple images. Most, but not all, modern commercial interpretation workstation software vendors provide multiattribute display tools using an opacity model. A smaller subset of vendors provide tools to interactively display two or three attributes using HLS, CMY, and RGB color models. I evaluated a technique (or trick) to simulate the HLS color model using monochromatic color bars and only opacity. This same trick only approximates true color blending of RGB or CMY components. There are three basic objectives in choosing which attributes to display together. The first objective is to understand the correlation of one attribute to another, and most commonly, of a given attribute to the original seismic amplitude data. The second objective is to visualize the confidence or relevance of a given attribute by modulating it with a second attribute. The third objective is to provide a more integrated image of the seismic data volume by choosing attributes that are mathematically independent but correlated through the underlying geology. I developed the interpretation value of the HLS display technique on a 3D data volume acquired over the Central Basin Platform of west Texas exhibiting faults, fractures, folds, channels, pinch outs, and karst features. To be a useful “technique,” I need to demonstrate these workflows within a specific package. Although I implemented the workflow in Petrel 2014, similar images can be generated using any software with flexible opacity capabilities. I also developed a short list of attribute combinations that are particularly amenable to corendering in HLS.