Bone Spring Research Articles

Geomechanical modeling of reservoir dynamics associated with shallow injection and production in the Delaware Basin

The Permian Basin is an area of active hydrocarbon production and saltwater disposal as well as associated induced seismicity and other geomechanical responses that threaten the surface environment. Among the important but not yet fully answered questions are: (1) what are the temporal and spatial changes in stress and pore pressure in response to fluid injection and production, and (2) how do these changes relate to slip on preexisting faults and surface deformation? We simulate stress and pore pressure responses to saltwater injection in the Delaware Mountain Group (DMG) and production from the Wolfcamp and Bone Spring Formations with the aid of 2D geomechanical simulations that capture key mechanical stratigraphic units and representative faults. Primary loading consists of localized pore pressure changes that represent fluid injection into the DMG and production from the lowermost portion of the Bone Spring Formation, the entire Wolfcamp A Formation, and the uppermost portion of the Wolfcamp B Formation. Injection leads to pore pressure increase, vertical extension, reduction in mean stress, and increase in differential stress in the DMG. Production leads to decrease in pore pressure, vertical contraction, increase in mean stress, and increase in differential stress in the Bone Spring, and Wolfcamp A and B Formations. The net effect of injection and production in our generalized simulations is normal faulting slip on faults that are relatively shallow in the subsurface, similar to faults that are known to have produced seismogenic rupture. The combination of injection and production reproduces a spatially variant trend in uplift and subsidence, consistent with regional patterns measured in the study area via InSAR analysis. The modeled scenarios with shallow injection and/or production caused only small (<0.2 MPa) stress perturbations to propagate downward to basement, which would be unlikely to cause instability of deep-seated seismogenic faults.

A machine-learning workflow to integrate high-resolution core-based facies into basin-scale stratigraphic models for the Wolfcamp and Third Bone Spring Sand, Delaware Basin

The characterization of subsurface reservoirs that are dominated by mudrock facies is hindered by the inherent heterogeneity and high degree of spatial variability typical of mudrock depositional systems. Subsurface reservoir properties that include porosity and permeability, fluid saturations, stratigraphic thicknesses of reservoir units, and source rock potential are ultimately controlled by the spatial distribution of sedimentary rock facies, which supports efforts to improve subsurface characterization workflows. Although core-based data provide direct measurements of rock attributes that are used to inform static reservoir models, capturing high-resolution core-based rock facies and downscaling these observations to tie to lower-resolution wireline logs remains a challenge. The effort to integrate core-based facies to reservoir-scale models is especially difficult when trying to capture thin-bedded heterogeneity that is common to mudrock systems. Herein, a workflow is developed and applied to visualize and integrate multivariate and spatially complex core-based data sets with wireline logs. Formation-specific core-based chemofacies training data sets are developed by integrating core descriptions with chemofacies clusters developed from high-resolution X-ray fluorescence core scanning. Core-based rock attribute data (e.g., XRD mineralogy, total porosity, and total organic matter content) are used to describe the chemofacies, providing a means to upscale low-resolution rock attribute measurements to high-resolution core-based chemofacies. Supervised core-based chemofacies training data sets are then used with neural network multiclass classification machine-learning tools to train triple combo wireline logs (gamma ray, deep resistivity, bulk density, and neutron porosity) to predict rock facies from wireline logs, providing a new approach to apply core-based facies classifications to wireline log studies. A basin-scale case study that applies this workflow is described for the Third Bone Spring Sand and units of the Wolfcamp Formation in the Delaware Basin of West Texas, United States.

Case Study: Gas Lift-Plunger Lift Combination Creates Full Life Cycle Production Solution

From the Wolfcamp and Bone Spring in the Permian Basin to the Niobrara and Codell in the Denver-Julesburg Basin, lateral lengths of 10,000 ft or greater are becoming the norm in tight-oil resource plays (Rassenfoss 2022; Addison, 2021; S&P 2021). From a production standpoint, longer laterals equate to greater stimulated rock volume per wellbore. That means higher flow rates, but it can also introduce more dynamic behavior and steeper production declines. The extended-well trajectories are often accompanied by high dogleg severities, high gas/oil ratios (GORs), and sand and solids production (Whitfield 2023; S&P 2021). Efficiently accommodating all of these factors while cost-effectively managing natural declines over time can be a challenge for any single artificial lift method. However, the combination of gas lift and plunger lift technology gives operators a flexible option to optimize production beginning with initial peak flow rates at the start of production and extending all the way through to depletion. This “full life cycle” approach encompasses three distinct phases that collectively span the entire slope of the tight-oil well decline curve: - Gas lift in early to mid-life (from first production to ±300 B/D) - Plunger-assisted gas lift (PAGL) in the mid- to late-life plateau (from ±300 to ±100 B/D) - Plunger lift in late life (from ±100 B/D to last oil) An artificial lift approach leveraging gas lift, PAGL, and plunger lift at different points along the production timeline aggregately brings the key advantages of all three to bear in horizontal tight-oil wells, including - Gas lift’s ability to mimic natural reservoir flow, lifting fluids to surface by reducing the flowing tubing pressure and creating differential pressure between the reservoir and wellbore. Gas lift handles an array of production rates (up to 2,000-plus B/D) and well characteristics—including high GORs and solid content—and can adapt to rapidly changing conditions during early well life. - PAGL’s ability to increase reservoir drawdown, stabilize production, and reduce system surging as production diminishes to the point where gas lift starts to become inefficient in the mid-life phase. - Plunger lift’s ability to use pressure buildup below the plunger to carry accumulated fluids to surface at rates as low as a few B/D, requiring no external power source to surface the plunger. The plunger creates a “swabbing effect” as it passes through the tubing that helps draw fluids from perforated intervals while keeping tubing swept of paraffin, scale, asphaltene, sand, etc.

Formation Damage Caused by Wax Deposition Results in Shale Production Decline

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210414, “First Evidence for Shale Production Decline as a Result of Formation Damage Caused by C60+ Paraffin Wax Deposition: A Permian Case Study,” by Amir Mahmoudkhani, SPE, Locus Fermentation Solutions, and Jonathan Rogers and Martin Shumway, SPE, Locus Bio-Energy Solutions, et al. The paper has not been peer reviewed. _ Analysis of production decline curves revealed that three candidate wells in West Texas depleted faster than indicated by a type decline curve, indicating a potentially abnormal permeability-reduction mechanism. A biosurfactant-based squeeze program was recommended and applied in three horizontal wells. The biosurfactant treatment offers an alternative and economical method for remediation of formation damage caused by high‑molecular‑weight paraffin wax deposition in porous media that does not require costly intervention techniques to apply. Introduction The Bone Springs horizontal oil play in the Delaware Basin spans from southeast New Mexico into West Texas. Stacked, multipay reservoirs, each with diverse rock properties, possess upside but also complexity. The initial targets in the play were conventional sandstones. Wells then tapped into carbonate lenses and, ultimately, low-permeability sandstones. As a result of horizontal drilling technology combined with hydraulic fracturing, very thin sands and other facies are now being produced. Generally, reservoir quality of this unconventional hydrocarbon system is controlled by carbonate content, where increased carbonate content typically is associated with lower productivity. Experimental Methods All crude oils exhibited precipitation of organics at ambient laboratory temperatures. Even after storing crudes at the bottomhole temperature of 140°F, a small amount of wax remained insoluble in bulk liquid. Samples of formation drill cuttings were received for various depth intervals between 8,500 and 12,000 ft. X‑ray diffraction analyses of solids revealed quartz as the major mineral phase, with clays and carbonates account for remaining phases. Combined fractions with 160-micron size were used for microcolumn oil-recovery screening tests. Carbon distributions of oils and waxes were performed by high-temperature gas chromatography (HTGC). The Du Noüy ring method was used to measure static surface tensions of biosurfactant solutions at different concentrations and was applied to calculate critical micelle concentrations at ambient temperature. Interfacial tension (IFT) measurements were performed using a drop-shaped tensiometer using the pendant-drop method. Finally, the IFTs of oil in synthetic formation water and in biosurfactant solutions prepared in city tap water were determined. Contact-angle measurements also were performed. The wax-appearance temperature (WAT) of crude and wax samples was determined by the differential scanning calorimetry method. Spontaneous imbibition experiments were performed using the Amott-cell method at reservoir temperature. Berea sandstone core plugs (25×50 mm) with a permeability of 385 md and porosity of 18.4% were used. Core plugs were saturated with homogenized crude oil samples at 140°F for 7 days.

Data-Driven Approach Develops Proactive Chemical Treatment Strategies

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3723425, “Delaware Basin Formational Solid Deposit Trends: A Data-Driven Look at Developing Proactive Chemical Treatment Strategies,” by Rachel W. Hudson, SPE, and Kevin J. Spicka, SPE, ChampionX, and Ryan W. Pagel, SPE, Cooper Gray Consulting, et al. The paper has not been peer reviewed. _ This paper highlights a chemical-treatment strategy developed specifically for solids mitigation for a Delaware Basin operator. More than 200 Delaware Basin solid samples from the New Mexico/Texas state line were collected over a 2-year period, spanning seven distinct producing intervals. A statistical approach was taken to determine which formations had the greatest potential for paraffin, carbonate, acid-soluble iron compounds, and sulfate scales. A similar macroscopic approach in other basins may be applied to identify what proactive treatment strategies could be developed based upon the specific challenges of those regions and may similarly improve field performance. Introduction A need exists for optimized cost-effective solids-mitigation and treatment strategies for oil and gas operators across multiple basins. The key is knowing what type of solids have the greatest potential to form before they precipitate and cause issues within a given system. There is a long-standing history of successful chemical and mechanical treatment strategies for solids in the Midland Basin, but less is known about recent unconventional developments in the Delaware Basin, particularly in the Wolfcamp and Bone Springs formations. The Delaware Basin, located within the Permian, is a series of stacked plays. The Avalon sits above the First, Second, and Third Bone Springs, all of which are Leonard-age strata. These formations sit stratigraphically above the Wolfcamp formations. Each producing interval has similar characteristics that directly affect the risk of solid precipitation. During the last decade, the most-common unconventional targets in the Delaware Basin have been the Avalon, Bone Springs, and Wolfcamp formations, which are the focus of the complete paper. Designing cost-effective proactive chemical or mechanical treatment strategies and optimizing those efforts is a challenging dynamic process. Historically, operators take one of two approaches: treat everything while changing chemical type on an as-needed basis or only treating locations where a problem has occurred in the past. Theory and Methods From experiences recorded across the Delaware Basin, it is clear that some formations have more scale or paraffin issues, but this has all been based on individual field experience in localized areas. For example, it is not uncommon to hear that the Second Bone Springs tends to have paraffin issues. If this is true on a larger scale, then widespread untreated solids-deposit data should be able to indicate which solids are the most probable from each formation. If a pattern can be found in the data, then a proactive risk-mitigation and treatment strategy potentially could be defined by formation. If such a data trend exists, it could provide great value and simplify upfront treatment methodology.

Conodonts and the correlation of the Lower Permian Yeso Group, New Mexico, USA

Across much of New Mexico, the Lower Permian Yeso Group is a thick and complex succession of nonmarine fluvial and eolian, evaporitic coastal sabkha and shallow, restricted to openmarine deposits.Yeso strata have long been assigned a Leonardian age because of their lateral equivalence to Leonardian strata of the Bone Spring Formation in the Delaware Basin of southeastern New Mexico-West Texas. However, Yeso strata have also failed to yield many age-diagnostic fossils.We document the first conodont assemblages from Yeso strata, from the lower part of the Los Vallos Formation of the Yeso Group in the Caballo Mountains of south-central New Mexico. These conodonts represent the Neostreptognathodus clinei-N. prayi Zone of middle Kungurian age. The conodonts from the base of the Los Vallos Formation correlate to a position near the base of the Cathedral Mountain Formation of the Leonardian stratotype and indicate that the LosValles Formation is approximately middle Leonardian in age. This correlation also establishes the age of an extensive marine transgression across much of New Mexico.

Wellsite Real-Time Geochemical and Petrophysical Logging in North America Unconventionals

Hundreds of wells are drilled in North America each year targeting the unconventional resource-rich oil and gas reservoirs across various basins. Each unconventional reservoir has unique and distinct petrophysical and geochemical properties based on reservoir geology and the geological environment of deposition. Unlike conventional drilling and completions, for unconvention-als, traditional logging and evaluation methodologies leave a lot of uncertainities and inconclusive answers to challenging reservoir heterogenities in providing inputs to target selection, well placement, completions and predict production potential. There are various techniques from surface logging methodologies to achieve quantitative results and interpretations. These techniques are non-intrusive and have provided some important and conclusive interpretation in recent years. This article will highlight key formation evaluation techniques that aided operators to drill and complete wells in the Wolfcamp, Bone Spring, Avalon, Spraberry, Woodford, Meramec, Osage, Haynesville, Marcellus, San Andres and Yeso formations.

Investigating Delaware Basin Bone Spring and Wolfcamp Observations Through Core-Based Quantification: Case Study in the Integrated Workflow, Including Closed Retort Comparisons

The Delaware Basin of the greater Permian Basin system has been the focus of continually increased attention in the exploration, appraisal, and development phases of unconventional oil and gas potential over the past decade. While the industry continues to drill horizontal wells for the exploitation of producible hydrocarbon, subsurface disciplines continue to investigate the rock and fluid properties of the stratigraphy through the application of various technological tools. In this study, we focus on five wells spatially covering Loving, Ward, and Reeves Counties in West Texas, where whole core samples were acquired and investigated to compare variations in the Bone Spring and Wolfcamp Formations across varying geological contexts. Samples taken from the whole conventional core were investigated in the laboratory setting, and a series of measurements were acquired on each sample. The laboratory measurements distinguished trends and changes in the rock property volumes (i.e., porosity, saturation, total organic carbon) over stratigraphic intervals. The utilization of nuclear magnetic resonance, as well as acquired geochemical data, allows an innovative approach and application of a correction factor to be applied to the saturation quantification. Integration of geological context with measured laboratory data constraints and petrophysical wireline-log-based interpretation links predictive trends from the defined rock and fluid property distributions and may aid in predicting hydrocarbon vs. water production.

Effects of Overpressure on Mechanical Properties of Unconventional Shale Reservoirs through Novel Use of a Sonic Overpressure Indicator

Summary Overpressure is a common feature among productive unconventional shale reservoirs, such as the Bone Spring (BSPG) and Wolfcamp (WFMP) Formations of the Delaware Basin (DB) of west Texas and southeastern New Mexico, and is thought to be a strong driver of well productivity. Compared with conventional reservoirs and shales in normal pressured conditions, the effects of overpressure on the mechanical properties of shales is not well understood. Here we present an analysis of overpressure in clay-bearing siliciclastic facies of the BSPG and WFMP Formations of the DB and implications for mechanical properties of the reservoir. Estimation of the effects of overpressure on mechanical properties of unconventional shale reservoirs is determined through use of the sonic overpressure indicator (SOPI). The method requires log model results that accurately characterize variations in lithology and porosity for the formations of interest. The SOPI (ΔT/ΔTN)2, where ΔT is the measured compressional sonic transit time, and ΔTN is the forward-modeled result for normally pressured conditions, can be used with elastic moduli and their interrelationships to compare estimates of mechanical properties including Poisson’s ratio ν, the Biot or effective stress coefficient α, and Young’s modulus E, in normal and overpressured conditions. Results presented here are broadly applicable to overpressured unconventional reservoirs that contain significant clay volume (>0.1 v/v) and exhibit low porosity (<0.08 v/v), comparable to that of siliciclastic-rich facies of the WFMP Formation. To account for increased VP/VS ratio, we regard overpressurization of shaly facies as an irreversible thermodynamic process that transforms a normally pressured siliciclastic system. At stress below the yield point, which is taken as the limit of normal pressure, the system responds elastically to stress; beyond this point, during overpressurization, the system responds as an elastic/plastic medium with strain hardening. We regard elastic moduli as descriptive of mechanical energy stored in this system. This perspective enables Poisson’s ratio for the overpressured system νOP to be computed from an estimate of the normally pressured system νN using (ΔT/ΔTN)2. Overpressure also results in a limited increase of the Biot or effective stress coefficient α. Moreover, recognition that overpressure results in a decrease of Young’s modulus, that is, EOP/EN < 1, provides a means of estimating the amount of strain energy stored by the formation due to overpressurization. We believe that when exposed to lower pressures by wellbore construction, this strain energy stored in overpressured unconventional reservoirs drives creep, which affects interpretations made using geomechanical models. We have developed and tested computational models based on biaxial or plane strain for vertical wells and uniaxial strain for horizontal wells that describe how creep likely affects estimation of minimum horizontal stress Shmin and pore pressure from instantaneous shut-in-pressure (ISIP) measurements. Thus, for overpressured unconventional reservoirs, ISIP determinations differ from tectonic Shmin by an amount related to ν and EOP/EN.

Adaptation of Crushed Rock Analysis to Intact Rock Analysis To Improve Assessment of Water Saturation and Fast Pressure Decay Permeability

Summary Legacy crushed rock analysis, as applied to unconventional formations, has shown great success in evaluating total porosity and water saturation over the previous three decades. The procedure of crushing rock into small particles improves the efficiency of fluid recovery and grain volume measurements in a laboratory environment. However, a caveat to crushed rock analysis is that water and volatile hydrocarbons evaporate from the rock during the preparatory crushing process, causing significant uncertainty in water saturation assessment. A modified crushed rock analysis incorporates nuclear magnetic resonance (NMR) measurements before and after the crushing process to quantify the volume of fluid loss. The advancements improve the overall total saturation quantification. However, challenges remain in the quantification of partitioned water and hydrocarbon loss currently derived from the NMR spectrum along with its uncertainty. Furthermore, pressure decay permeability from crushed rock analysis has been reported to have two to three orders of magnitude difference between different laboratories. The calculated pressure decay permeability of the same rock could even vary by several orders of magnitude with different crushed sizes, which questions the quality of the crushed pressure decay permeability. In this paper, we introduce an intact rock analysis workflow on unconventional cores for improved assessment of water saturation and enhanced quantification of fast pressure decay matrix permeability from intact rock. The workflow starts with acquisition of NMR T2 and bulk density measurements on the as-received state intact rock. Instead of crushing the rock, the intact rock is directly transferred to a retort chamber and heated to 300°C for thermal extraction. The volumes of thermally recovered fluids are quantified through an image-based process. The grain volume measurement and a second NMR T2 measurement are performed on post-retort intact rock. The pressure decay curve during the grain volume measurement is then used for calculating the pressure decay matrix permeability. Total porosity is calculated using the bulk volume and grain volume of the rock. Water saturation is quantified using the total volume of recovered water. In addition, the twin as-received-state rocks are processed through the crushed rock analysis workflow for an apple-to-apple comparison. Meanwhile, the pressure decay permeability of the post-retort intact sample is cross-validated against the steady-state gas permeability of the same post-retort sample. The introduced workflow has been tested successfully on different formations, including Bakken, Bone Spring, Eagle Ford, Cotton Valley, and Niobrara. The results show that total porosities calculated from intact rock analysis are consistent with total porosities from crushed rock analysis, while water saturations from the new workflow are an average 8% saturation unit (SU) [0.2 to 0.7% porosity unit (PU) of bulk volume water (BVW)] higher than those from the prior crushed rock workflows. The study also indicates that for some formations (e.g., Bone Spring), the fluid loss during the crushing process is dominated by water; however, for some other formations (e.g., Bakken), the hydrocarbon loss is significant. Pressure decay permeability quantified using intact rock analysis is also confirmed within an order of magnitude of steady-state matrix permeability.

Machine-Learning Approach Optimizes Well Spacing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201698, “Finding a Trend Out of Chaos: A Machine-Learning Approach for Well-Spacing Optimization,” by Zheren Ma, Ehsan Davani, SPE, and Xiaodan Ma, SPE, Quantum Reservoir Impact, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Data-driven decisions powered by machine-learning (ML) methods are increasing in popularity when optimizing field development in unconventional reservoirs. However, because well performance is affected by many factors, the challenge is to uncover trends within all the noise. By leveraging basin-level knowledge captured by big data sculpting, integrating private and public data with the use of uncertainty quantification, a process the authors describe as augmented artificial intelligence (AI) can provide quick, science-based answers for well spacing and fracturing optimization and can assess the full potential of an asset in unconventional reservoirs. A case study in the Midland Basin is detailed in the complete paper. Introduction Augmented AI is a process wherein ML and human expertise are coupled to improve solutions. The augmented AI work flow (Fig. 1) starts with data sculpting, which includes information retrieval; data cleaning and standardization; and smart, deep, and systematic data quality control (QC). Feature engineering generates all relevant parameters entering the ML model. More than 50 features have been generated for this work and categorized. The final step is to perform model tuning and ensemble, evaluating model robustness and generating model explanation and uncertainty quantification. Geology The complete paper provides a detailed geological background of the Permian Basin and its Wolfcamp unconventional layer, an organic-rich shale formation with tight reservoir properties. To find a solution for the multidimensional well-spacing problem in the Permian Basin, multiple sources and types of data were gathered using publicly available sources. The detailed geological attributes, including structure, petrophysics, geochemistry, basin-level features, and cultural information (such as counties or lease boundaries) have been combined in an integrated database to extract and generate features for the ML algorithm. Most attributes are available either in a limited number of wells, mostly vertical, or through the low number of available cored wells across the basin. Therefore, a significant amount of data imputation has been processed with mapping exercises using geostatistical modeling techniques. The mapping process augmented the ML attribute-generation step because these features were distributed in both vertical and lateral dimensions. All horizontal wells within the area of interest across the Permian Basin have been resampled with the logged and mapped information. The geological features also are reengineered into multiple indices to reduce the number of labeled features to include in the ML process. This feature-reduction process also has helped in ranking and selecting the most-important parameters relevant to the well-spacing problem. Here, a key attribute called the shale-oil index was introduced, which is generated for the ML-driven process and is used in understanding the level of contribution of geological sweet spots to well-spacing optimization. In addition, the initial well, reservoir, or laboratory data, including logs, have been normalized before mapping and modeling to eliminate potential bias. This study has focused on Wolfcamp layers; however, both geological and engineering attribute generation work flows used for this practical ML methodology to find optimization solutions for common problems are highly applicable to other unconventional layers, such as Bone Spring or Spraberry.

Progradational slope architecture and sediment distribution in outcrops of the mixed carbonate-siliciclastic Bone Spring Formation, Permian Basin, west Texas

AbstractSediment transport and distribution are the keys to understanding slope-building processes in mixed carbonate-siliciclastic sediment routing systems. The Permian Bone Spring Formation, Delaware Basin, west Texas, is such a mixed system and has been extensively studied in its distal (basinal) extent but is poorly constrained in its proximal upper-slope segment. Here, we define the stratigraphic architecture of proximal outcrops in Guadalupe Mountains National Park in order to delineate the shelf-slope dynamics of carbonate and siliciclastic sediment distribution and delivery to the basin. Upper-slope deposits are predominantly fine-grained carbonate lithologies, interbedded at various scales with terrigenous (i.e., siliciclastic and clay) hemipelagic and gravity-flow deposits. We identify ten slope-building clinothems varying from terrigenous-rich to carbonate-rich and truncated by slope detachment surfaces that record large-scale mass wasting of the shelf margin. X-ray fluorescence (XRF) data indicate that slope detachment surfaces contain elevated proportions of terrigenous sediment, suggesting that failure is triggered by changes in accommodation or sediment supply at the shelf margin. A well-exposed terrigenous-rich clinothem, identified here as the 1st Bone Spring Sand, provides evidence that carbonate and terrigenous sediments were deposited contemporaneously, suggesting that both autogenic and allogenic processes influenced sediment accumulation. The mixing of lithologies at multiple scales and the prevalence of mass wasting acted as primary controls on the stacking patterns of terrigenous and carbonate lithologies of the Bone Spring Formation, not only on the shelf margin and upper slope, but also in the distal, basinal deposits of the Delaware Basin.

Machine learning assisted detection of excess water-producing wells in unconventional shale plays

Excess water production from oil/gas wells drilled in unconventional shale formations of Permian Basin leads to environmental concerns related to the disposal of produced water and also leads to significant expenses in water management programs. In the Delaware Basin, water-to-oil ratios are as high as 10:1 for an oil-producing well. This paper analyzes subsurface data from 20 wells targeting the Bone Springs sands and the Wolfcamp shale formation, which are the primary unconventional-resource targets in the Delaware Basin. The dataset was expanded by adding 53 wells from both the Fort Worth Basin and Gulf Coast Region. For purposes of this study, a data-driven workflow was developed to use 5 well logs from the 300-feet depth interval above or below the kick-off point for each well to detect high water-producing well. The 300 ft of logged data above or below the KOP are divided into six 50-ft intervals. From these banded intervals, 7 statistical parameters were computed for each of the 5 logs. In doing so, 210 features were generated for each well, which were then reduced to most informative 21 features by first thresholding based on p-value and F value, followed by the use of Pearson Correlation. The dimensionally reduced 21 features were used to train classification methods to predict whether a well is a high-water producer (HWPs) and low-water producer (LWPs). Logistic regression performs the best. In Delaware Basin, the prediction performance has a median F1 score of 0.96 and a median Matthew's Correlation Coefficient of 0.92. Median scores for both the Fort Worth and Gulf Coast datasets are above 0.80. For the Delaware Basin, the statistical parameters computed using deep resistivity and porosity logs from the nearest 50-ft band just below the KOP are the most informative features for detecting excess water-producing well.

The Influence of Development Target Depletion on Stress Evolution and Infill Drilling of Upside Target in the Permian Basin

SummaryThe extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. Backed by the data set from the Permian Basin, in this work we present a novel integrated reservoir-geomechanics-fracture model to simulate the spatiotemporal stress evolution and locate the optimal development strategy in the upside target of the Bone Spring Formation. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. Being able to incorporate both pressure and stress responses, the reservoir-geomechanics-fracture model delivers a more comprehensive understanding and a more integral solution of infill-well design in multilayer unconventional reservoirs. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.

Complex Fracture Depletion Model for Reserves Estimations in Shale

Abstract Reserve estimation is a subject of continuous importance in the petroleum industry; controlling field development related decisions and providing valuation of corporations. Tight formations are usually completed with multistage hydraulic fractures and horizontal wellbores. However, these completion scheme results in heterogeneous fracture lengths and spacing. Consequently, some counterparts of the reservoir would experience boundary-dominated flow, while others are still experiencing an infinite-acting linear flow which creates a composite flow regime dubbed as complex fracture depletion (CFD). It is worth noting that the CFD flow regime might be preceded by a linear flow depending on the fracture complexity. We are proposing a unified model that integrates the flow regime analysis and the well performance analysis. Our model utilizes the derivative of the cumulative production with respect to the square root of produced time where the linear flow exhibits a horizontal line and the CFD exhibits an exponential straight line. Therefore, the onset of the CFD becomes the only variable for the regression analysis. Another consequence of utilizing an exponential fit of the flow derivative is a continuous reduction in the Arps’ “b” exponent from a “b” value of two during CFD. We also validated our model estimations to the estimations of Arap’s and stretch exponential production decline (SEPD) with recent production data from the Bone Spring formation, New Mexico, and major shale/tight reservoirs.

Geochemical characterization and classification of crude oils of the Permian Basin, west Texas and southeastern New Mexico

Fifty crude oils from reservoirs ranging in age from Cambrian to late Permian and distributed widely over the Permian Basin were geochemically characterized to assess their stratigraphic interrelationships and provenance. Detailed characterization using stable carbon isotopic composition and biomarker characteristics recognized five genetic groups. Genetic group I oils originate from a type II kerogen, Ordovician marine shale (Simpson Group) source rock deposited under anoxic conditions. Genetic group II oils, believed to be sourced from two kitchens, originate from type II/III kerogen Devonian marine shale (Woodford Shale) source rock deposited under anoxic to suboxic environments. Genetic group III oils are similar in many respects to group II oils. This group, however, shows evidence of significant terrigenous organic matter input. Genetic group III oils, single kitchen–derived oils, are inferred to be sourced from the Mississippian shale (Barnett Shale). Oils of genetic group IV are sourced from two kitchens and generated from the Cisuralian Wolfcamp shale source rock having type II/III kerogen deposited under anoxic–suboxic environments. Group V oils are derived from carbonate-rich shales (marls) of the Cisuralian Bone Spring Formation, having type II kerogen deposited under extremely anoxic environments. With the exception of Devonian- and Mississippian-sourced oils, which occur across a large stratigraphic interval (Cambrian–Ordovician to Permian), the rest of the genetic oil groups occur in close proximity to their candidate source rocks. Although no source rock samples were used in this study, the detailed geochemical study of oils has provided an understanding of the stratigraphic relationships between oils and their inferred source rocks.

Seismic reservoir characterization of the Bone Spring and Wolfcamp Formations in the Delaware Basin: Challenges and uncertainty in characterization using rock physics — A case study: Part 2

The discrimination of fluid content and lithology in a reservoir is important because it has a bearing on reservoir development and its management. Among other things, rock-physics analysis is usually carried out to distinguish between the lithology and fluid components of a reservoir by way of estimating the volume of clay, water saturation, and porosity using seismic data. Although these rock-physics parameters are easy to compute for conventional plays, there are many uncertainties in their estimation for unconventional plays, especially where multiple zones need to be characterized simultaneously. We have evaluated such uncertainties with reference to a data set from the Delaware Basin where the Bone Spring, Wolfcamp, Barnett, and Mississippian Formations are the prospective zones. Attempts at seismic reservoir characterization of these formations have been developed in Part 1 of this paper, where the geologic background of the area of study, the preconditioning of prestack seismic data, well-log correlation, accounting for the temporal and lateral variation in the seismic wavelets, and building of robust low-frequency model for prestack simultaneous impedance inversion were determined. We determine the challenges and the uncertainty in the characterization of the Bone Spring, Wolfcamp, Barnett, and Mississippian sections and explain how we overcame those. In the light of these uncertainties, we decide that any deterministic approach for characterization of the target formations of interest may not be appropriate and we build a case for adopting a robust statistical approach. Making use of neutron porosity and density porosity well-log data in the formations of interest, we determine how the type of shale, volume of shale, effective porosity, and lithoclassification can be carried out. Using the available log data, multimineral analysis was also carried out using a nonlinear optimization approach, which lent support to our facies classification. We then extend this exercise to derived seismic attributes for determination of the lithofacies volumes and their probabilities, together with their correlations with the facies information derived from mud log data.

Seismic reservoir characterization of Bone Spring and Wolfcamp Formations in the Delaware Basin — A case study: Part 1

The Delaware and Midland Basins are multistacked plays with production being drawn from different zones. Of the various prospective zones in the Delaware Basin, the Bone Spring and Wolfcamp Formations are the most productive and thus are the most drilled zones. To understand the reservoirs of interest and identify the hydrocarbon sweet spots, a 3D seismic inversion project was undertaken in the northern part of the Delaware Basin in 2018. We have examined the reservoir characterization exercise for this dataset in two parts. In addition to a brief description of the geology, we evaluate the challenges faced in performing seismic inversion for characterizing multistacked plays. The key elements that lend confidence in seismic inversion and the quantitative predictions made therefrom are well-to-seismic ties, proper data conditioning, robust initial models, and adequate parameterization of inversion analysis. We examine the limitations of a conventional approach associated with these individual steps and determine how to overcome them. Later work will first elaborate on the uncertainties associated with input parameters required for executing rock-physics analysis and then evaluate the proposed robust statistical approach for defining the different lithofacies.

Origin of low salinity, high volume produced waters in the Wolfcamp Shale (Permian), Delaware Basin, USA

The Wolfcamp Shale within the Delaware Basin of West Texas and southeastern New Mexico is one of the largest unconventional oil reservoirs globally and also produces high volumes of relatively low salinity water. In contrast, the overlying Bone Spring Formation and, particularly, the shallower Delaware Mountain Group contain very saline brines. The objective of the study was to assess source and nature of waters produced from the Wolfcamp and to frame them in the larger geological and hydrogeological evolution of the Basin. A total of ~150 produced water samples were analyzed for major and trace element chemistry and isotope data and were complemented by public domain and confidential information. The formation shows a striking total dissolved solids (TDS) distribution with low TDS water samples (<25 g/L) restricted to the basin center that increases up to 100–140 g/L towards the basin margins. Water isotopes (heavy δ18O +5–+8‰ and δ2H -25–-10‰ VSMOW) and low Cl/Br mass ratios (100–200) support the hypothesis that low-TDS waters result from water released during smectite-to-illite conversion. Chemical and isotopic data preclude a meteoric water source and mixing hydraulic fracturing water. Anomalously high Water to Oil Ratios (WORs) in the Wolfcamp Shale (~4) are associated with higher clay content in the target horizon and with low-TDS produced water. These associations are considered causative with the high water cut and low salinity being intrinsically geologic and attributed to the thick (>2 km) mudstone package of Pennsylvanian to lower Permian age, combined with the effects of the Laramide uplift and Neogene tilting of the entire Basin.

Monte Carlo simulation and production analysis for ultimate recovery estimation of shale wells

The current scheme for developing shale reservoirs necessitates special considerations while estimating the reserve. While reservoir characteristics lead to an extended infinite acting flow regime, completion schemes could result in a series of linear flows. Therefore, the initial linear flow does not have to be followed by a boundary-dominated flow. Overlooking this observation leads to unphysical Arps' exponents and overestimations of the Estimated Ultimate Recovery (EUR). We are proposing a workflow to overcome these challenges and honor the inherited uncertainty while using the classic Arps (1956) hyperbolic forecast. Our workflow starts with identifying the current flow regime of the well where two intermediate flow regimes are considered, namely Linear-post-Linear (LPL) and Linear Post Linear Post Linear (LPLPL) flow regimes. We deterministically forecasted the boundary-dominated wells and probabilistically forecasted the rest. We used the distribution of the current flow regime in the field to forecast the transient wells. The well features of the infinite/semi-infinite wells are stochastically sampled from the field database combining well features of the boundary-dominated wells. After that, Monte Carlo simulation is employed to probabilistically estimate the EUR. We constrained the well life by an economical limit or a maximum of 40 years. We selected Bone Springs formation as a field study of this workflow. We found that the LPL is the common current flow regime. A reduction in Arps’ exponent is observed when well experience an intermediate linear flow before boundary-dominated flow. Significant number of interference wells are identified through their Water/Oil Ratio (WOR) signature. We also studied the evolution of EUR which suggests that more than 75% of the production history is needed for the deterministic methods to provide reliable estimates of the EUR. We generated heat maps of the area of interest to summarize the EUR and remaining reserve results.