Bian, Changrong (Sinopec Exploration & Production Research Institute) | Zhang, Dianwei (Sinopec Exploration & Production Research Institute) | Shen, Feng (GeoReservoir Research) | Wo, Yujin (Sinopec Exploration & Production Research Institute) | Sun, Wei (Sinopec Exploration & Production Research Institute) | Li, Jingliang (GeoReservoir Research) | Han, Juan (GeoReservoir Research) | Li, Shuiquan (GeoReservoir Research) | Ma, Qiang (Sinopec Exploration & Production Research Institute)
Delineating geometry of natural fractures realistically and understanding fracture stress sensitivity help to optimize well placement and well spacing design in shale gas reservoirs. This paper presents a methodology for building 3D hybrid discrete natural fracture network (DFN) models and using an analytical model to assess reactivation potential of natural fracture in the Longmaxi shale, Sichuan Basin.
Small-throw faults and natural fractures ranging from seismic scale to well scale in shale reservoirs have important effects on the success of horizontal drilling and hydraulic fracturing. Seismic geometric multi-attributes at different resolution scales are used to classify seismic facies according to the degree of fracturing. Small-throw faults are delineated using seismic facies and validated against drilling data. We develop a discrete natural fracture network (DFN) model at the seismic scale by meshing fracture lineaments tracked from an enhanced curvature attribute. Fracture topologies are used for fracture connectivity analysis to build local fracture networks along and around the horizontal wellbores. Diffuse fractures at the small scale are modeled with curvature attributes and well data analysis under the constraint of the seismic facies. The analytical model incorporates fracture properties and geomechanical model to describe the deformation of natural fractures due to hydraulic fracturing. Fracture stress-sensitivity are assessed based on changes of fracture volumes under different stress conditions. Characterized reactivated local fracture networks at different scales along the horizontal wells are used to map out volumetric extent of zones with potential to develop tensile and shear deformation during hydraulic fracturing. Available microseismic data from the hydraulic fracture stimulation of the reservoir is used to validate the fracture models.
Our stress sensitivity analysis indicates that reactivation potential of natural fractures varies considerably, mainly depending on natural fracture size and orientation, rock mechanical properties and anisotropy of horizontal stresses. DFN models reveal that fracture concentrations are correlative with the footprint of observed microseismic events. Comparison of 3D natural fracture models with the microseismic event distribution shows that vertical variation of fracture properties in the laminated shale reservoir adds complexity for fracture propagation.
A case study is used to illustrate the efficiency of the methodology. Fracture models at different scales and associated fracture stress-sensitivity can be used as a predictive tool for locating new wells and completion design in shale gas reservoirs.
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
Morales, Adrian (Chesapeake Energy Corp.) | Holman, Robert (Chesapeake Energy Corp.) | Nugent, Drew (Chesapeake Energy Corp.) | Wang, Jingjing (Chesapeake Energy Corp.) | Reece, Zach (Chesapeake Energy Corp.) | Madubuike, Chinomso (Chesapeake Energy Corp.) | Flores, Santiago (Chesapeake Energy Corp.) | Berndt, Tyson (Chesapeake Energy Corp.) | Nowaczewski, Vincent (Chesapeake Energy Corp.) | Cook, Stephanie (Chesapeake Energy Corp.) | Trumbo, Amanda (Chesapeake Energy Corp.) | Keng, Rachel (Chesapeake Energy Corp.) | Vallejo, Julieta (Chesapeake Energy Corp.) | Richard, Rex (Chesapeake Energy Corp.)
An integrated project can take many forms depending on available data. As simple as a horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations, to a large scale seismic to simulation workflow. Presented is a large-scale workflow designed to take into consideration a vast source of data.
In this study, the team investigates a development area in the Eagle Ford rich in data acquisition. We develop a robust workflow, taking into account field data acquisition (seismic, 4D seismic and chemical tracers), laboratory (geomechanical, geochemistry and PVT) measurements and correlations, petrophysical measurements (characterization, facies, electrical borehole image), real time field surveillance (microseismic, MTI, fracture hit prevention and mitigation program through pressure monitoring) and finally integrating all the components of a complex large scale project into a common simulation platform (seismic, geomodelling, hydraulic fracturing and reservoir simulation) which is used to run sensitivities.
The workflow developed and applied for this project can be scaled for projects of any size depending on the data available. After integrating data from various disciplines, the following primary drivers and reservoir understanding can be concluded. At a given oil price, optimum well spacing for a given completion strategy can be developed to maximize rate of return of the project. Many operators function in isolated teams with a genuine effort for collaboration, however genuine effort is not enough for a successful integrated modelling project, a dedicated multidisciplinary team is required.
We present what is to our knowledge, one of the most complete data sets used for an integrated modelling project to be presented to the public. The specific lessons from the project are applied to future Eagle Ford projects, while the overall workflow developed can be tailored and applied to any future field developments.
When combined with relatively mature subsea production technologies (see subsea chapter on well systems, manifold, pipeline, power and control umbilical, and so on), it can reduce development cost, enhance reservoir productivity, and improve subsea system reliability and operability. Over the period from 1970 to 2000, millions of dollars have been spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry has not rushed to deploy the technology on a commercial basis. However, as the industry moves into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, making small fields economically viable and large fields even more profitable. Subsea processing refers to the separation of produced ...
Many oilfield processes normally employed on the surface may be adapted to downhole conditions. Sometimes the design specifications for downhole processes may be looser than surface processing because control is more difficult. Partial processing, in which fluids are separated into a relatively pure phase stream and a residual mixed-phase stream, are most common. Downhole separation technology is best suited for removing the bulk (50 to 90%) of the gas or water, with downstream surface or subsea equipment being used to "polish" the streams for complete separation. In the case of gas separation, even with complete separation downhole, dissolved gas will evolve from the liquid phase as the pressure drops when the oil flows to surface.
Malpani, Raj (Schlumberger) | Alimahomed, Farhan (Schlumberger) | Defeu, Cyrille (Schlumberger) | Green, Larrez (MDC Texas Energy) | Alimahomed, Adnan (MDC Texas Energy) | Valle, Laine (MDC Texas Energy) | Entzminger, David (MDC Texas Energy) | Tovar, David (Schlumberger)
As well density in a section increases, drilling and completions decisions regarding the stimulation of infill wells are increasingly informed by changes in the in-situ stress, mechanical properties, and material balance that result from depletion around parent wells. This is a multifaceted reservoir-dependent four-dimensional problem with many different dependencies. Accordingly, projects involving parent-child interactions during the completion phase are carefully planned using sound engineering principles to avoid negative effects of depletion and fracture hits. We present a case study from a section development in the Wolfcamp formation. Multiple wells drilled at various times are chronologically described below:
1) Parent well in the middle of the section – generation I
2) Child well 1 to the western edge of the section (2 months after parent well) – generation II
3) Child well 2 to the eastern edge of the section (2 months after child well 1) – generation II
4) Child well 3A between parent well and child well 1 (6 months after child well 2) – generation III
5) Child wells 3B, 3C, and 3D (drilled from the same pad) between parent well and child 2 (6 months after child well 2) – generation III
All wells but child 3D are in the same horizon. Downhole and surface gauges were installed on all observation wells during the completion infill wells (child 3A, 3B, 3C, and 3D). Water injection treatment was performed on the existing wells (parent, child 1, and child 2) wells prior to completing generation III infill wells. Child well 3A was completed first to build up pressure on the west side of the section. Child wells 3B, 3C, and 3D were from same pad on the surface and were zipper fractured. Design changes were made to the completion program with contingencies built-in to make additional changes on the fly to incorporate field geometry control aids and reduction to injection rate and fluid volume.
The parent well experienced fracture hits during completion of child 1 and child 2, spaced at ~2,500 ft. Chemical tracers and production behavior suggested that even a few months of production led to pressure reduction in the section. During completion of child wells 3A, 3B, 3C, and 3D, multiple pressure increases were observed on the parent and child 2 wells with varying degree of severity, but no fracture hit. The stress buffer (shadow) created by carefully sequencing the stimulation program aided in reducing the fracture communication. The fluid injection strategy was effective in reducing the magnitude of pressure communication. Additionally, an active pressure-monitoring program and real-time design changes were able to prevent fracture hits.
The tracer data and productivity index (PI) profile suggest that during stimulation, wells have been hydraulically connected; even though the connections fade over time, results in overall of lowering of reservoir pressure. Some sections do show abnormal behavior likely due to localize geological features. The initial PI for the child 3A, child 3B, and child 3C is smaller than that of the parent well, like child 1 and child 2 wells. All wells in Wolfcamp A shows similar PI profile after all the wells were put back on production, except for child 3A. Child 3D well (Wolfcamp B) has higher PI than other generation III wells pointing to no or minimal communication between the two formations. The infill wells (generation III) have increased water cut than the existing wells (generations I and II). Child 3D well is in Wolfcamp B, which has higher water saturation as compared to Wolfcamp A in the area.
Wells with spacing above 1,000 ft show equivalent productivity, but wells less than 500 ft apart show inferior productivity. The optimum well spacing with the general completion and stimulation design in the area seems to be within 500 ft to 1,000 ft (5 to 10 wells in a section) in this area in Wolfcamp A. The results also suggest that hydraulic connectivity from Wolfcamp B to Wolfcamp A but the production seems to be isolated from Wolfcamp A. Developing a section with depletion effects occurring at various distances and durations is challenging. Our proactive approach of designing, monitoring, and responding provides insights into the development of multigeneration wells in the Wolfcamp formation and in similar settings around the world.
Bryndzia, L. Taras (Shell International Exploration and Production) | Hows, Amie M. (Shell International Exploration and Production) | Day-Stirrat, Ruarri J. (Shell International Exploration and Production) | Nikitin, Anton (Shell International Exploration and Production) | Huvaz, Ozkan (Shell International Exploration and Production)
The Permian Delaware Basin (DB) is one of the most desirable regions for production of unconventional oil in the United States. While extended horizontal wells, stimulated with hydraulic fracturing, can recover economic volumes of oil in the DB, this production is often associated with large volumes of water. Relatively high water-oil ratios (WORs) can erode the value of producing wells. This of course begs the questions: where is the water coming from and why is so much being produced?
This study shows that the produced waters (PWs) are primarily in-situ Wolfcamp shale formation water and not water associated with hydraulic fracturing or well completions. This conclusion is based on the observation that the Wolfcamp shale formation water has an oxygen isotopic composition of ~6.5 ± 0.5 ‰ (SMOW) and a salinity of ~23 kppm. These oxygen isotopic data and salinities are consistent with illite-water equilibrium at peak burial conditions.
However, in some areas of the DB, PWs have much higher salinities (~50-125 kppm). The PWs also have a characteristic geochemical fingerprint of highly radiogenic 87/86Sr ratios of ~0.7085-0.7095. The source of this highly radiogenic strontium is believed to be the Salado salt in the overlying shallow Ochoan evaporites, with 87/86Sr of ~0.7090-0.7095. Dissolution of the Ochoan evaporites and salt is the likely source of high salinity brines in Guadalupian and Leonardian age sands and silts within the DB. These high salinity PWs are mixtures of Wolfcamp formation water and dissolved Ochoan evaporites and salt that infiltrated deep into the DB during uplift of the western edge of the DB. Uplift was closely related to the formation of the “Alvarado Ridge”, beginning at ~20 Ma, with peak uplift at ~7 to 4 Ma, creating conditions hydrologically favorable for ingress of the high salinity brines deep into the DB.
Due to the high illite content in the Wolfcamp shale, the shale-silt interface likely behaved as a clay membrane. Differences in salinity (up to ~100 kppm) between shales and sands/silts created gradients in ion and water activity (aw) across the interface. These gradients resulted in the diffusion of ions from high salinity sands/silt (low aw) into adjacent shales with high aw and low salinity. Where shales have not equilibrated with high salinity sands/silts, the water saturation (Sw) in the Wolfcamp shale would remain high and the resultant WOR would also be high. The ion diffusion model predicts co-current flow of oil and water out of the shale. This may explain why oil production in the DB produces so much water.
Flotron, Alyssa (Kansas Interdisciplinary Carbonates Consortium [KICC], University of Kansas) | Franseen, Evan (Kansas Interdisciplinary Carbonates Consortium [KICC], University of Kansas) | Goldstein, Robert (Kansas Interdisciplinary Carbonates Consortium [KICC], University of Kansas)
Controls on deposition and reservoir quality of mixed unconventional carbonates and siliciclastics are not adequately understood. This project explores the Wolfcamp ‘A’ (early Leonardian) in Howard County, TX to determine what stratigraphic and sedimentologic controls lead to areas with the best reservoirs.
Core, thin section, XRD, TRA, and rock-eval pyrolysis data were used to analyze sedimentary facies and rock properties. Core observations were used to calibrate facies to 1122 well logs, which were used to correlate the Wolfcamp A internal stratigraphy across an area of 3637 km2. Facies distribution and thickness were mapped in each stratigraphic package to analyze controls on distribution of high and low reservoir-quality sediment gravity flow (SGF) facies.
Out of 11 lithofacies, the dominant facies assemblages are coarse-grained packstone-floatstone-rudstone (CGC), fine-grained calcareous mudstone-wackestone (FGMW), and siliceous mudstone-siltstone (SMS). CGC facies have sharp, locally erosive surfaces, rip-up clasts, are massive or have internal grading, suggesting deposition from SGFs. The dominance of detrital quartz, lack of radiolarians, rarity of shallow-water skeletal fragments, and massive or normal graded laminations suggest SMS and FGMW were deposited as SGFs with a separate siliciclastic (SMS) or carbonate slope (FGMW) source. SMS facies have the best unconventional reservoir potential, with total porosity ranging from ~6-10%, TOC of 2-3.2 wt%, and low clay content (<50%).
Six regionally identifiable major units show progradational and compensational geometries, and each pair of major units has wedge-on-wedge relationships. The lowest two major units are CGC-rich, the middle two are characterized by SMS facies, and the upper two contain all three facies assemblages. The three major units that are thickest proximally are lobe-shaped and sourced from between the Eastern Shelf and Glasscock “nose” with internal units downlapping basinwards. The other three major units are thickest distally and laterally with internal units onlapping proximally and, with some exceptions, are mostly sourced from the Eastern Shelf and Glasscock “nose.”
The results suggest CGC facies were commonly deposited during high relative sea level whereas most SMS and FGMW facies were deposited during low relative sea level. Notch-like features in the slope acted as foci for SGFs. Promising sweet spots of greatest thickness and SMS prevalence are in the middle pair of major units and located near a northeast-southwest trend of thick SMS deposition situated medially. The distribution of those sweet spots is predictable by mapping paleotopographic funneling mechanisms, and understanding how relative sea level controls facies distribution and how paleotopography controls sediment dispersal and geometries. These controls are broadly applicable across areas of the Permian Basin.
With the better understandings of well performance mechanisms from unconventional reservoirs and maturing technologies in drilling and completion, the industry has started realizing there could be significant potential value in those reservoirs. Improper development may leave significant resources unrecovered and significant value unrealized. The full field development concepts such as “tank” or “cube” developments are being implemented in the Permian Basin to maximize the asset value from developing those reservoirs. The paper first summarizes our analysis results of three full field developments implemented by three operators in the Northern Midland, and the paper presents optimal full field development plans (FDPs) in the Southern Midland Basin with our systematical workflow.
After we systematically review the main drivers of completion designs on the well performance and recovery efficiency, we then focus on a case history study we performed to compare the field development plans implemented by three operators in the same geologically similar area, including the well spacing and placement patterns, well completion designs, completion efficiency analysis, and corresponding well performance. We also performed long-term production forecast and economic analysis for those three field developments. Inspired by the outcome of the case history study, we then developed a systematic way (workflow) to optimize FDPs for any given unconventional reservoir.
The paper will illustrate the application of our workflow into the Wolfcamp formation in the Southern Midland Basin. We first build the numerical reservoir performance models based upon geological and reservoir properties, and calibrated those models with completion and well production history; We then assembled 155 different FDPs by combining different vertical and lateral well spacings and multiple completion designs; Next, we used those calibrated models to study the resource recovery and economics from those FDPs. Finally, we performed a sensitivity analysis of well cost structure and completion efficiency on the asset development values of those FDPs, from which an optimal FDP was proposed.
Based upon those two case studies, we observed that there is a sweet spot for well spacing and corresponding well completion design to maximize development value for a given reservoir. The study results also demonstrate that sub-optimal completion designs and well spacings could leave significant resource and values behind. Our study indicates that the drilling and completion cost structure and operation efficiency are very critical to realize potential value. Those two case studies show that the operator economic key driver, (such as Rate of Return Vs Net Present Value), will drive very different full field development decisions.
We are utilizing our workflow to study the optimal full field plan in the Delaware Basin. The workflow can be easily applied to optimize full field development plans to maximize the asset value for any unconventional reservoir, which may also minimize the number of pilot tests and parent-child well situations.
Total organic carbon (TOC) as measured by laboratory techniques from core historically has been used to assess the quality of source rocks. Now, TOC measurements are widely used to help evaluate unconventional reservoirs/resource plays and to more optimally target and design lateral wells to achieve maximum productivity. This paper describes a method to estimate TOC from wireline logs and visualize its distribution across the entire Delaware Basin.
Hydrocarbon exploitation in the Delaware Basin is currently focused on the Wolfcamp and Bone Spring Formations, however proven productive zones occur in the stratigraphic section from the overlying Delaware Mountain Group to the Ordovician Ellenburger. Known regional source rocks throughout the section include the Ordovician Simpson, Devonian Woodford, Mississippian Barnett, and potential local sources in the Pennsylvanian, Permian Wolfcamp and the Avalon shale member of the Bone Spring. To gain insight into the basin's petroleum systems, we describe a convenient approach to comparatively view source richness and distribution estimates from a basin-wide perspective.
Traditional sample based methodology uses TOC datasets from laboratory measurements that are displayed by plotting and contouring TOC values on a 2D map. This may be appropriate for thin homogenous shale formations, but for thicker heterogeneous source beds maps offer little flexibility in viewing and analyzing the data. More recently, petrophysical methods to derive TOC from wireline logs have been proposed and tested in several basins globally (eg Passey et al., 1990 & 2010, Issler et al., 2002). Those methods were not easily applicable here, the Passey method because of abundant calcite in the sediments and the need for good thermal maturity control, and the Issler method because of the general paucity of good quality sonic log coverage in the Delaware Basin.
Our project derived a petrophysical model to estimate TOC through the Bone Spring and Wolfcamp by calibrating ~1900 core measured TOC values from 57 wells to wireline curves. A calculated TOC curve was generated for each lithostratigraphic unit as appropriate using RHOB as the primary input (continuous DT curves were sparse in the wells with sample data). GR and borehole rugosity cutoffs were applied to constrain the calculation. The model was then applied to 872 wells across the basin and interpolated to provide a 3D volume of estimated TOC. The calculated curves and 3D model were QC'd visually and semi-statistically and found to be a reasonable match to the core data, given the methodology