Wolfcamp Shale Research Articles

Multiproxy sedimentary organic matter analysis of the upper Wolfcamp Formation in the Collier-1201 well, southeastern Delaware Basin, Texas

Horizontal drilling and multistage fracturing designs have recently made the Wolfcamp shale horizons a highly sought-after and low-cost oil opportunity at a time of market volatility. One current challenge is that the Wolfcamp shale horizons are unpredictable, especially in acreages with limited well control and seismic data. Sedimentary organic matter (palynofacies) analysis can delineate thermal maturity windows, determine kerogen types, and reflect depositional environments to aid in realizing hydrocarbon potential. We palynologically processed 16 samples at roughly 3 m intervals from the upper Wolfcamp section of the Collier-1201 well in Reeves County, Texas. We examined the prepared microscope slides in transmitted light to quantify (point count) and describe the organic facies in each sample. Additionally, we integrated organic geochemical data to corroborate palynofacies analysis. We classified most of the observed organic matter particles as highly degraded phytoclasts with unidentifiable terrestrial palynomorphs. The palynofacies and organic geochemical data indicate a mixed type-II/III kerogen (oil- and gas-prone materials) characterized by substantial terrigenous input. All samples displayed a high degree of thermal maturity from immense overburden as the Delaware Basin subsided and the overlying beds compacted. The lithologic and organic facies of the studied interval reflect fluctuating proximal marine conditions.

“Dominator Project” Raises Key Questions About Future of Cube Drilling

In Lea County, New Mexico, shale producers drill an average of 10 wells per 640-acre section. But last year, Concho Resources, the third-largest producer of oil and gas in the Permian Basin, decided to push the envelope. The company assembled seven drilling rigs owned by six different contractors and five fracturing fleets on a mile-long tract of land to build the “Dominator Project.” The effort took the better part of a year and, in the end, it delivered 23 wells targeting five individual target horizons in the Wolfcamp Shale formation. The location, in the northern Delaware Basin, was carefully selected for sit-ting atop some of highest-quality geology within one of the highest-producing unconventional plays on the planet. But when executives revealed the first oil production results in July, new doubts were raised about the success of the experiment. They said the well spacing, which averaged a horizontal distance of 230 ft compared with the area average of 600 ft, was “too tight” and that future projects would execute wider intervals. Independently developed type curves show that the Dominator wells are now on pace to fall short of initial estimates, maybe by as much as 45%. The news triggered one of the sharpest selloffs ever seen in the shale business, sending Concho’s share price down 22% for a single-day market value loss of close to $4.4 billion. The sector is now studying the implications that this project will have on the cube developments that are believed to require at least $150–$200 million to execute for the largest such projects. Only the largest operators can afford to take this route and among those are Concho, Encana, Devon Energy, and QEP. Several others, including Callon Petroleum, Pioneer Natural Resources, and Chevron are in transition, according to various reports. As the trend moves forward, questions are being raised about the business model that the cube represents, and how big these developments can be before diminishing returns kick in. Analytics and industry consulting firm Enverus, which just this week changed its name from DrillingInfo, is using a new platform it built for analyzing well spacing scenarios to piece together the lessons learned from the Dominator case study. One obvious takeaway for the firm is that constructing 23 wells in a drilling section is probably too many, at least in the oil window of the northern Delaware. “You now have the upper range,” said Tyler Krolczyk, a petroleum engineer and analyst at Enverus. He noted that Concho’s program mostly involved eight well pads in this area of the Wolfcamp before it jumped to the 23-well Dominator pad. Other operators have averaged just a couple of more wells per pad. “There is a big question mark in between the 10 and 23 wells,” said Krolczyk, citing specifically a dearth of pads in the area drilled out to 16 wells. “I think it would be interesting to get into that middle ground and see what the production number is.”

Surfactant-Assisted Spontaneous Imbibition to Improve Oil Recovery on the Eagle Ford and Wolfcamp Shale Oil Reservoir: Laboratory to Field Analysis

Abundant resources being left behind at the end of the short production life of an unconventional liquid-rich reservoir (ULR) well has inspired many to investigate methods to improve the recovery. ...

A New Technique for Quantifying Pressure Interference in Fractured Horizontal Shale Wells

Summary Pressure communication is commonly observed in fractured horizontal shale wells, particularly at early times when wells are placed on production. In this paper we present a new technique, based on the diffusion exponent from the power-law model, to quantify connectivity in multistage-hydraulic-fractured wells with complex fracture networks. In addition to explaining the theory and analysis techniques, we present examples using measured bottomhole pressure (BHP) from the Permian Basin Wolfcamp Shale that illustrate the utility of this technique to better understand the relationship between completion size, well spacing, and well performance. Using the concept of anomalous diffusion, Chen and Raghavan (2015) developed a 1D, fractional-order, transient diffusion equation to model fluid flow in complex geological media. They showed that anomalous diffusion, which can be caused by heterogeneities in the matrix or the fracture system, exhibits a power-law behavior. In addition to Chen and Raghavan (2015), Acuña (2016) demonstrated that variations in matrix block sizes, fracture conductivity, and drainage shape also exhibit power-law behavior. While the approach from these two studies is somewhat different, they each demonstrated that a generalized power-law model is often more appropriate than traditional linear- or radial-flow pressure-transient analysis techniques for unconventional shale reservoirs. Further, each work shows that the power-law response can be related to some form of heterogeneity in the drainage volume. While traditional techniques for estimating well interference have been previously developed and applied in conventional reservoirs, in this paper we focus on quantifying the magnitude of pressure interference (MPI) in unconventional reservoirs, which commonly demonstrate a generalized, power-law pressure response that is different from radial or linear flow. The examples presented in this paper are for wells from the Permian Basin Wolfcamp Shale. Under the framework of power-law behavior, our technique involves plotting pressure-interference-test (PIT) data in terms of the Chow pressure group (CPG), which enables us to define an indicator of connectivity reflecting temporal and spatial effects. On each test, we derive a diffusion exponent reflective of the MPI. We will show among other things that multiple PITs over time often indicate degrading connectivity between wells. From PIT analyses in Permian Basin Wolfcamp Shale, we were able to establish a relationship between MPI and well spacing. The first example demonstrates analyses of PITs between wells during the production phase and also shows how connectivity between wells diminishes over time. A second example applies the same analysis techniques to quantify interwell connectivity during the post-stimulation phase by analyzing a pressure falloff (PFO) after communication with other wells. A third example illustrates an application of desuperposition to remove the effect of a power-law pressure trend (PT) on interference tests. Techniques to analyze PITs assuming radial or linear flow have been previously developed; however, Raghavan and Chen (2018) showed that apparent radial or linear flow could exist under anomalous diffusion for heterogeneous reservoirs. In this work, we present a technique for analyzing power-law PIT data, which is typical of most horizontally fractured shale wells. This model is a unique approach to understanding flow behavior, quantifying well interference, and analyzing and predicting well performance in unconventional reservoirs. Our examples, which are based on high-quality BHP gauge data, show how this technique could shorten the cycle time for operators to determine the well spacing for a given completion design.

Rate-Transient Analysis Based on the Power-Law Behavior for Permian Wells

Summary In unconventional reservoirs, the application of many rate–transient–analysis (RTA) techniques relies heavily on the identification and analysis of the linear flow regime, which is characterized by a ½–slope on a log–log plot of Δp vs. t. Through our analysis of more than 400 wells with downhole pressure gauges in the Wolfcamp Shale of the Permian Basin, we observed power–law behavior, but with slopes much different from ½ over long periods of time. In many cases, the duration of the straight line with a slope different from ½ lasts for years, without ever converging to ½. In some cases, the slope changes over time but is rarely the characteristic ½–slope observed over long periods. Rate forecasts would be in error if we were to assume that the slope would converge to a ½–slope at a later time. In this work, we present examples of Permian Wolfcamp horizontal wells each with a measured bottomhole pressure (BHP) to demonstrate the characteristic power–law behavior with slopes different from ½. Power–law behaviors are typical in heterogeneous systems and are identified using the Chow pressure group (CPG). On the basis of the concept of power–law behavior, we developed a workflow to analyze single–phase rate–transient data with high–quality measured BHP. Ultimately, the new workflow for RTA uses power–law characteristics to evaluate well performance and is a complementary tool to traditional methods such as the Arps decline–curve analysis (Arps 1945). In this paper, we outline a power–law analysis workflow scheme and demonstrate that the CPG is a convenient means for identifying the exponents of straight lines. In addition, we present case studies to demonstrate the application of this technique to predict the long–term well performance from choked–back wells, to evaluate long–term performance changes associated with offset fracture hits, and to estimate the hyperbolic–decline–curve b–factor.

Study Uses Wellbore, Reservoir, Fracture Models To Determine Productivity

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190860, “Evaluating the Impact of Lateral Landing, Wellbore Trajectory, and Hydraulic Fractures To Determine Unconventional Reservoir Productivity,” by Piyush Pankaj, Priyavrat Shukla, SPE, Ge Yuan, and Xu Zhang, Schlumberger, prepared for the 2018 SPE Europec featured at the 80th EAGE Annual Conference and Exhibition, Copenhagen, Denmark, 11–14 June. The paper has not been peer reviewed. Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. This paper demonstrates the need to couple the wellbore model to the reservoir-simulation and hydraulic-fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity. The authors aim to demonstrate and deconvolute the well-trajectory plan with an integrated parametric study that helps to improve well productivity. Methodology To plan a well profile, two critical pieces of information are required: Lateral landing depth, and well trajectory originating from the landing depth. To reach the targeted landing depth, the well trajectory undergoes a certain buildup of curvature deviating from the vertical section and, eventually, when the landing depth is reached, the designed trajectory profile is maintained and continued for the horizontal wellbore. The authors evaluated well trajectory and well productivity on the basis of the effect of the following parameters to guide well-trajectory planning: Hydraulic-fracturing fluid Natural fracture network Wellbore trajectory, undulations, toe up, toe down, or combinations Production operations such as proppant flowback, fracturing choke management, and well shutdown Geological Review of the Model A 3D earth model in the Permian Basin for the Wolfcamp shale was used to develop a work flow for determining well landing and well trajectory. The Wolfcamp shale covers most of the Midland Basin and ranges in thickness from 200 ft in the north of the basin to 2,600 ft in the south. The entire play is dominated by a fine-grained, naturally fractured source rock. The depths range from 5,500 to 11,000 ft. The Wolfcamp is slightly overpressured, with the pressure gradient varying between 0.55 and 0.70 psi/ft. In the past few years, the Wolfcamp has become one of the most profitable and exploited unconventional plays in the US. Almost all of the operators are collecting a significant share of their well inventory, which yields over 1,000 BOPD routinely in initial-production rate. The production declines within a short period (6 to 9 months). The recovery factors remain in the single digits for most operators. The Wolfcamp, Spraberry, and Bone Spring formations are the most prolific in the basin. Defining Landing Depth The proposed solution considers applying an end-to-end cycle of a streamlined work flow that starts with sampling engineered landing location points in the geomodel defined by the user on the basis of reservoir-quality (RQ) cutoffs. The first step is building the geological model around the sweet spot. This geological model contains petrophysical and mechanical properties of the rock along the depth of the targeted interval.

Conodont and fusulinid biostratigraphy of the Strawn Group (Desmoinesian, Middle Pennsylvanian) and lower part of the "Wolfcamp Shale" (Missourian-Virgilian, Late Pennsylvanian) in the northern Midland Basin, West Texas

Conodont and fusulinid biostratigraphy of the Strawn Group (Desmoinesian, Middle Pennsylvanian) and lower part of the "Wolfcamp Shale" (Missourian-Virgilian, Late Pennsylvanian) in the northern Midland Basin, West Texas

A strain based approach to calculate disparities in pore structure between shale basins during permeability evolution

We test the permeability response of Marcellus shale and Wolfcamp shale under changing strain. While magnitude of strain for a given stress is determined predominantly through mineral composition, the response of transport properties to a given strain are dependent on pore density, pore geometry, and rock fabric/mineral distribution around pores. We characterize the differences between the two shales using bulk mineralogy, SEM imaging with elemental analysis, and the cubic law for permeability evolution. We find that the Marcellus shale is comprised predominantly of clays that leads to more deformation when stressed than the Wolfcamp shale which is composed predominantly of quartz and calcite. The level of creep and compaction are directly related to the amount of clay in each shale sample. A novel result of our study is a strain-driven model to capture permeability evolution in shale due to differences in pore structure.

Regional appraisal of shale resource potential within the Permian, Anadarko and Arkoma basins: how does the Alpine High stack up?

Abstract The Alpine High on the southwestern fringe of the Delaware sub-basin in the Permian Basin (Figure 1) is an emerging unconventional fairway with shale resource potential. In 2016, an operator drilled a series of exploration and appraisal wells on the Alpine High, targeting the stacked resource interval comprising the Woodford, Barnett and Wolfcamp shale plays (Apache Corporation, 2017). All three plays have been successfully developed elsewhere in Texas and/or Oklahoma, but were previously untested on the Alpine High. There are more than 4500 wells targeting the Woodford in the Anadarko and Arkoma basins, more than 24,000 wells targeting the Barnett shale in the Fort Worth Basin and more than 16,000 wells targeting the Wolfcamp in the Delaware and Midland sub-basins of the Permian Basin (Rystad Energy, 2018). The distribution of the wells targeting these shale plays is shown in Figure 1. Initial well results and production tests on the Alpine High are reported to have been promising (Apache Corporation, 2017) and, as a result, the Alpine High is regarded as a highly prospective, but largely untested, unconventional fairway.

Reservoir-on-a-Chip Technology Opens a New Window Into Oilfield Chemistry

With its ability to replicate little slivers of reservoir rocks, microfluidics is giving the oil and gas industry a new way to capture images of interactions between chemicals and hydrocarbons. The biggest advantage this emerging technology holds over more established research tools is that it can capture the images at all. “You actually see what it looks like when the oil, water, and chemistry all interact, and that means we are making direct measurements of the performance characteristics,” explained Stuart Kinnear, the chief executive officer of Interface Fluidics. The Edmonton, Alberta-based startup of just 3 years is generating increasing interest among operators and suppliers that want independent reviews of whether particular production-enhancing chemicals will work inside a reservoir as advertised. The work places it amid a small group of firms trying to take microfluidics from its native home in the biomedical sector and into the oil field. Interface Fluidics’ innovation is a type of microfluidic chip that is etched from a postage-stamp-sized strip of silicon and glass to form what it calls a “reservoir analogue.” Depending on the inputs, such as data obtained from rock samples or even industry literature, a blank chip can in a matter of a few hours be turned into a tiny duplicate of a porous sandstone from Alberta or the nanodarcy pathways of the Permian Basin’s Wolfcamp Shale. So far, more than 20 different types of formations have been replicated for projects involving heavy-oil extraction, hydraulic fracturing fluid analysis, and enhanced oil recovery (EOR) for shale. “We can also copy-and-paste to make a hundred or a thousand copies if you wanted to,” added Kinnear, highlighting another advantage that microfluidics offers over relying solely on analysis of real rock samples: repeatability. Thanks to the chip-making process, “you know the only thing you are changing run to run is the chemistry.” To simulate reservoir-like conditions, the chips are heated, pressurized, and loaded with samples of the crude and water from the look-alike’s actual field. Videos taken as chemicals are introduced reveal how the medley of fluids mobilize around the artificial pore structures and get oil flowing, or not. Kinnear described this element as the technology’s “killer app.” Because each chip is transparent on one side, a microscope-mounted camera can be used to document experiments with high resolution. Prized by first-adopters, the recordings explain what drives flow behavior, e.g., phase trapping, wettability modification, solids deposition, or emulsion. First Adopters See Wide Applicability For at least one chemical maker, that window into porosity has become a critical tool for validating its own emerging technology, a new line of nanosurfactants tailored for shale reservoirs. “The visual aspect is something we’ve never had before, and that really helps us understand what’s going on,” said Bill O’Neil, the research director at ChemTerra Innovation, the chemical subsidiary of Calgary-based service provider Trican Well Service. Its pilot with Interface Fluidics, details of which were published in March (SPE 189780), resulted in the company moving forward with a significantly larger study that is still underway.

How Close is too Close? Well Spacing Decisions Come With Risks

There is no formula for properly spacing wells in unconventional plays. When a reservoir consultant recently described conversations with clients about how many wells they could drill per acre, it sounded like a doctor advising a patient considering back surgery. “I am not trying to tell you what your spacing should be,” said Miles Palke, management senior vice president for Ryder Scott, adding that the modeling and production history matching his company offers is “a process to help you inform your decision.” The cautious approach was understandable in his talk at the recent SPE Hydrocarbon Economics and Evaluation Symposium. Well-spacing decisions are increasingly tricky because of the potential downsides, from damaging hits to older parent wells to production from new child wells falling short of the old wells. A recent technical paper authored by Schlumberger (SPE 191799), based on data from the Wolfcamp shale play in the Permian’s Delaware Basin, found that when a new well is drilled within 1,000 ft of an older well, the older parent well outperformed the child well 66% of the time. When the results were adjusted for the bigger, more expensive completions now common, 79% of the older wells performed better. It is getting harder to avoid the issue of well spacing. In its recent earnings call with investment analysts, Schlumberger said that 70% of the wells drilled in the Eagle Ford are infill wells, as are 50% of those wells drilled in the Permian. While there is a lot of agonizing about fracs hits when wells are closely spaced, wider spacing also has its risks. Schlumberger predicted that even when the wells are 2,000–2,500 ft apart, the parent wells perform better 61% of the time when the production was adjusted for the larger volumes of proppant per foot now commonly used. As wells get farther apart, there is a growing chance that productive rock in between will never be stimulated. Well interactions are a constant reminder that fracturing does not create networks of producing fractures shaped like shoe boxes that can be lined up neatly on a shelf. Fracturing the maximum volume of a reservoir requires dealing with the contact that comes when wells with irregularly shaped fracture networks are located side by side. “People talk about well interference and bring it up as if it is a bad thing,” said Erdal Ozkan, SPE’s reservoir technical director. The petroleum engineering professor at Colorado School of Mines added that overlapping production “has always existed between two wells in the same field. There will be interference. If you reduce the drainable area, you reduce productivity of each well.”

A Data-Analytics Tutorial: Building Predictive Models for Oil Production in an Unconventional Shale Reservoir

SummaryConsiderable amounts of data are being generated during the development and operation of unconventional reservoirs. Statistical methods that can provide data-driven insights into production performance are gaining in popularity. Unfortunately, the application of advanced statistical algorithms remains somewhat of a mystery to petroleum engineers and geoscientists. The objective of this paper is to provide some clarity to this issue, focusing on how to build robust predictive models and how to develop decision rules that help identify factors separating good wells from poor performers. The data for this study come from wells completed in the Wolfcamp Shale Formation in the Permian Basin. Data categories used in the study included well location and assorted metrics capturing various aspects of well architecture, well completion, stimulation, and production.Predictive models for the production metric of interest are built using simple regression and other advanced methods such as random forests (RFs), support-vector regression (SVR), gradient-boosting machine (GBM), and multidimensional Kriging. The data-fitting process involves splitting the data into a training set and a test set, building a regression model on the training set and validating it with the test set. Repeated application of a “cross-validation” procedure yields valuable information regarding the robustness of each regression-modeling approach. Furthermore, decision rules that can identify extreme behavior in production wells (i.e., top x% of the wells vs. bottom x%, as ranked by the production metric) are generated using the classification and regression-tree algorithm. The resulting decision tree (DT) provides useful insights regarding what variables (or combinations of variables) can drive production performance into such extreme categories.The main contributions of this paper are to provide guidelines on how to build robust predictive models, and to demonstrate the utility of DTs for identifying factors responsible for good vs. poor wells.

Hydrocarbon saturation in upper Wolfcamp shale formation

Water saturation (Sw) and hydrocarbon saturation (Shc=1-Sw) estimates in hydrocarbon-bearing formations are generally derived from Dean-Stark core measurements, NMR log, and electromagnetic (EM) logs, such as induction log, galvanic resistivity (laterolog), or dielectric dispersion logs. In-situ estimation of hydrocarbon saturation in conventional reservoirs primarily rely on the deep-sensing or high-resolution EM logs. However, in the hydrocarbon-bearing shale formations, hydrocarbon saturation estimates obtained from EM logs tend to be unreliable. Conventional EM-log-interpretation models tend to break down for shale formations because they neglect the interfacial polarization effects and the dispersive behavior of EM properties of such geomaterials. This can be addressed by jointly processing the subsurface galvanic resistivity, induction, propagation and dielectric dispersion logs using an integrated model that accounts for the interfacial polarization mechanisms.One galvanic resistivity (laterolog) and dielectric dispersion logs, comprising 4 conductivity and 4 dielectric permittivity logs measured at four distinct frequencies, were acquired in a 520-feet depth interval of a well drilled in the upper Wolfcamp shale formation. We implement a novel log interpretation technique for the improved estimation of water saturation (Sw), brine conductivity (Cw), textural index/cementation exponent (m), and saturation exponent (n) in the upper Wolfcamp shale. Log processing was performed with an integrated mechanistic model, which combines Complex Refractive Index (CRI) model to analyze the conductivity and permittivity logs acquired at 1 GHz, Stroud-Milton-De (SMD) model to analyze the 3 conductivity dispersion and 3 permittivity dispersion logs in the frequency range of 10 MHz to 0.3 GHz, and Waxman-Smits (WS) model to analyze the deep galvanic resistivity log (RLA5) measured by the EM laterolog tool at 1 kHz.In the upper Wolfcamp shale, estimates derived from the joint inversion were robust in the presence of pyrite, low water saturation, and low porosity as compared to estimates from the inversion of only four-frequency dielectric dispersion logs. Formation brine conductivity and saturation-exponent estimates are more reliable compared to water saturation and cementation exponent estimates. Water saturation estimates obtained using the proposed methodology are compared against those obtained using multi-mineral inversion and those derived using CRIM model. Average relative errors in fitting the 1 laterolog resistivity and 8 dielectric dispersion logs using the estimates obtained from the proposed method are 10% and 20%, respectively, and their extreme values are 55% and 60%, respectively, in the 520-ft depth interval of the upper Wolfcamp shale formation.

Investigation of asphaltene deposition mechanisms during CO2 huff-n-puff injection in Eagle Ford shale

ABSTRACTIn this study, laboratory tests were conducted to investigate the asphaltene deposition mechanisms during CO2 huff-n-puff injection in an Eagle Ford shale core using Wolfcamp shale oil. The permeability reduction due to asphaltene deposition by mechanical plugging and adsorption mechanisms were determined using the n-Heptane and toluene reverse flooding, respectively. The results showed that 83% of the total permeability reduction is due to asphaltene deposition by mechanical plugging mechanism, while 17% of the total permeability reduction is due to asphaltene deposition by adsorption mechanism. The critical interstitial velocity for entrainment of asphaltene deposition was around 0.0008 cm/sec.

Experimental and numerical study of permeability reduction caused by asphaltene precipitation and deposition during CO2 huff and puff injection in Eagle Ford shale

The permeability reduction associated with asphaltene precipitation and deposition in gas injection EOR processes has been widely observed and well-studied in conventional plays. In our previous research, such permeability reduction due to asphaltene deposition during gas huff and puff injection process in shale core plugs were observed. In this study, experiments were conducted to investigate the permeability reduction caused by asphaltene deposition in shale core samples during the CO2 huff and puff injection process. A dead oil sample from a Wolfcamp shale reservoir was used. A core scale simulation model was built up to mimic the huff and puff injection process in the experiment and the parameters for the asphaltene deposition in shale were obtained by matching the experimental oil recovery and permeability reduction data. The asphaltene precipitation and deposition process during the CO2 huff and puff injection experiment are discussed in details based on the simulation results.Experimental results showed that severe permeability damage was caused by asphaltene during CO2 huff and puff injection (e.g., 48.5%), especially in the first cycle (e.g., 26.8%). Analysis of the experiments using simulation approach show that oil recovery factor reduction starts right after the beginning of CO2 huff and puff injection and the effect of asphaltene deposition on oil recovery factor accumulated during the later cycles. The asphaltene deposition was mainly formed in the near surface area of the core plug. As the CO2 concentration is quickly increased in the first cycle and more oil is near the rock surface in the first cycle, asphaltene precipitation and deposition were most significant during the huff period in the first cycle compared with the subsequent cycles. In the puff period of the first cycle, asphaltene precipitation is quickly decreased, as CO2 flow back. In addition, although oil in the inner blocks continuously flows to the outer blocks during the puff period, due to the extremely low permeability of the core plug, the amount of oil is small and this oil has already experienced the asphaltene precipitation process during the previous huff period, very small amount of increase in the asphaltene deposition occurs during the subsequent puff periods.

Improving oil recovery in the Wolfcamp unconventional liquid reservoir using surfactants in completion fluids

Well performance after stimulation in unconventional liquid reservoirs (ULR) can be enhanced by altering rock wettability, and by moderately reducing interfacial tension (IFT) using surfactants in completion fluids. However, ULR lithology plays a major role in surfactant selection due to rock-fluid interactions having direct impact on oil recovery. This experimental study evaluates and compares the efficiency of different groups and blends of surfactants on recovering liquid hydrocarbons from siliceous and carbonate Wolfcamp shale cores by analyzing the effects of lithology, oil and surfactant type on wettability and IFT alteration, and their impact on imbibition and oil recovery.ULR wettability was determined by contact angle (CA) experiments, and its alteration was evidenced when adding surfactants to completion fluids. The results showed that at field-used concentrations, all tested surfactants altered wettability from oil and intermediate-wet to water-wet. These findings were consistent with zeta potential results when assessing surfactant solution film stability on siliceous and carbonate shale rock surfaces as an indication of water wetness. In addition, IFT between crude oil and completion fluids was measured to gauge IFT reduction by surfactants, showing higher reductions by anionic surfactants compared to nonionic and blended surfactants. Finally, imbibition potential for completion fluids with and without surfactants was tested in spontaneous imbibition experiments. Oil recovery from Wolfcamp shale cores was tracked in real time, and CT scan technology was simultaneously used to monitor frac fluid penetration in ULR cores. The results showed that cores submerged in completion fluids with surfactant additives have higher hydrocarbon recovery and better fluid imbibition than those in frac fluids without surfactants. In addition, siliceous shale cores had higher oil recovery and fluid penetration when anionic surfactants were used. Conversely, carbonate shale cores showed better hydrocarbon recovery and penetration when submerged in nonionic-cationic surfactants. Hence, it can be concluded that the addition of surfactants to completion fluids improved oil recovery by wettability alteration and IFT reduction, and core lithology, oil and surfactant type impacted fluid imbibition and oil recovery and should play a major role on surfactant selection. These findings give important understanding for designing completion fluid treatments and flowback schedules for these ULR.

Relative permeability estimates for Wolfcamp and Eagle Ford shale samples from oil, gas and condensate windows using adsorption-desorption measurements

Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate relative permeability of aqueous and hydrocarbon phase in shales by processing the low-pressure nitrogen adsorption-desorption isotherm measurements. The interpretation method is applied to 35 samples from various maturity windows of Eagle Ford and Wolfcamp shale formations. The method assumes that effective medium theory, percolation theory, and critical path analysis can quantify the biphasic fluid transport in shales.The relative permeability curves were estimated for samples collected from 100ft interval in Eagle Ford gas window, 30ft interval in Eagle Ford oil window, and 60ft interval in Wolfcamp condensate window. Although the samples exhibit large variations in organic content, pore connectivity, range of connected pore network, and pore complexity, the relative permeability curves estimated for these samples exhibit relatively similar trends. Samples from gas and oil windows were low temperature plasma ashed to study the effects of removal of organic matter on relative permeability and pore network characteristics. The relative permeability of aqueous phase decreases sharply with decrease in water saturation, whereas the relative permeability of hydrocarbon phase decreases at a relatively slow and constant rate with increase in water saturation. Relative permeability estimates for the shale samples explain the low water-cut during hydrocarbon production, absence of correlation between hydrocarbon production decline and the increase in water production, and the existence of permeability jail in shale reservoirs.

Nanopore confinement effects on phase behavior and capillary pressure in a Wolfcamp shale reservoir

As unconventional oil production is the main focus in petroleum industry, the phase behavior of fluids in nanopore media draws high attention nowadays. The extremely small pore sizes in shale reservoirs affect the fluid phase equilibrium. In this study, the phase equilibrium of Wolfcamp oil in nanopores is studied by coupling the cubic Peng–Robinson equation of state (PR-EOS) with the Young–Laplace capillary pressure equation, fugacity of vapor–liquid calculation, and shifted critical properties. A mercury injection experiment showed that 93.7% of pore diameters in Wolfcamp cores were less than 10nm. The capillary pressure curve in a real shale reservoir with a multicomponent Wolfcamp oil was generated for the first time. The results show that the bubble point pressure was suppressed by 17.3% when the pore radius (r) is 10nm, and by 63.8% when r is 1.5nm. The interfacial tension (IFT) decreases slowly when r is bigger than 50nm. However, as r becomes smaller, the IFT decreases rapidly, especially when r is less than 10nm. The nanopore confinement narrows the two-phase region, resulting in a lower capillary pressure and elongating the lower gas–oil ratio production period.

Effect of the Injection Pressure on Enhancing Oil Recovery in Shale Cores during the CO2 Huff-n-Puff Process When It Is above and below the Minimum Miscibility Pressure

In CO2 injection, there is a minimum miscibility pressure (MMP) above that CO2 can be miscible with oil, so that oil recovery will be high. This paper is to investigate the effect of the injection pressure on enhanced oil recovery in shale oil cores under huff-n-puff CO2 injection, when the pressure is above and below the MMP. We first estimated the MMP for a Wolfcamp oil using slimtube tests. The slimtube test results showed that the estimated MMP for the CO2–Wolfcamp crude oil system was about 1620 psi at 104 °F. After that, we conducted 15 CO2 huff-n-puff experiments using three different Wolfcamp shale cores at pressures below and above the MMP. These pressures were 1200, 1600, 1800, 2000, and 2400 psi. Each huff-n-puff test has 7 cycles. The huff-n-puff experiments for three cores showed that, below the MMP, the injection pressure had a significant effect on enhancing oil recovery. Higher than the MMP, the increased pressure further increased the oil recovery until the injection pressure was about 20...

Experimental study of permeability reduction and pore size distribution change due to asphaltene deposition during CO2 huff and puff injection in Eagle Ford shale

AbstractMany laboratory and simulation studies regarding gas injection enhanced oil recovery method in shale reservoir have been performed and shown good results. However, one problem not investigated is the asphaltene precipitation and deposition problem. In conventional reservoirs, the permeability reduction caused by asphaltene plugging and adsorption has been observed and well studied. In shale reservoirs, the deposition, if any, will be more critical.In this work, experimental studies were conducted to investigate the effect of asphaltene deposition on the pore size reduction and permeability reduction in shale core samples during the CO2 huff and puff injection process using a dead oil sample from a Wolfcamp shale reservoir. A decrement of pore with a diameter size in the range from 100 to 800 nm and an increment of pore with a diameter size smaller than 100 nm were observed after 6 cycles of CO2 huff and puff injection. The result indicates the existence of pore plugging and asphaltene adsorption during the gas injection process. The experimental results also showed a 47.5‐nD permeability reduction after 6 cycles of CO2 huff and puff injection. Compared with the original permeability of the shale core, 126 nD, the permeability reduction is more than one‐third of the original permeability. © 2017 Curtin University of Technology and John Wiley & Sons, Ltd.