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Kazak, Ekaterina S. (Skolkovo Institute of Science and Technology, Lomonosov Moscow State University) | Kazak, Andrey V. (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Bilek, Felix (Dresden Groundwater Research Centre)
The research goal is the development of a novel integrated solution of formation water content and salinity determination for petrophysical characterization. The workflow relies on three techniques: evaporation method (EM) with isotopic composition analysis, analysis of water extracts, and cation exchange capacity (CEC) study. The EM offers a fast, efficient, and accurate measurement of the residual water content with breakdown into free and loosely clay-bound types. The isotopic composition reveals the origin and genesis of pore water. The chemical analysis of water extracts delivers a lower bound salinity in terms of NaCl. CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks.
A representative collection of rock samples is formed based on the petrophysical interpretation of well logs for a complex tight gas reservoir rock of the the Bazhenov formation (West Siberia, Russia). The evaporation method employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, XRD. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δ18O and δD. A modified alcoholic NH4Cl method provides CEC and exchangeable cations concentration of the rock samples with low carbonate content.
The target rock samples contained residual formation water 0.11–4.27 wt.%, including free 0.04–3.92 wt.% and loosely clay-bound water 0.09–0.96 wt.%. The loosely bound water content correlates well to the clay mineral fraction. The estimated pore water salinity reached tens of grams per liter; the corresponding isotopic composition indicated the deep formation genesis and generally correlated to that of the deep stratal waters of West Siberia. The amount of chemically bound water fell in a range of 0–6.40 wt.% and exceeds that of free and loosely bound water. The isotopic composition proved the formation origin of the extracted pore water samples. CEC falls in 1.5–4.73 cmol/kg and depends on the clay content.
The study made a qualitative step up towards the quantitative characterization of formation water in shale reservoir rocks. Research effort delivered an integrated workflow for reliable determination formation of water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs, as well as general reservoir characterization and reserves estimation. The research novelty is in using a unique suite of laboratory methods adapted for tight shale rocks with the initial water content of less than 1 wt.%.
Ali, Safdar (W.D. Von Gonten Laboratories) | Barnes, Colton (W.D. Von Gonten Laboratories) | Mathur, Ashish (W.D. Von Gonten Laboratories) | Chin, Brian (W.D. Von Gonten Laboratories) | Belanger, Chad (W.D. Von Gonten Laboratories)
Techniques such as horizontal drilling and hydraulic fracturing have helped in exploitation of unconventional shale reservoirs. However, a drawback of hydraulic fracturing is that it results in forced imbibition of frac-water into the pore system of the organic shale matrix. This can potentially result in lower productivity emanating from water blockage of oil-wet and oil-bearing nano-pore networks. This paper introduces a laboratory setup to investigate and quantify the damage to oil permeability caused by invasion of fracturing fluids in shales. The proposed process also allows for testing the impact of altering completions fluids chemistry (fresh versus produced water, surfactants, friction reducers, etc) on oil productivity.
The technique starts with carrying out micro-CT and NMR scans on as-received shale plug samples to evaluate sample condition and fluid saturations. These samples are then humidified and then saturated with either produced crude, after which a subsequent NMR scan is done to track oil and water saturation. For the permeability measurement, the samples are then loaded in an overburden cell, some of which are made of non-ferrous material and can be loaded in the NMR spectrometer. The sample is brought to reservoir stress conditions by increasing overburden stress and pore pressure gradually. The initial steady state permeability measurement is measured by injecting produced crude or hydrocarbon gases at a constant flow rate using a pump and monitoring pore pressures for stability. The downstream pressure is controlled by a back-pressure regulator.
Once steady state flow is established and the baseline effective hydrocarbon permeability is measured, a brine or a fracturing fluid solution is injected into the sample from the downstream side (frac face) for a specified time period. The completion fluid injection pressure is typically about 1000 psi to 2000 psi higher than the upstream oil pressure to simulate hydraulic fracturing induced imbibition of water. Then, to mimic shut-in that follows hydraulic fracturing of a stage, the upstream and downstream valves are closed for about 12 to 24 hours. Finally, hydrocarbon permeability is measured again as was done initially, to quantify degradation of deliverability due to water imbibition. Saturations of hydrocarbon fluid and brine in the sample are calculated using NMR T2 and T1T2 scans either during the test or right after the test is complete. In some instances, the saturation front of the hydrocarbon fluid or injected brine is examined using 2D and 3D gradient NMR scans.
These tests can be conducted at high pressure and temperature, while the setup that involves continuous NMR scanning of the plug during the core flooding process is rated to 10,000 psi for overburden pressure, 9000 psi for reservoir pressure and 100 C for reservoir temperature [Mathur et al. 2020]. Permeabilities as lows as 5 nano-Darcies can be measured. Varying completions fluids chemistries (salinity alteration, KCl, surfactants, FRs, etc) can also be used in the setup to evaluate the benefit or lack thereof in minimizing permeability damage.
On average, a decrease of 70% in hydrocarbon productivity is observed on comparing initial permeability and final permeability after water damage. As a validation of the water block phenomenon, samples have also been injected with decane and diesel from the bottom and little to no damage in hydrocarbon productivity is observed. Some scenarios of adding surfactant mixtures to the frac water, as well as cyclic gas injection have shown initial positive results; and are active areas of study.
Landry, Christopher J. (Center for Subsurface Engineering and the Environment, The University of Texas at Austin) | Hart, Bruce S. (Western University) | Prodanovic, Maša (The University of Texas at Austin)
In this paper we develop and test an SEM-based methodology for quantifying the porosity of clay-rich shales (argillaceous/siliceous mudstones) from broad-ion beam scanning electron microscopy (BIB-SEM) images of drill cuttings. SEM energy-dispersive x-ray elemental mapping was used to identify ’clay rich’-dominated cuttings for analysis. Multiple high-resolution SEM image mosaics are segmented for porosity quantification using a novel image segmentation algorithm developed for SEM images. Drill cuttings were also analyzed for mineralogy and grain density down to a depth of approximately 11,000’.
In the absence of direct porosity measurements of shale from the cuttings, we compare the SEM-based porosity measurements to sonic- and density-log derived porosity estimates that were defined using industry-standard approaches. We also show that the porosity values based on image analysis compare favorably to a simple point counting based porosity measurement from the same images. The wireline log-based porosity vs. depth profile shows a familiar exponential decline in porosity from 4000 to 12000’. However, the SEM-based porosity values for depths of 6840’ to 11070’ are nearly invariant.
Our results suggest that porosity loss through mechanical compaction is effectively complete in shales by a depth of 6500-7000’ (~2 km). The continued decreasing log-based porosity with depth might be due to mechanical and chemical compaction other types of rocks (e.g., shaley siltstones, thinly interbedded sandstones and shales) that are interlaminated and interbedded with the clay-dominated rocks at scales of microns to dm. Observations such as these help us to better understand the process of shale/silt/sandstone compaction and diagenesis, both as shale overburden and reservoir.
The development of unconventional resources typically entails drilling through several thousand feet of overburden. Information about pore pressures, porosity, lithology, and other parameters in that section can be required to drill through it safely and efficiency. For financial and logistical reasons, the overburden shales are very seldom cored for physical-property analyses. If the overburden is overpressured, then retrieving intact core for physical-property analyses can be challenging.
Song, Yilei (China University of Petroleum) | Song, Zhaojie (China University of Petroleum) | Guo, Jia (China University of Petroleum) | Feng, Dong (China University of Petroleum) | Bai, Baojun (Missouri University of Science & Tech) | Liu, Yueliang (China University of Petroleum)
The nanopore confinement plays an important role in fluid phase behavior and transport. However, investigation of the confinement effect on fluid phase behavior and production performance is lacking in the petroleum industry. Conventional models need to be adjusted to account for nanopore confinement in both phase equilibrium and fluid transport. The objective of this study is to put forward an efficient model to fill this gap and to evaluate the production performance of shale oil reservoir.
In this work, the phase equilibrium of Bakken oil is investigated using an adsorption-dependent Peng-Robinson equation of state (A-PR-EOS) coupled with fugacity calculation, capillary pressure calculation, and shifted critical properties. The shifted critical properties can be described by the A-PR-EOS. The bubble point pressure and black-oil properties at different pore sizes are calculated and compared. In addition, the phase behavior calculation results are coupled with the reservoir simulator to evaluate the nanopore confinement effect on the production performance in the Bakken shale reservoir. Results in nanopores show that the bubble point pressure is depressed due to the confinement effect. In the two-phase region, solution gas-oil ratio and oil formation volume factor increase, and oil viscosity decreases as the pore size reduces. In the single-phase region, solution gas-oil ratio and oil formation volume factor in nanopores is the same as those in bulk, while the oil viscosity still decreases as the pore size decreases. The cumulative oil and gas recovery in Bakken reservoir will be enhanced if considering the nanopore confinement. This work provides an improved understanding of the confinement effect on the fluid phase equilibrium and production performance in shale oil reservoirs.
As unconventional hydrocarbons, shale oil and gas are enormous energy resources (EIA, 2016). Great success has been achieved to produce shale reservoirs. However, our understanding of the phase and flow behavior of shale reservoir fluids is still very limited (Salahshoor et al. 2018). Phase behaviors and properties of reservoir fluid and their effects on flow behavior play a key role in the production processes of both conventional and unconventional reservoirs (Song et al. 2020c). Thus, more efforts may be needed to better understand the phase and flow behavior of confined fluids in shale reservoirs.
Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment’s eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for fracture initiation from perforated wells relative-to-the-wellbore (longitudinal or transverse). These criteria were numerically assessed and found to overvalue transverse fracture initiation, which takes place under a narrow range of conditions when the rock formation’s tensile strength is lower than a critical value and the breakdown pressure falls within a "window."
A robust three-dimensional numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence numerically-deriving correction factors for the closed-form approximations. Geomechanical inputs from the Barnett Shale in Texas are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The numerically-corrected expressions can predict fracture initiation pressures for a specific orientation of fracture initiation (longitudinal or transverse). Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study (normal faulting regime), perforations on the side of the borehole yield both a wider breakdown pressure window and a higher critical tensile strength by 32.5%, compared to perforations on top of the borehole. Leakage of fracturing fluid around the wellbore reduces the breakdown pressure window by 11% and the critical tensile strength by 65%.
Dimensionless plots are employed to present the range of
During fracturing, pressure responses are often observed in a nearby offset monitor well as hydraulic fractures propagate from the treatment well towards the monitor well. These pressure responses can be caused by, (a) purely poroelastic interactions between the treatment and monitor well fractures, (b) a combination of poroelastic interaction and hydraulic connection between the fractures (mixed response) or (c) massive direct frac-hits from the treatment into the monitor well fractures. In this work, we demonstrate an automated pattern recognition workflow to systematically identify and interpret the different types of pressure responses observed in field data from the Permian Basin.
An automated pattern recognition workflow based on Python scripting has been developed that parses field offset well pressure data during fracturing from multiple wells, stage-by-stage, in each well. The script develops overlay-plots containing treatment and monitor well pressure for each stage, which can be stored in a directory of the user’s choice (for future reference). The script then automatically determines the magnitude of pressure response as well as the type of pressure interference - "purely-poroelastic", "mixed" [poroelastic + hydraulic] or "direct frac-hit" - and the output is automatically stored stage-by-stage in a user-friendly text delimited (".txt", ".csv" or ".xlsx") format while the script executes. In addition, the script can also calculate the fracture azimuth based on relative distance between interacting stages and the magnitude of the observed pressure response.
In case of a purely poroelastic response, pressure fall-off is observed in the monitor well as soon as the nearby treatment well is shut-in (Seth et al., 2019a). This is an important distinction between purely poroelastic responses and other types of pressure responses where a pressure increase is observed even after the nearby treatment well is shut-in. The magnitude of pressure response also varies with the type of pressure response. Typically, purely poroelastic pressure responses range between 1-100 psi (sometimes higher) depending upon the distance and overlap between the interacting fractures, whereas mixed pressure responses range between 10s-100s of psi. Direct frac-hits usually cause a massive increase in the offset monitor well pressure (100s-1000s of psi) and are relatively easy to spot visually as they disrupt the pressure response trend.
It is crucial to correctly identify and interpret the type of pressure interference observed in field offset well pressure data before using this data for further analysis (such as fracture geometry estimation). This work details the different types of pressure responses typically observed in field data and provides guidelines on identifying and characterizing these responses correctly. In addition, the demonstrated automated workflow introduces a novel tool to systematically parse and characterize field offset well pressure data efficiently and calculate fracture azimuth based on magnitude of observed pressure response and distance between the interacting stages.
Well spacing and optimization has been one of the industry’s biggest challenges over the past few years. The time component of spacing in fracture-driven interactions, via parent and child well relationships, add an additional layer of complexity on top of just understanding how far apart to spacing nearby horizontal wellbores. This study uses geological, engineering, and operational attributes alongside well spacing variables to understand fracture-driven interaction productivity impact and to discuss methods to minimize the associated productivity risks.
Ahead of understanding all engineering and operational variables, i.e. proppant and fluid volumes, a robust well spacing dataset is generated. The underlying assumptions for this dataset will be discussed in detail. Well spacing will be calculated across vertical, horizontal, and true distances for neighboring wells within a half-mile horizontal radius. Distances will be calculated for the nearest neighbors. By incorporating the element of time, distances will also be calculated separately for parent, child, and co-completed wells within the same search radius.
The Wolfcamp A has been the most predominately targeted horizon within the Delaware Basin. Therefore, this study focuses on the Wolfcamp A. Within the basin, the hydrocarbon windows vary from black oil to wet gas. Fracture-driven interactions can vary by fluid composition; therefore, the study breaks up the Wolfcamp A separately across the different hydrocarbon windows for further analysis. Regional type well grouping can further delineate the basin. This is done across a variety of geological components such as depth, thickness, and log properties. Certain areas within the same hydrocarbon window can have different results when modeling degradation due to varying geology.
Binning well spacing distances versus productivity can identify a range-bound spacing interval to model productivity degradation. By incorporating geologically defined areas, the combination should indicate spacing optimization and tactics to minimize developmental risks. Co-completing wells with no nearby parents have had much higher productivity results than child wells that we also co-completed. This can limit parent and child risks considerably and sometimes actually allow for a tighter well spacing program before degradation appears. Down spacing developments and child well degradation risks can have drastic implications on an assets net value. Being able to accurately model degradation factors alongside different spacing development strategies can optimize productivity, which is paramount in our difficult current commodity and valuation market.
With signs of the shale boom slowing, the need to make informed decisions on asset development becomes increasingly critical in a competitive landscape. Yet the data for informed decision making is often spotty, particularly with regards to one of the industry’s greatest hurdles: maximizing stimulated reservoir volume with minimal investment. For many, the problems that underpin this hurdle are clear: improper well spacing, frac hits/stress shadowing, unsuitable connectivity between benches, and interwell interference/communication all well-established contributors to poor productivity and a non-ideal stimulated reservoir volume (SRV), a definitive strategy for the "best" way to develop different plays has not proven as obvious.
One area that has seen sustained interest is the SCOOP/STACK play of the Anadarko basin. Since 2012, this geological region has proven one of the lowest-cost, highest margin plays in the U.S. With multiple stacked reservoirs, the effective stratigraphic trap of the area creates a continuous petroleum system with multiple development opportunities. In this study, non-radioactive liquid chemical tracers were pumped alongside stimulation treatments for dozens of wells placed in the Woodford, Meramec, and Osage layers. These tracers served to uniquely "tag" downhole oil and water phases, allowing the operator to quantitatively track the production of oil and water as well as their point of origin. On an individual level, these liquid tracers served as an effective production log, measuring changes in behavior over time. On a field level, however, the application of liquid tracers made it possible to evaluate bench-to-bench communication and the effect different completion designs had on interwell communication/interference. Multiple variables were considered, including the effect of geological features, frac order, well spacing, and parent pump-in protection to achieve an optimal completion strategy. This work shares many of the high-level lessons learned, providing a beneficial ROI by rapid fine-tuning of well spacing based on ongoing tracer communication over time.
Evaluation of reservoir rocks often starts with the measurements of total porosity. Total porosity reported by laboratories depends on several factors including the effective pressure during the measurement. In unconventional shales, several studies have demonstrated the existence of an additional effective stress due to capillary forces. While previous studies have shown that the additional effective stress due to capillary forces affects the elastic properties of unconventional shales, its effect on total porosity has not been studied. Our paper presents the results of an experimental investigation of the impact of capillary forces on total porosity measurements in unconventional shale reservoir samples.
For the purpose of this study, 7 samples were collected from an oil producing unconventional shale reservoir located in the Permian Basin. These samples were characterized by measurements of their mineralogy and TOC. To evaluate the impact of capillary forces on total porosity measurements, NMR T2, helium porosity, mass, and relative humidity measurements were conducted on the shale samples at water saturation values ranging from 100% to 10%. The combination of NMR and helium porosity was used to assess total porosity while NMR and gravimetric methods were used to determine water saturation. Capillary pressure at every water content was computed using the relative humidity data.
The analysis of the collected data shows that the additional effective stress due to capillary forces can be as large as 10,000 psi for water saturations lower than 20%. This compressive stress can reduce the total porosity by 13%. The reduction in total porosity could be responsible for some of the discrepancies observed between total porosity and water saturation values reported by different laboratory protocols. Porosity determination methods that require samples in dry conditions could underestimate the total storage capacity of the reservoirs.
Shale reservoirs are organic rich, fine-grained sedimentary rocks with a significant fraction of pores in the nanometer size range (Bustin et al. 2008, Sondergeld et al. 2010). The nanometer sized pores of shale reservoirs can induce capillary pressures values in excess of 10,000 psi for a gas-water system (Kale et al. 2010, Sondhi 2011, Donnelly et al. 2016). Capillary pressure is the pressure required to displace a wetting fluid by a non-wetting fluid and can be computed with Equation 1:
There are many recent efforts on fracture mitigation to ensure competitive infill wells. While operators are trying to overcome asymmetrical fractures caused by existing primary wells, there is also a continuous effort to evaluate the quality of the fracture surface area for the infill wells. SPE 199686-MS covered passive frac mitigation using water to pre-load two Upper and two Lower Wolfcamp primary wells in the Midland Basin. The goal of the study is to determine the success of the pre-load trial by studying the infill well created fractures. We accomplished this using diagnostic plots such as Volume to First Response (VFR), Instantaneous Shut-in Pressure (ISIP), Rate Transient Analysis (RTA) and by characterizing the number of fractures using fracture-type diagnostics. Shear fractures maximize the fracture surface area (FSA) of the well; tensile fractures have limited FSA. Tensile fractures are also a characteristic of asymmetrical fractures, and these, are the types of fractures found in well-to-well communication.
The passive frac mitigation method and initial production results are covered in SPE 199686-MS. The team recorded second by second pressure data with pre-loaded and offset shut-in primary and infill wells. Time was synchronized to absolute reference time to properly assign the origin of fracture driven interactions (FDIs) as they occurred. By use of frac treatment pressure data, the team was able to determine the number of shear and tensile fractures. Then during flowback, the team compared production results per well with the estimated number of resulting shear fractures. For other co-developed infill wells in the same bench, the team also compared the number of shear fractures to determine if frac mitigation technique of preloading aided in maximizing the number of shear fractures.
The team found correlations between the number of tensile fractures measured and location of FDIs. VFR plots confirmed frac-frac connections during the higher-magnitude FDIs. Most interestingly, "low" FDI pressures of 50 -100 psi size were responsible for most of the frac to frac communication. RTA linear flow parameter (LFP), also known as (equation), showed correlation with both VFR and the number of shear fractures.
Incorporating the fracture type in evaluating fracture mitigation techniques provides another dimension to understanding and determining success of the infill well. In our study, frac mitigation using pre-load is not just preventing asymmetrical fractures, but also aiding the maximum FSA created. Production and RTA results confirm that the number of shear fractures and differentiating fracture types are valid metrics. Targeting the right type of fracture during completion when making "on-the-fly" completion modifications may be an important role in frac mitigation.