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Recent research has put extensive focus on the magic of graphene in drilling fluids. Graphene, because of its thermal, electrical, chemical, and mechanical properties, improves mudcake stability and minimizes fluid loss that eventually reduces formation damage. Not all friction reducers are created equal. With dozens of varieties on the market, industry research suggests that oil and gas companies be choosy. Twelve organizations—universities and private technology companies—will conduct research and development on emerging shale plays and technologies covering everything from digital pressure-sensing to smart microchip proppant.
Not all friction reducers are created equal. With dozens of varieties on the market, industry research suggests that oil and gas companies be choosy. Twelve organizations—universities and private technology companies—will conduct research and development on emerging shale plays and technologies covering everything from digital pressure-sensing to smart microchip proppant. It is no secret that drilling fluid is crucial in drilling operations. The main function of drilling fluids is to transport drill cuttings from the bottom of the hole up to the surface.
Twelve organizations—universities and private technology companies—will conduct research and development on emerging shale plays and technologies covering everything from digital pressure-sensing to smart microchip proppant. It is no secret that drilling fluid is crucial in drilling operations. The main function of drilling fluids is to transport drill cuttings from the bottom of the hole up to the surface. Drill cuttings then will be separated on the surface before being recycled back for further drilling. Drilling fluid is subjected to extreme pressure and temperature, and its properties such as viscosity are affected strongly by pressure and temperature.
Fracture conductivity in shale formations can be greatly reduced because of water/rock interactions depending on the properties of formation rock and reservoir/fracture fluids. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration caused by fracture-surface spalling and failed proppant particles. Fracture conductivity is influenced by closure stress, bulk and surface rock mechanical properties, fracture-surface topography, fracture-surface elemental composition, rock mineralogy, and proppant type and concentration, among other factors. This paper presents a study considering several of the aforementioned factors, centered primarily on saline-water-induced fracture-conductivity impairment of the Eagle Ford Shale Formation and its five vertical lithostratigraphic units.
Laboratory experiments were conducted to investigate and quantify the effect of flowback water on fracture conductivity for samples of Eagle Ford Shale. The majority of test samples were obtained from an outcrop in Antonio Creek, Terrell County, Texas, while the remaining samples were obtained from downhole core provided by an industry partner. The different lithostratigraphic units present in the Eagle Ford Shale formation were accounted for. Saline water with a chemical composition similar to that of the typical field flowback water was used.
Fracture-conductivity measurements were conducted in three stages. In the first stage, dry nitrogen was flowed to ascertain the undamaged initial fracture conductivity. In the second stage, the saline solution was injected into the fracture until steady-state behavior was observed. In the third and final stage, dry nitrogen was once again flowed to quantify the recovered fracture conductivity. Reported mechanical properties from the same outcrop-rock samples, consisting of Poisson’s ratio and the Brinell hardness number (BHN), were considered in this study. In addition, reported mineralogy obtained by use of X-ray-diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained by use of X-ray-fluorescence (XRF) microscopy, and fracture-surface topography was obtained by use of a laser surface scanner and profilometer.
Results support findings that bulk and surface mechanical properties influence fracture conductivity, as well as surface topography and related attributes such as fracture surface area. Furthermore, the bulk mineralogical composition of the rock and the elemental composition of the rock fracture surface have a significant effect on fracture conductivity when flowing saline water to simulate flowback. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for the Eagle Ford Formation ranging from approximately 4 to 25% after flowing saline water, compared with the initial conductivity measured by flowing dry nitrogen before saline-water exposure. This is not a large loss in conductivity caused by water damage, and suggests that water damage may not be the major cause of the large early decline rates observed in most Eagle Ford Shale producing wells.
He, Kai (Halliburton) | Xu, Liang (Halliburton) | Lord, Paul (Halliburton) | Lozano, Martin (Colorado School of Mines) | Kenzhekhanov, Shaken (Colorado School of Mines) | Yin, Xiaolong (Colorado School of Mines) | Neeves, Keith (Colorado School of Mines) | Huang, Tao (China University of Petroleum)
As infill drilling practices become more widely used, operators have observed increased well interference or "bashing" in various shale plays wherein the production of mature wells has been significantly impaired by new infilling wells. Notably, some wells have experienced production decrease of approximately 80% as a result of bashing. One possible explanation is the occurrence of hydraulic communication between the old and new wells because they are most likely connected by the newly created or reactivated natural fractures. However, the mechanisms in which hydraulic communication influences production have not been fundamentally studied.
Current technologies, such as pressure-transient analysis or production data mining, do not explicitly provide a physical understanding of the bashing phenomena. This paper discusses a study wherein "Rock-on-a-chip" (ROC) devices were used to investigate hydraulic fracturing fluid invasion and flowback processes. A homogeneous porous network based on the Voronoi tessellation method was patterned on a ROC device. To simulate one aspect of well interference (the impact of an offset well's fracturing fluid entering an existing well's fracture network), two fluid invasion-flowback cycles were performed. It was hypothesized that if the fracturing fluid injected through the new infill enters the fracture networks of existing wells, fracturing fluid would again be forced into the matrix, inflicting damage to the fracture-matrix interface and impairing production.
Test results revealed that water saturations in the ROC after the second flowback were higher than those after the first invasion-flowback cycle, suggesting that the second invasion-flowback cycle could indeed damage the matrix and reduce the relative permeability of the oil. Additionally, surfactant clearly improved the displacement efficiencies in the matrix. One experiment shows that surfactant used in the second invasion-flowback cycle even reduced the damage incurred by the first invasion-flowback cycle. The benefit of surfactant has been observed from field results from the Wolfcamp shale, where it was discovered that the EURs (estimated ultimate recoverys) of wells bashed by surfactant-stimulated offset wells were higher than those bashed by non-surfactant-stimulated offset wells. This study shows that fracturing fluid from offset wells can, in fact, damage the productivity of existing wells through connected fractures. In addition, surfactant, when properly selected, can potentially be used to help reduce damage, or even repair previous damage, caused by well bashing.
Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Hydraulic fracturing is a proven technology that is implemented through injecting highly pressurized water into tight formations. The excessive amount of water use during the process poses serious environmental problems. To address this issue, we propose and study the feasibility of a new fracturing technology utilizing air injection as an alternative fracturing fluid for tight oil and gas reservoirs. Samples from Eagle Ford and Green River formations are selected to study due to their compositional differences; carbonate rich and kerogen rich, respectively. Samples were first characterized with X-ray Diffraction (XRD), Scanning Electron Microscopy (SEM), and Thermogravimetric Analysis (TGA) to determine their mineralogical and organic content. A special core holder was designed to visualize the fracture formation during experiments with X-Ray Computed Tomography (CT). CT scan results were analyzed for fracture formation and propagation during air injection. Experimental results show that the clay content and type during air injection play an important role on fracture formation. It has been found that the alterations in clays at elevated temperatures contribute to keep the formed fracture apertures open due to the cementing behavior of clays at high temperatures. Kerogen was found to also contribute to the formation of microfractures due to its thermal decomposition and the thermal expansion of formed gases at elevated temperatures. Furthermore, the decomposition of inorganic content, especially the carbonate content of shale samples, enhances the fracture formation. Hence, all clay rich, carbonate rich, and kerogen rich shale samples show a trend that favors effective fracturing with air. CT scan results also validate the formation and propagation of these effective fractures, and CT scans taken after one day of the core flooding experiments prove that the fractures remain open even without proppant addition. Because air is an abundant, cheap, and easy to handle injection fluid, it is an attractive alternative to water for fracturing. Our experimental results support the use of air as an alternative fracturing fluid in a promising, feasible, and low cost method for fracturing tight oil and gas reservoirs.
Description of the Material:
The FracFocus chemical disclosure registry provides public disclosure of hydraulic fracturing chemical additives used in nearly 50,000 wells by over 600 companies in the United States. The large number of well sites that have been entered into the registry present a rich population of hydraulic fracturing jobs over a wide geographic area and spanning a period of more than two years. This paper will review the structure of FracFocus and how the system works, discuss industry’s experience in working with the system, and present selected analyses of that data showing how the volume of fluids and the number and type of additives vary by company, by region and play, and even within plays.
ALL Consulting developed and manages the FracFocus database and web site. The company has dedicated considerable resources to assess the quality of the data in FracFocus and convert submittals to a database format. ALL has used the resulting data to analyze a variety of research questions about hydraulic fracturing and related environmental concerns and public disclosure issues.
Results, Observations, Conclusions:
This paper will demonstrate the use of the FracFocus data to investigate a number of questions concerning hydraulic fracturing, including: water use trends across plays, among plays, among companies, and over time; chemical makeup of fracturing jobs, again within and between plays, among companies, and over time; geographic distributions of disclosures (where are submissions being made?); company distributions of disclosures (who is making them?); the use of proprietary or trade secret designations in FracFocus; the use of green chemicals; and whether fracture fluid “recipes” are converging over time within plays or within a given company.
Significance of the Subject Matter:
The analysis of the data from FracFocus can help bring a scientific approach to addressing many of the concerns expressed by the public, NGOs, and regulatory agencies regarding hydraulic fracturing. These issues include: water use; the number and variety of chemicals used in fracturing fluids and the risk associated with them; and how these factors have changed over the two-year history of FracFocus.
As of this date, approximately 5,000 horizontal Eagle Ford wells have been completed in South Texas. Still, geologists and engineers question whether their companies are using the most appropriate operating practices. Side-by-side case studies may show value or not, given the challenge of small sample size and hidden influences on outcome. Multivariate statistical analysis of larger data sets offers sound interpretation across larger geographic areas, with the caveat that correlations need to be scaled to local conditions. The purpose of this paper is to apply multivariate statistical modeling in conjunction with Geographic Information Systems (GIS) pattern recognition work to the Eagle Ford.
The investigation began by acquiring Eagle Ford data using both proprietary and public information. The different data sets were loaded into a common database and put through quality control sanity checks. Production proxies, such as maximum oil rate in the first 12 producing months and normalized 12 month cumulative production, were selected and merged with the other data. Final data sets were then subjected to analysis in both an open-source multivariate statistical analysis and visualization code and a commercial Geographic Information Systems (GIS) application.
Similar to other studies in unconventional reservoirs, integration of the two analysis and interpretation methods highlighted the importance of using well location as a proxy for reservoir quality when working with data sets that lack such measurements. The use of multivariate statistical analysis allowed modeling the impact of particular well architecture, completion, and stimulation parameters on the production outcome by integrating out the impact of other variables in the system.
This work is a continuation of the prior work designed to address well optimization in unconventional reservoirs. It is significant in that it takes full advantage of GIS map-based methods and multivariate statistical methods to capitalize on the volume of data available through the public domain.
Portis, Douglas H. (Pioneer Natural Resources ) | Bello, Hector (Pioneer Natural Resources) | Murray, Mark (Pioneer Natural Resources) | Barzola, Gervasio (Pioneer Natural Resources) | Clarke, Paul (Pioneer Natural Resources) | Canan, Katy (Pioneer Natural Resources)
Four years after the "discovery?? of the Eagle Ford shale play, most operators have shifted their efforts from appraisal and delineation, to full-field development. This commonly involves drilling multiple (three to four) horizontal wells, simultaneously from one common surface location (or pad). Inter-well spacing ranges from 330 - 1000 feet across the trend as industry searches for the optimism well spacing for a range Eagle Ford shale thickness, rock-quality, pressure and thermal maturity windows. Pioneer Natural Resources (PXD) has followed this same transition and routinely drills three well pads with approximately 500 foot spacing between wells, which are completed with "zipper-frac?? treatments. This paper presents a tool-kit designed in-house and currently employed to monitor well interference, communication and pad performance/drainage efficiency. The ultimate goal of this project is to better understand the reservoir response during hydraulic fracture treatments (at 500 foot. spacing) and use these learnings to positively impact the full field development and by achieving an optimum well spacing.
A multidisciplinary technical team has designed an integrated data acquisition "tool-kit?? to address the above issues. Essential to the tool-kit are chemical and radioactive tracers, pumped during the stimulation of one or more wells in a given pad. These data help our interpretation of fracture generation, fracture growth and fluid flow/ proppant placement (i.e. proppant distances, fluid distances, and fracture geometry). Several microseismic surveys also assist in the recognition, quantification and distribution of stimulated rock volume. A major portion of this tool-kit includes the monitoring of pressure communication in offset wells during fracture stimulation and flowback/production. Subsequent interference tests over a period of several months allow for a better understanding of the changes in fracture conductivity and effectively propped fractures.
Collectively, these data are helping refine our geologic model and confirming the significance of attributes extracted from our 3D seismic data-set. We detail design parameters and practical applications of these tools, while discussing pitfalls and learning from project to date. Our findings have implications for development well planning, well spacing and frac-design.