Researchers mapped 251 faults in the North Texas home of the Barnett Shale, the birthplace of the shale revolution, finding that wastewater injection there “significantly increases the likelihood for faults to slip.” This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. Efforts to solve its challenges have been extensive and continue to evolve. These efforts can have a strong effect on the profitability of an operation. This paper aims to provide an introduction to the early management of downhole produced water in strong waterdrive reservoirs using inverted electrical-submersible-pump (ESP) technology.
I am encouraged that we, as an industy, continue to refine and tweak our practices to solve zonal-isolation and cementing challenges in every well environment in which we work. As cementing techniques are improved, so, too, are the cement-evaluation methods and work flows. This paper demonstrates a new way to create gas-tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed. This paper discusses shale creep and other shale-deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India.
Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share. Every attendee leaves energised with a full list of ideas and a support network of fellow leaders. Those sections and student chapters actively participating in this workshop have consistently been recognized with awards as the best in SPE. SPE Cares is a global volunteering drive aimed at promoting, supporting and participating in community services at the SPE section and student chapter’s level. On its official launch this year at ATCE Dubai, SPE Cares will conduct a “Give a Ghaf” Tree Planting Programme to help preserve Ghaf’s cultural and ecological heritage. The Ghaf tree is an indigenous species, specific to UAE, Oman and Saudi Arabia. It is a drought tolerant, evergreen tree that can survive a harsh desert environment. The initiative not only aims to hold events/activities at ATCE, but also recognise community service that SPE members are already conducting in their respective student chapters and professional sections. The KEY Club, open daily, is an exclusive lounge for key SPE members. The lounge is open to those with 25 years or more of continuous membership, Century Club members, current and former SPE Board officers and directors, Honorary and Distinguished Members, as well as this year’s SPE International Award Winners and Distinguished Lecturers. DSATS (SPE’s Drilling Systems Automation Technical Section) will hold a half-day symposium featuring keynote presentations on urban automation. This symposium will explore technologies being used in developing smart cities through the automation of their infrastructure, transportation systems, energy distribution, water systems, street lighting, refuse collection, etc. These efforts rely on many of the same tools needed for drilling systems automation yielding increased efficiencies, lower maintenance and reduced emissions. Their knowledge and experience can guide the path being travelled by the oilfield drilling industry.
Zafar is a strategy consultant with Accenture and is based out of Mumbai. Before Accenture, he worked for 5 years at Halliburton designing drill bits for oil and gas companies in South Asia. He has been a volunteer with TWA since 2013 supporting multiple sections prior to transitioning to a leadership role in 2018. He is a keen technophile, an avid debater, and a passionate Toastmaster. He has participated in and won several public speaking and debate competitions. His hobbies include running, collecting key-rings, building robots, and keeping abreast of global geopolitics. Kristin Cook is the Advisor to TWA. She is an MS candidate in Energy and Earth Resources at the University of Texas at Austin. Her interests include energy policy, oil and gas project development, and energy security and geopolitics. Prior to starting graduate school, Cook worked for 5 years as a production engineer in the San Juan Basin, a natural gas field in northwestern New Mexico.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
The objective of the project is to reconcile and quantify the impact of geological and completion variables that cause significant EUR differences in two recent wells drilled and completed in the Uteland Butte member of the Green River formation in Uinta Basin, Utah. While the geology and reservoir conditions are similar for both wells, the completion design and parameters are different (Ball-and-Sleeve vs. Plug-and-Perf, job size, treatment rates, well length, etc.).
The Asset Team uses a structured workflow consisting of several modeling tools: Rate-Transient-Analysis (RTA), Frac Modeling (FM) and Reservoir Simulation (RS) to address and quantify the impact of each variable: Job size, Treatment Rate, Frac count per Stage, Well Length and the effect of clays.
The workflow began with a performance evaluation of the high EUR well (Plug-and-Perf, large job) with RTA and Frac modeling; followed by history-match and prediction of the EUR with the RS model. In the subsequent workflow, a single variable is changed in each modeling step, while others are held constant -- as such, the EUR impact for each variable can be quantified. The result from each step is calibrated with the actual performance observed in the field.
This model-based approach successfully quantified the production impact of each variable. Subsequently, the key drivers can be determined which explains the estimated EUR difference between the two wells. This work drives us to conclude that due to varying pressure, PVT and lithology across the field, different completion designs shall be utilized. The team has gained valuable insight on how to implement different completion techniques with varying job size and design for the basin. Currently, these results are used to drive the well designs and approval; with the long-term objective of optimizing the Field Development Plan.
The difficulty in obtaining a continuous rock elastic properties (REP) profile from triaxial test makes calibration of geomechanical characterization models subjective. The impulse hammer method however provides reliable, reproducible, and continuous proxy for REP dataset, allowing for rock profiling. The relationship between the REP from these two techniques is not well understood, this study employed multivariate data reduction analysis and modeling to extract relevant correlations between Impulse Hammer and Triaxial derived REP. We derived a Young's modulus proxy called reduced Young's modulus (E*) from core plug samples. The E* was acquired from each sample systematically with respect to rock heterogeneity, grain size, and macropore size. The E* was taken as an average of nine impulse hammer runs per sample on equally spaced gridded location on each sample surface. Dynamic Young's modulus (Ed) and static Young's modulus (Es) were derived from the conventional triaxial test. The geochemical analyses were carried out to capture the mineralogical variations in the selected samples. We used statistical analysis and modeling to establish empirical relationship between Impulse Hammer and Triaxial derived RMP.
The results showed that, E* reliably captures the variables within the rock elastic properties. A strong correlation between the Ed, Es, and E* were observed in the samples. We also observed that E*, reveals details of several geomechanical heterogeneity and anisotropy which are not possible with traditional triaxial method. The results show that the empirical relationship between E and E* can be established to generate a continuous REP profile.
Sample availability, representativeness, time, and cost are common challenges in traditional triaxial test. The Impulse Hammer method is a non-destructive technique that significantly saves time, and has a promising cost efficient workflow, which provides reliable, reproducible and continuous rock mechanical properties profile. A robust geomechanical characterization and model calibration can be performed by combining the outputs obtained from these two methods.
The completion design process for most horizontal wells in shale reservoirs has become a statistical evaluation process, rather than an engineering-based process. Our paper presents an alternative approach using an engineering approach to define the reservoir properties and the effectiveness of the fracture treatments. We then use these results in an economic analysis that allows the engineer to be predictive with respect to how capital is spent in the completion process.
This paper presents a methodology for both the evaluation of the reservoir and the design of the well completion where the engineer can make economic decisions and determine the change in the return on investment as a function of the change in capital expenditure. The engineer can then be able to “optimize” the completion and fracture treatment designs based on Net Present Value, Return on Investment or any other economic parameter desired. We use a rate transient analysis approach to estimate reservoir and fracture properties. We present case histories in the paper, and the interpretation of the production analyses of these case histories yields information about the formation permeability and the effective lengths and number of hydraulic fractures created during the completion process.
With knowledge of the reservoir and fracture properties in hand, the engineer can then determine the “optimum” completion design for future wells. This understanding can be achieved much quicker and for much less money than the cost to drill the number of wells necessary to make statistical analysis meaningful. The results of the case histories indicate that many completion designs are not in the “optimum” range. Too much capital is being spent increasing stage count when it should be going to increased effective length. The focus on early-time production has ignored the effect that more fractures has on ultimate recovery.
The results and conclusions in this paper will run contrary to much of the direction most unconventional completion designs have been evolving over the past 5 to 10 years. A much greater emphasis on achieving increased effective lengths will be demonstrated and that increased stage count can prove detrimental to economic success over the well's life. Processes in the paper will also prove valuable for smaller operators that do not have a large well counts that are usually required to achieve a meaningful statistical evaluation.
An integration of fracture model and reservoir model with complex fracture geometry plays an important role in understanding the impacts of fracture complexity on optimization of well spacing. In this study, we applied the non-intrusive EDFM (Embedded Discrete Fracture Model) technology to couple fracture and reservoir models to perform shale gas simulation with and without considering natural fractures. First, we applied a complex fracture propagation model to predict hydraulic fracture geometry. For the first time, the impact of non-uniform natural fracture distribution with a larger fracture intensity nearby the wellbore region on fracture complexity was investigated. Two horizontal wells with and without natural fractures were simulated to generate simple and complex fractures. Complex fractures include hydraulic fractures and complex activated natural fractures. Well interference due to hydraulic fracture hits of both fracture geometries were analyzed and compared. After that, both simple and complex fractures were directly transferred to a shale-gas two-phase reservoir model through the non-intrusive EDFM technology. Both fracture geometries can be easily embedded into the structured matrix grids. Fluid flow between fracture and matrix grids can be exactly handled by non-neighboring connections and transmissibility. During the shale-gas production simulation, key effects such as non-Darcy flow in fractures, gas desorption, and pressure-dependent matrix permeability, hydraulic fracture permeability, and activated natural fracture permeability were considered. Additionally, different relative permeability curves for matrix and fractures were assigned in the reservoir model. We compared the well performance of 30 years under the constant flowing bottomhole pressure constraint between simple and complex fractures. The simulation results show that complex fractures can perform much better in terms of cumulative gas and water production than the simple fractures. The simple fractures are easier to cause well interference due to hydraulic fracture hits than the complex fractures under the same completion condition. Furthermore, the simple fractures have a much smaller drainage area and less drainage efficiency than the simple fractures. Finally, the simple fractures have a much larger pressure difference from the fracture center to its neighboring shale matrix than the complex fractures, which indicates that the smaller cluster spacing might be suggested in order to maximize the drainage efficiency if ignoring the natural fracture effect. This study provides critical insights into understanding the impact of non-uniform natural fractures on fracture propagation and shale-gas production simulation.
Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures (NFs) exist in the rock body, additional elastic anisotropy can be introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that treating the naturally fractured shale rock as a TI medium by ignoring the NF-induced anisotropy can cause the erroneous estimation of the geomechanical properties and in-situ stress. In this paper, the study is extended to quantify the impact of NF-induced elastic anisotropy on completion and fracturing designs in different actual shale reservoirs in U.S.
Published acoustic log data from five different shale formations (Bakken, Marcellus, Haynesville, Eagle Ford, and Niobrara) are collected and examined to determine their availability to generate the stiffness tensor of the representative TI background rock of each Shale reservoir. Natural fractures with different intensity values from 0 to 10 per foot, with shear wave splitting ranging from 0-5%, are introduced in the TI background rock to create the corresponding OB rock stiffness tensor. The OB stiffness tensors of different shale cases are finally converted back to the compressional and shear acoustic signals, which can be interpreted based on the TI or OB assumptions. The final output elastic moduli and in-situ stress results interpreted from different assumptions are compared, and the impact of NF-induced elastic anisotropy on completion and fracturing designs is quantified and fully understood for different shales.
The results show that introducing natural fractures into the TI background shale rock leads to a decrease of the in-situ stress and Young's modulus at the orientation perpendicular to the natural fracture plane. Such impact increases with increasing split of fast and slow shear wave slowness (SWS), while decreases with increasing ratio of the “soft mineral content” (i.e. clay and TOC) to the “hard mineral content” (i.e. quartz and calcite). In addition to that, different impacts on stress contrast (variation along the vertical depth) are observed for different shales, owing to the complex mineralogy/lithology sequences of different shale formations. As a result, ignoring the natural fracture induced elastic anisotropy in acoustic log interpretation can result in an overestimation of in-situ stress and Young's modulus as well as a misinterpretation of stress contrast, which further leads to the problematic or suboptimal completion/fracturing designs. The results have been also compared with the shale mineralogy/lithology log data to reveal how the natural fracture induced elastic anisotropy impact is associated with the natural fracture properties (compliance and intensity) and the mineralogy of TI background rocks.
The current study not only illustrates the importance of taking natural fracture induced anisotropy into account when performing geomechanical log interpretation, but also provides guidance to the operators of the five shale fields to better evaluate their current completion/fracturing design strategies and to determine if the natural fracture induced anisotropy impact should be corrected for their current designs or not based on the monitored splitting of fast and slow shear wave slowness.