The oil and gas production landscape in North America has seen a paradigm shift since the collapse in oil prices in 2014. Although prices remain challenging, several operators have managed to sustain the relatively long period of low margins through some aggressive approaches. This paper inspects changes in operating strategies and field development plans across all oil-rich basins in the US Rocky Mountain fields and how operators have used a combination of low oilfield service prices, high-graded well locations, and incremental fluid/proppant volumes to increase production.
The paper investigates the transformation in operating philosophies since 2014 in four oil-rich basins in the Rocky Mountain region—Williston, Denver-Julesburg (DJ), Uinta, and Powder River. The Bakken formation in the Williston basin represents one of the best-quality rocks in all of North America. However, high oil-price differentials and well costs have made it difficult for drilling to remain profitable. The core of the DJ basin (Wattenberg) has one of the lowest break-even prices in the region, and rig count continues to increase as operators start seeing signs of recovery in the market. The Uinta basin, although relatively small in size, has shown tremendous return potential in the form of multiple stacked pays and promising production results. The Powder River basin poses one of the toughest operational environments in the region owing to wildlife stipulations, harsh weather, and deeper targets.
High-graded well locations in the Bakken are limited to few fields, which limits the scope of expansion in the current oil price environment. The DJ basin is challenged with high-density well spacing; estimated ultimate recovery (EUR) per drilling spacing unit (DSU) continues to increase, but EUR per well has gone down by as much as 60%. In the Uinta basin, formations never known to be continuous in the Green River group have shown significant return potential. The Powder River basin has recently attracted large investments from major independent operators as they tackle drilling challenges associated with abrasive rocks and testing optimum lateral landing points.
Case studies show how operating strategies have changed with changes in oil prices. The Bakken and DJ basins are relatively mature, and as drilled-but-uncompleted (DUC) inventory continues to increase, depletion from existing wells and interference between fractures is impacting production from new wells. The Powder River basin is still in the exploratory phase, and operators are still working on reducing well-costs, optimizing fracturing-fluid/proppant volumes, and examining productivity of other target rocks. The Uinta basin is in the early phases of expansion, with many of the fields still being explored for scalability. Changes in production maps and completion trends provide a comprehensive understanding of how these variables have impacted oil output from the region since 2012.
High-resolution scanning electron microscopy (SEM) has been widely applied to understand the mechanism for oil/gas storage in the unconventional shale reservoirs. However, the microstructures in the Upper Devonian–Lower Mississippian Lower Bakken and Pronghorn members of the Bakken Formation are poorly understood in the context of petrography. This project used SEM to investigate the pore types, porosity development, and their variability as functions of mineral composition, organic-matter type, total organic carbon (TOC) content, and thermal maturity in the Lower Bakken and Pronghorn members. Eleven representative organic-rich rock samples from nine wells, spanning across the Williston Basin, have variable levels of maturity from immature (Tmax=422.5°C, equivalent calculated vitrinite reflectance Ro=0.45%) to late mature (Tmax=453.7°C, equivalent cal. Ro=1.0%). These samples also have a broad range of TOC values from approximately 0.5 to 23 wt.%.
Three pore types were recognized in this study: mineral matrix pores, organic-matter pores, and fractures. Common mineral matrix pores include interparticle pores (e.g., pores between clay platelets and pores at the edge of rigid grains) and intraparticle pores (e.g., pores in dolomite, framboidal pyrite, and microfossil-cavity). The size of these pores varies from 10 nm to no more than 8 μm. Our results suggest that an increase of mineral matrix porosity appears to be related to higher clay and dolomite content. The nanometer-sized organic matter pores are predominantly preserved in the amorphous organic matter, and they are most abundant in the immature and latemature shales. On the other hand, structured kerogens (e.g., Tasmanites and terrestrial phytodetritus) are typically non-porous regardless of thermal maturity. The integration of petrographic features and thermal maturity data can assist in distinguishing between kerogen and migrated oil/bitumen. Care should be taken to interpret the shrinkage pores within organic matter as evidence shows that some shrinkage pores are filled with calcite, reflecting a reducing volume of kerogen during oil/bitumen generation. The presence of fractures is implied by the crack-filling migrated bitumen/oil as a consequence of the overpressure caused by thermal decomposition of kerogen. This study demonstrates that there is no single, universal relationship between TOC and organic porosity for all samples. We also conclude that a vanishing volume of organic matter pores from immature to early mature Bakken shale samples, followed by a general increase of organic porosity in peak and late maturity windows.
Coalbed methane (CBM) produced from subsurface coal deposits has been produced commercially for more than 30 years in North America, and relatively recently in Australia, China, and India. Historical challenges to predicting CBM-well performance and long-term production have included accurate estimation of gas in place (including quantification of in-situ sorbed gas storage); estimation of initial fluid saturations (in saturated reservoirs) and mobile water in place; estimation of the degree of undersaturation (undersaturated coals produce mainly water above desorption pressure); estimation of initial absolute permeability (system); selection of appropriate relative permeability curves; estimation of absolute-permeability changes as a function of depletion; prediction of produced-gas composition changes as a function of depletion; accounting for multilayer behavior; and accurate prediction of cavity or hydraulic-fracture properties. These challenges have primarily been a result of the unique reservoir properties of CBM. Much progress has been made in the past decade to evaluate fundamental properties of coal reservoirs, but obtaining accurate estimates of some basic reservoir and geomechanical properties remains challenging.
The purpose of the current work is to review the state of the art in field-based techniques for CBM reservoir-property and stimulation-efficiency evaluation. Advances in production and pressure-transient analysis, gas-content determination, and material-balance methods made in the past 2 decades will be summarized. The impact of these new methods on the evaluation of key reservoir properties, such as absolute/relative permeability and gas content/gas in place, as well as completion/stimulation properties will be discussed. Recommendations on key surveillance data to assist with field-based evaluation of CBM, along with insight into practical usage of these data, will be provided.
POGC Rehman-1 discovered gas from the Pab sandstone in mid-2009. The well had low productivity primarily due to low reservoir permeability. In December 2009, the well's Upper and Lower Pab zones were fractured, resulting in a fourfold increase in production. Post-frac testing of the zones discovered very little proppant flowback.
This paper outlines the history of this successful hydraulic fracturing treatment in the Kirthar region. The document also discusses the detailed job design, fracture modeling, pre-frac production model calibration, and sensitivities to treatment size. A series of fracture designs was developed to evaluate the uncertainty in fracture geometry predictions. The successful stimulation of a low-permeability gas reservoir dictated placing a long conductive fracture.
An important aspect of fracture design is fluid selection. The fluid must maintain excellent proppant transport characteristics throughout the pumping sequence, yet break rapidly and cleanly once the treatment is completed. Another important aspect of fracture design: proppant selection. The proppant is basically the life of the fracture and should maintain adequate conductivity throughout the designed exploitation life of the fracture and completion.
The fracturing program and the main treatment's actual execution are presented in the paper. Operational issues are also discussed. One-hundred mesh sand was used to minimize the risks associated with pressure dependent leakoff (PDL) into natural hairline fractures seen on the FMI log. Post-fracture well-testing data was recorded and analyzed. The results were used to quantify the fracture effectiveness.
Coalbed methane (CBM) produced from subsurface coal deposits, has been produced commercially now for over 30 years in North America, and relatively recently in Australia, China and India. Historical challenges to predicting CBM well performance and long-term production have included: accurate estimation of gas-in-place (including quantification of in-situ adsorbed gas storage); estimation of initial fluid saturations (in saturated reservoirs) and mobile-water-in-place, estimation of the degree of under-saturation (undersaturated coals produce mainly water above desorption pressure); estimation of initial absolute permeability (system); selection of appropriate relative permeability curves; estimation of absolute permeability changes as a function of depletion; prediction of produced gas composition changes as a function of depletion; accounting for multi-layer behavior, and accurate prediction of cavity or hydraulic fracture properties. These challenges have primarily been a result of the unique reservoir properties of CBM. Much progress has been made in the past decade to evaluate fundamental properties of coal reservoirs, but there is still work to be done to obtain accurate estimates of some basic reservoir properties.
In recent years, horizontal wells and more complex well architectures and stimulation methodologies have been implemented to improve recovery of CBM. These more complex development options bring with them a new set of challenges for operators producing CBM. The exploitation of more geologically-complex coal with poorer reservoir quality will necessitate new and inventive ways to develop the existing natural gas resources and possibly combine this with new methods to extract energy from the coal in-situ. Development planning in these scenarios will become increasingly complex as will evaluation methods.
The purpose of the current work is to review the state-of-the-art in CBM reservoir property and stimulation efficiency evaluation and speculate on possible CBM development scenarios for the future and the technical challenges they will bring. Current and future work required to meet these challenges will be discussed in the hope that industry, academia, and government bodies alike will be proactive in the development of solutions that will make future CBM recovery efficient, economic, and environmentally friendly.
Ramurthy, Muthukumarappan (Halliburton Energy Services) | Barree, Robert David (Barree & Assocs. LLC) | Broacha, Earuch F. (Bill Barrett Corp.) | Longwell, John Dorney (Gasco Energy) | Kundert, Donald P. (Halliburton Energy Services) | Tamayo, Hilda Cristina (Halliburton)
Over the last few years shale plays across North America have received significant attention because of their revenue potential and the supplementary reserves they add to the U.S. natural-gas reserves. However, the flow capacity (i.e., permeability) of these shales is very low and, therefore, requires some sort of stimulation to make them economically viable. Problems during stimulation treatments can lead to "pressure outs?? and screenouts. One of the main reasons that lead to "pressure outs?? is high process-zone stress (PZS). With high PZS, the chance for pressuring out is higher than screenout (i.e., one can still flush the job at lower rates provided the sand has not settled in the wellbore). The purpose of this work is to show the effects of high PZS in shale stimulation treatments and the associated production from such zones.
Examples are presented from three shale wells in the Rocky Mountain region. Well A provides examples from the Gothic and Hovenweep shales, while Well B consists of an example from the Mancos shale. A Diagnostic Fracture-Injection Test (DFIT) was performed in the Gothic and Hovenweep shales before the stimulation treatment, and the results obtained point to very high PZS. History-match analysis of the Gothic and Upper or Main Hovenweep stimulation treatments using a grid-oriented, fully functional three-dimensional (3D) fracture simulator confirmed the same. Solutions are provided to overcome this effect and successfully "place?? the stimulation treatment. However, the production associated with such high PZS zones is not very encouraging. Well A is temporarily abandoned because of poor production, and the Mancos shale well with high PZS (Well B) is one of the poor producers in the field. Finally, another example (Well C) from a successful Mancos test is also included in this work to show the difference in production between high- and low-PZS zones. This paper discusses methods for early identification of high-PZS shale zones to possibly avoid stimulation treatments in order to pay more attention to the low-PZS zones that require stimulation.
Coalbed methane development continues to increase accounting for 8% of U.S. gas production in 2002. Many coalbed methane wells must be stimulated by hydraulic fracturing in order to achieve economic production rates. However, optimizing hydraulic fracture treatments in coalbed methane is difficult and advanced diagnostics can aid in the process. This paper discusses completion optimization for two coalbed methane reservoirs in the Rocky Mountains. Hydraulic fracture mapping was performed with treatment well tiltmeters on several wells in each reservoir. Treatment well tiltmeter fracture mapping is an emerging technology to optimize development of low permeability reservoirs. The fracture height measured with the treatment well tools was used to calibrate a fracture model for each field. The fracture mapping, calibrated model and on-site diagnostics were used to modify completion and stimulation strategy in these fields.
The completion strategy for both fields was fairly similar early on. Fracture mapping showed height growth through several coal stringers in both areas. There was some degree of containment in the laminated lithology bounding the pay packages but one field was more prone to height growth at higher pumping rates. Job size and injection rate were drastically reduced in this field because of the height growth tendencies and the presence of nearby water sands. This paper shows how the application of fracture diagnostics and engineering can reduce costs and help avoid costly errors. One example is shown with advanced diagnostics applied early in the development of a field and another example is shown with diagnostics applied after some development has already occurred. The differences in hydraulic fracture geometry that can occur between areas are also shown and how they create changes in completion strategy.
Sobernheim, D.W. (Schlumberger Data and Consulting Services) | Aly, A.M. (Schlumberger Data and Consulting Services) | Denoo, S.A. (Schlumberger Data and Consulting Services) | Rowe, W.S. (Schlumberger Data and Consulting Services) | Sturm, S.D. (Schlumberger Data and Consulting Services) | White, D.J. (Schlumberger Data and Consulting Services)
This paper will focus on an applied and integrated real-time technique developed to optimize the completions in low permeability, stacked, lenticular gas sand reservoirs.
This integrated approach involves developing a predictive model based on well logs and pressure transient techniques utilized to calibrate the well logs. The model uses either standard open hole or cased hole log data for calculating reservoir properties, rock mechanical properties, and individual zone productivities. A unique analytical tool was developed to convert continuous log data into discrete layers for input into fracture simulators. A multi-layer simulator is field calibrated to predict individual zone productivity under various stimulation scenarios.
Completions are rapidly designed by multi-disciplinary teams to assure the optimum design based on all available data and knowledge. Data flow is facilitated by an interactive webbased system to allow models to be computed and analysis to be begun within hours of the well reaching total depth. The entire design process must be completed within as few as forty-eight hours to keep pace with extremely aggressive drilling and completion schedules.
The team rigorously pursues systematic learning through comprehensive post appraisals of each completion. Predicted performance is compared to actual well performance on a well-by-well basis for continual improvement of the input models. Production logs and advanced decline curve analysis are strategically employed to provide key data sets. As production logs become available after the hydraulic fracture, new procedures are applied for analyzing the data to quantify estimates of the reservoir effective permeability, effective fracture half-length, and average fracture conductivity within individual productive layers.
This approach involves having a rapid reservoir model at the center of the integrated approach1. The reservoir model is the repository of all the knowledge acquired in the field2. This model is used to investigate and optimize well locations, predict fracture interference problems, and optimize drainage areas. The production data from all the wells are updated in the model on a real-time basis. Drainage patterns, depletion effects, and expected saturation front movements within the reservoir may then be continuously updated and used for forward planning and simulation.
By continuously monitoring and updating the actual production results on the model-based production prediction chart, discrepancies between designed and actual well performance are quickly identified and remedial actions, if necessary, may be efficiently taken. These action steps may include such items as obtaining a production log over the interval to determine what layers are contributing - and which are not, re-checking the completion records to insure that the correct design was pumped, and then applying interventions via coiled tubing and/or re-perforating to correct the situation in the well. The end goal is to quickly get the well on-line, producing to its economic potential.
The result is an integrated technique for a rapid and dramatic turnaround in the optimization of completions in tight gas reservoirs.
This paper presents case histories and field data that detail the application of well test data to calibrate fracture models, understand fracture performance, and optimize treatment designs. The paper includes field results from gas reservoirs in the Rocky Mountains and west Texas. The case histories also illustrate the application of postfracture pressure-buildup data to identify reasons for fracture treatment problems and to confirm treatment success. The paper also includes a novel data set that illustrates fracture performance from a liquid CO2 stimulation (no sand, no water) in west Texas. The case histories illustrate the importance of integrating well test data with fracture treatment optimization, showing how this process can improve our ability to reliably make multimillion-dollar decisions concerning proppant selection and fracture treatment size.