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Collaborating Authors
Unconventional and Complex Reservoirs
Abstract Current water management strategies require recycling and reuse of oil sand process affected water (OSPW) to as much as 80%. Continuous recycling and reuse of OSPW degrades water quality as the concentrations of total dissolved solids (TDS) and dissolved organic materials (DOM) accumulate. This results in a net increase in operating and maintenance costs and an impact on the extraction process and bitumen recovery. Remaining water containing fines and suspended clays adds to the mature fine tailings and associated problems for tailings pond treatment and management. Presence of residual bitumen and other organics is known to create difficulties in common practices for flocculation and dewatering of tailings. With the problems stated above, one may consider a pre-treatment approach rather than the common post-treatment remedies. The ore grade profoundly affects the efficiency of bitumen recovery in the hot water extraction of bitumen, the principal step in the bitumen extraction process. Sodium hydroxide is commonly added to the conditioning step to improve bitumen recovery. As the sodium ions build in concentration, they disperse clays in the ore and create tailings that resist dewatering. This is especially true for low-grade and oxidized ores, which present the greatest challenges in bitumen recovery and produce the major portion of tailings due to high fines content. With current trends for increasing production from mining operations to almost double by 2020, industry has to adopt new technologies to manage tradeoffs between water and energy. We present a new approach toward total water management by introducing environmentally friendly process aids that can improve bitumen recovery from low-grade oil sands ores. Lab-scale experimental data from a Denver flotation cell and hydrotransport loop were analyzed to evaluate the efficiency on the processability of high and low grade oil sands, water chemistry and tailings management. The results demonstrate that using new process aids during the conditioning stage improves bitumen recovery from low-grade oil sands and can accelerate tailings settling. This pretreatment approach can be incorporated into current oil sands mining processing facilities and delivers environmental and economical benefits. A critical evaluation for use of new process aids versus sodium hydroxide is given in detail.
- Overview > Innovation (0.54)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract This paper is a comprehensive literature survey and analysis of the Bakken Oil play, Williston Basin, which is one of the largest known oil accumulations in the world. This analysis includes; examining reservoir characterization and resource assessments, and evaluating project economics as well as current operators activities. These characteristics and assessments are then used to better understand and put context around the current drilling and completion best practices as well as water handling and operational constraints. The paper thoroughly analyzes the prolific Bakken petroleum system and describes the successful application of technologies and efficient operating practices that have enabled current Bakken production to increase to the cusp of the 500,000 BOPD mark. The hydrocarbon charge comes from two very organic-rich shales, which have matured and expelled oil both into the fractured clastic layer that separates them and the fractured mixed clastics and carbonates that bound them above and below. Where the upper and lower Bakken shale members are both thick and mature, the middle member has high residual oil saturation and high fracture density. Although the natural fractures are well interconnected over large portions of the basin, the highest resource density occurs in areas with the highest fracture densities. Through rapid dynamic evolution and application of new horizontal drilling and multistage fracturing technologies, this prolific play has experienced a recent resurgence in activity. Today, operators are able to produce the Bakken at reported rates of up to 7,000 bopd, utilizing (typical) well designs consisting of horizontal wells with 10,000’ nominal lateral lengths, stimulated with 18–36+ fracture stimulation stages. Since 2000, Bakken activity has surged, with 1,946 horizontal wells completed between January 2000 and July 2010. Operators, from small private firms to large public multinationals, are continuing to invest heavily in the Bakken. The continuation of this rapid pace of development has led to many challenges, including; water supply and handling challenges, increased infrastructure and human resource demands, and environmental sustainability. Nevertheless, the industry continues to rise to meet these challenges and is betting on continued Bakken success.
- North America > United States > South Dakota (1.00)
- North America > United States > Montana (1.00)
- North America > Canada > Saskatchewan (1.00)
- North America > United States > North Dakota > Mountrail County (0.68)
- Overview (0.86)
- Financial News (0.67)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Abstract The Bakken is one of the most active basins in the world in terms of number of rigs, with over 200 operating on the US side of the US-Canadian border. Production has rapidly increased from 100,000 BOPD in 2005 to 600,000 BOPD in 2012 in the state of North Dakota with the majority of production coming from the Bakken (Uptream Online, 2012). Greater horizontal drilling activity and a continuing increase in the number of hydraulic fracture stages per lateral have helped North Dakota grow its oil production six-fold in just seven years. The Bakken is a fairly tight dolomitic siltstone requiring hydraulic fractures to produce economically. The stage count for hydraulic fracture treatments averaged nearly three stages in early 2007 and increased steadily over time to nearly 30 stages in late 2011. Some wells have even been completed with 40 or more stages. With the ever increasing stage count, the question remains: has the economic stage count limit been reached in the Bakken? This paper analyzes the stage count versus the production impact of horizontal Bakken wells to determine if the economic stage count has been reached in the play. Wells are grouped and analyzed based on geographic considerations to help normalize for changes in geologic attributes such as natural fractures, reservoir quality, and net pay. Lateral length was also taken into account as varied lengths can impact stage spacing and interference issues. Analyses were run with various oil and well service costs to determine how the economic stage count may change over time. If the economic limit was not reached under certain circumstances, this paper analyzes possible scenarios to determine when the economic stage count would be reached. This approach should provide insight into how other unconventional oil plays can evolve in the future.
- North America > United States > South Dakota (1.00)
- North America > United States > Montana (1.00)
- North America > United States > North Dakota > McKenzie County (0.67)
- North America > United States > North Dakota > Mountrail County (0.46)
- Geology > Petroleum Play Type (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.87)
- North America > United States > Texas > Fort Worth Basin > Sherman Basin > Sadler Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Fairway Field > James Lime Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (18 more...)
Completion Influence On Haynesville Shale Gas Well Performance
Xie, Xueying (Shell Exploration and Production Company) | Glashan, John D. (Shell Exploration and Production Company) | Holzhauser, Shawn P. (Shell Exploration and Production Company) | Knott, Gregory M. (Shell Exploration and Production Company)
Abstract Shale gas has becoming an important source of gas production in recent years with the advantage of completion technique development. Completion to generate desired fracture system in the reservoir is critical to shale gas production and the corresponding well performance. The impact of fracture system and completion parameters on the well performance decline curves of Haynesville shale gas wells is investigated by using both simulations and field data. Applying numerical simulation models on horizontal Haynesville shale gas wells with regularly spaced transverse fractures, we investigated the impact of the fracture half length and total fracture surface area on the performance decline curve. The results show that the total fracture surface area defines the early production behavior during the linear flow period and the half length determines the declining slope of the main production time during the fracture interference period if the reservoir parameters are the same. If the reservoir parameters are different, the early time production behavior depends on , which is the square root of permeability times fracture surface area. Using field data of hundreds of Haynesville shale gas wells, we observed the different performance decline curves when compared among different regions and compared among different completions in the same region. The difference of decline curves in different regions when using the same completion practice indicates that the reservoir properties are different and thus impact both generated fracture system and flows in the matrix. The difference of decline curves in different completions in the same region suggests that completion impacts the generated fracture system and thus the decline performance. Based on the study results, we can improve the completion practice to optimize well performance and completion cost.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- North America > United States > Arkansas (1.00)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract This paper discusses how non-technical risks are impacting shale gas developments in Europe and how challenging it is to obtain the Social License to Operate. Although still at the early exploration phase, most European developments are already significantly hit by stakeholder concerns, lack of public acceptance and often lack of government support. Some European countries have even halted early exploration - at least temporarily - by political decision. Most of the public concerns are of environmental nature, especially linked to the use of chemical additives in the hydraulic fracturing process and related concerns about potential groundwater impacts, but hardly any is based on real events in Europe. Most concerns have developed on the back of perception and experiences in the US. This paper also takes a critical look at the discrepancy between public environmental concerns and real environmental risks. Initial experience in Europe has shown that the non-technical challenges have initially been underestimated, and that huge efforts are necessary to gain public acceptance and political support. A lot of efforts have already been put on stakeholder engagement, public information on technical processes, disclosure of chemicals and initial promotion campaigns, but the acceptance in most parts of Europe – Poland being the only exception - remains challenging. Besides technical and regulatory requirements, obtaining a "social license to operate" is thus of increasing importance for the success of a project.
- North America > United States (0.49)
- Europe > United Kingdom > England (0.30)
- Europe > France > Paris Basin (0.99)
- North America > United States > Ohio > Denmark Field (0.93)
- Europe > Sweden (0.93)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Management (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
Abstract Long-term economic viability of unconventional reservoirs is evaluated from the profit-maximizing perspective of a producing company. The case of the liquids-rich production from the Bakken field is considered as a representative of unconventional resources. A profit-margin optimization model is constructed for a company to meet the demand it faces from a stock of conventional and unconventional resources given different sets of exogenously determined prices. The model is parameterized using the different production-decline rates of the two sources, physical and economic exhaustibility of the resources, and the ever-increasing marginal cost of adding conventional resources into the company portfolio. The optimal extraction path of oil from the conventional and unconventional reservoirs is assessed and the long-term economic consequence of keeping the unconventional resource in the ground for different oil-price scenarios is predicted. The model reveals the appropriate composition of a portfolio of conventional and unconventional resources. In the case of a high-price scenario, the optimal efficient extraction path is the pursuit of additional conventional resources before utilizing unconventionals to meet the demand. For the reference-price scenario, the decline of the conventional reserves should be substituted with unconventionals from the beginning. The profitability of the EOR applications in unconventional reservoirs and when they should be implemented are also determined. Contrary to common expectation, it is shown that the EOR technology is more justifiable in the case of a lower price forecast.
- North America > United States > North Dakota (0.85)
- North America > United States > South Dakota (0.71)
- North America > United States > Montana (0.71)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.50)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
An Efficient Decision Framework for Optimizing Tight and Unconventional Resources
Wehunt, C. D. (Chevron Corp.) | Hrachovy, M. J. (Chevron North America Exploration & Production Co.) | Walker, S. C. (Chevron North America Exploration & Production Co.) | Padmakar, A. S. (Chevron Energy Technology Co.)
Abstract Making an efficient and wise concept selection decision—quickly selecting the right project—is often of equal or greater importance than later design and execution tasks for determining project success. Value lost from a suboptimal concept selection decision or from a needlessly prolonged decision process is independent of value generation opportunities during design and execution, and cannot be recouped during later project phases. This paper presents decision framework and production forecasting processes that complement one another, and promote an efficient and high-quality concept selection decision for tight or unconventional resources. The method is for both oil and gas resources, and is especially useful for assessing and developing large contiguous tracts. High quality production forecasting is very important during concept selection. Better quality concept selection decisions will also result if the alternative conceptual plans are equally optimized when the decision is made, and our assessment process facilitates both accurate forecasting and equal optimization of the various development alternatives. Our method includes symmetry element reservoir simulation models and an efficient economic spreadsheet model with an optimizer. The sector simulation models run fast and can evaluate many cases, but they still explicitly address the physical effects relevant to flow in porous media with vertical, transverse, hydraulic fractures intersecting horizontal wells. The decision framework is structured so that some decisions are independent of the simulation model, and those decisions are rapidly optimized within the economic model. We introduce a fracture efficiency factor which may be important for modeling the diminished performance observed as the number of stages increase in multi-fractured horizontal wells. This fracture efficiency factor may also be an important discriminator of performance between wells fractured using aqueous vs. non-aqueous fracturing fluids. We also show how to use meaningful constraints with a symmetry element model to ensure that the economic forecasts are both realistic and achievable.
- North America > Canada (0.68)
- North America > United States > Colorado (0.67)
- North America > United States > Colorado > Skinner Ridge Field (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Horn River Shale Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- Management > Risk Management and Decision-Making > Decision-making processes (1.00)
Abstract This paper examines corporate economic and financial performance in the natural gas producing industry and assesses whether performance is a function of portfolio (types and location of gas supplies) or efficiencies in execution in capital spending and operations. This issue is relevant for North American gas producers, related service companies, and government fiscal policy that are all trying to deal with the current low gas price environment, and the future. North American gas producing companies assemble their portfolios from 2 categories of gas supply: Conventional and Unconventional (including Tight Gas, Coal Bed Methane, and Shale Gas). Producers economic performance is very different depending on the level of gas prices, so 2 price cases will be examined - ‘normal’ price ($5+/Mcf), and ‘depressed’ price (<$3/Mcf), comparing Conventional & Unconventional gas. In the Normal Price case, full cycle costs are the most relevant performance measure. The largest component, Capital Spending Efficiency, drives full cycle economic results and the return available to the producer. We show the wide range of company performance, such as Finding & Development Cost for gas only by company, and examples of full cycle cost for Unconventional vs. Conventional plays. Some play types are more economic (portfolio selection) and some companies are more efficient than others (Execution). The Depressed Price (current) world is characterized by a gas price well below Full Cycle Economics - there is no return, though some cash is generated. Operating Costs are most important. The range of average Operating Costs between types of gas fields in Western Canada and the Gulf of Mexico Shelf is shown. There is a large variation in operating cost among similar fields. Both portfolio and execution are critical to surviving today's gas markets. It is important to know full cycle costs by strategy (and gas basin analysis) to achieve a target portfolio and strong performance in CapEx and Operations is critical. Other key factors to enhance revenue are: the impact of natural gas liquids on gas economics and the effect of hedging on the price achieved. Natural gas prices have plummeted to decade lows, threatening gas activity. An understanding of industry economics is critical to forecasting and maybe even surviving!
- North America > United States (1.00)
- North America > Canada > Alberta (0.47)
- Geology > Rock Type > Sedimentary Rock (0.56)
- Geology > Petroleum Play Type (0.48)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (21 more...)
Abstract Traditional stochastic modeling efforts for exploration project assessment start from a model that incorporates estimates of uncertainties and risks and then simulates how the company (decision subject) acts as the risks and uncertainties are resolved (outcomes revealed). In resource play assessment the model also often includes learning of the experience curve (learning-bydoing) type: there is a model component that specifies how uncertain well costs and uncertain drilling durations are reduced as a function of the cumulative number of wells that have been drilled. This paper presents a framework for assessment of recovered resources and economic value that also models statistical learning. The framework includes an explicit model of how prior uncertainties are transformed into posterior uncertainties and simulates decisions that are based on the posterior uncertainties -- and not on full certainty. The learning application is shale gas resource play assessment and the learning is linked to pilot production. The work follows up on earlier work (Haskett & Brown, 2005) that recognizes that analogs used to define well performance provide an envelope (a population) of well curves. The new integrated analytics presented in this paper use the pilot production to constrain the prior distribution and make decisions based on the resulting posterior well performance (EUR/well) curves. Modeling learning provides a basis for a more realistic simulation that captures not only the potential for more or less effective decisions, but also can be used to assess the value of information. Application is illustrated with an assessment that is used to support the decision to enter a shale gas resource play.
- North America > United States (0.48)
- North America > Canada (0.46)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Management > Risk Management and Decision-Making (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (0.89)
Abstract This paper presents the methodology and technical solutions used to perform an evaluation of Gas Resources for two coalbed methane (CBM) projects in former coal mining basins in the North and East of France. These assessed gas volumes constitute one of Europe's important reported coal bed methane's resources. Successful gas flow rates were also obtained from a horizontal well drilled in coal strata. CBM resources classification principles as described in the Guidelines for Application of the Petroleum Resources Management System (PRMS - November 2011) were applied. The main issues encountered were the allocation and categorization of the 1C/2C/3C Contingent Resources and Low/Best/High Prospective Resources. Dealing rigorously with uncertainties inherent to the type of data used was an essential part of the study. A fully integrated workflow was used to undertake the resources evaluation. The Gas Initially in Place (GIIP) estimation is based on 3D geological models. Project specific criteria were applied to derive the final volume estimation in the context of CBM resources in the vicinity of former coal mines. Potential recovery factor calculations followed 3 different approaches: Langmuir isotherm curves, material balance based on mining data and 3-D dynamic simulation based on pilot horizontal well results. Due to large uncertainties existing on various parameters, a sensitivity analysis was performed to evaluate their relative impact on production during the dynamic simulation, using experimental design techniques. The final resources calculations and their respective categorization were based on a probabilistic methodology using Monte Carlo simulations with specific distributions for all parameters used at each stage of the workflow (net coal, gas content, coal density, level of coal undersaturation, permeability and recovery factor distributions). Key parameters were identified as critical with a large impact on the final assessment (gas content, level of undersaturation, shape of Langmuir isotherm curve, abandonment pressure). The elaborated workflow allowed the classification in Contingent and Prospective resources as well as evaluating their respective range of uncertainty which was required to complete the evaluation.
- Europe > France > Pas De Calais Basin (0.99)
- North America > United States > Kansas > Lorraine Field (0.97)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)