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Collaborating Authors
Unconventional and Complex Reservoirs
Abstract Multiple stage hydraulic fracturing is a key technology driving the development of unconventional resources in North America. This technique began in the Barnett shale and its application has opened the door for the successful development of nearly every shale play in the world, including the Eagle Ford shale. Given the relatively new application of this technique, and the number of fracture treatments completed, initial fracture treatment designs in a given play are often transferred from other North American shale plays to serve as baseline treatments. Given the rapid pace of development in a new play, as well as the desire to get to a standardized completion program, many operators continue to use these baseline designs and fail to evaluate current designs to develop more optimal treatments. This paper will discuss the successful evolution of hydraulic fracture designs in the Eagle Ford shale from one operator's perspective. It will detail the development from the traditional low conductivity slick water fracture treatments used initially in the play, to the use of higher conductivity hybrid fracture designs. In addition to detailing the theory and workflow of these design changes, this paper will also evaluate production data from multiple wells and evaluate production results for the hydraulic fracture designs. Discussion of enhanced conductivity will be presented along with the economic benefit of these changes. Those working the Eagle Ford shale can directly apply the principles presented in this paper to enhance the productivity and economics of their completions. In addition, engineers working other resource developments can use the principles from this paper to compare their current fracture design methodology and develop best practice approaches for hydraulic fracture design optimization in their respective plays.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
Optimizing Completion Designs for Horizontal Shale Gas Wells Using Completion Diagnostics
Bartuska, J. E. (J-W Energy Company) | Pechiney, J. J. (ProTechnics Division of Core Laboratories) | Leonard, R. S. (ProTechnics Division of Core Laboratories) | Woodroof, R. A. (ProTechnics Division of Core Laboratories)
Abstract In horizontal shale completions, one of the primary goals is to maximize contact with the most reservoir rock and effectively drain the complex fracture network that has been created during the stimulation process. This paper covers a five-well case study in the Marcellus Shale where completion diagnostics were used to evaluate and optimize the completion process. The case histories will detail key completion parameters and how they changed over time based on various diagnostic results. Completion diagnostics such as proppant and fluid tracers can be integrated with production, stimulation and geologic data to provide useful information as to the effectiveness of the completion design. Proppant tracers have been utilized in horizontal shale basins throughout North America to evaluate near-wellbore fracture initiation, identify un-stimulated perforations, and evaluate proppant interference between stimulated wellbores. Fluid tracers are currently being used to analyze lateral clean-up over time and to quantify fracture fluid interference between wells. In this case study, these diagnostic technologies were instrumental in addressing several completion design questions. Proppant tracers were used to evaluate cluster and stage spacing and also identified proppant interference with adjacent wells. Fluid tracers were utilized to evaluate overall load fluid recoveries for various wellbore trajectories and helped quantify the source and amount of interference between wells.
- North America > United States > West Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- North America > United States > Virginia (0.90)
- (2 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract In recent years, drilling and production activity in US shale gas has been increasing. This high volume of work has led to the use of manufacturing-style well construction. Each area has its own challenges; however, problematic wells are prevalent in many shale plays. A major study in the Haynesville shale targeted the manufacturing-style methodology. Over the course of the study, more than 160 cement jobs were analyzed including surface, intermediate and production strings. This study implemented the use of careful engineering decisions that were focused on the issues and challenges specific to wells in this area. This was achieved through analyzing and optimizing the laboratory operations, design of cement systems, bulk plant and job site processes. This study shows by taking the proper steps to design these processes, a manufacturing style approach can be very successful when applied in challenging shale cementing operations.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.88)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
Abstract It has been observed that the shale gas production modeled with conventional simulators/models is much lower than actually observed field data. Generally reservoir and/or stimulated reservoir volume (SRV) parameters are modified (without much physical support) to match production data. One of the important parameters controlling flow is the effective permeability of the intact shale. In this project we aim to model flow in shale nano pores by capturing the physics behind the actual process. For the flow dynamics, in addition to Darcy flow, the effects of slippage at the boundary of pores and Knudsen diffusion have been included. For the gas source, the compressed gas stored in pore spaces, gas adsorbed at pore walls and gas diffusing from the kerogen have been considered. To imitate the actual scenario, real gas has been considered to model the flow. Partial differential equations were derived capturing the physics and finite difference method was used to solve the coupled differential equations numerically. The contribution of Knudsen diffusion and gas slippage, gas desorption and gas diffusion from kerogen to total production was studied in detail. It was seen that including the additional physics causes significant differences in pressure gradients and increases cumulative production. We conclude that the above effects should be considered while modeling and making production forecasts for shale gas reservoirs.
- Asia (0.93)
- North America > United States > Texas (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Abstract Determining the optimal number of wells for infill drilling in an unconventional reservoir is a critical endeavor for shale gas operators as many leases are held only by production. To develop a given section, operators must select locations and completion designs for all wells. The planned well placement and completion design will dictate the economic viability and production of the field for the asset's life. The key factors impacting performance in shale gas reservoirs can be broadly divided into two categories: controllable and uncontrollable. Uncontrollable factors include rock properties such as porosity, water saturation, net-to-gross, initial pressure, permeability, natural fractures, and fluid properties. Controllable factors related to producibility that can be optimized include well design, completion design, well placement, surface facilities design, and operating conditions. Development schemes must consider both engineering and economic risks that include reduction of reservoir permeability due to rock compaction and changes in completion characteristics/efficiency. To determine optimal development, these factors have to be evaluated. This paper outlines the results of well optimization studies initiated from a production performance analysis of over 100 wells in the Haynesville Shale and over 300 wells in the Marcellus Shale. Both analytical and numerical tools were used in the presented workflow. The study results indicate a threshold of reservoir and completion properties below which any well drilled may be uneconomic based on our financial assumptions. Original gas-in-place (OGIP), rock brittleness, and fracture height containment were considered with regard to stimulated reservoir volume, SRV. The effect of natural fractures was also studied. With low gas prices, optimal capital allocation is a critical development component and is an issue that all operators face. The subsequent results presented could save operators myriad hours of simulation effort while potentially saving millions of dollars by eliminating unnecessary wells.
- North America > United States > Pennsylvania (0.89)
- North America > United States > Texas (0.66)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.88)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.69)
Abstract Completion programs for hydraulic fracture stimulations are planned to optimize the spacing of wells and perforation clusters such that the largest volume of the reservoir can be accessed through the promotion of a discrete fracture network in the reservoir. Such treatments also seek to minimize costs associated with pumping proppants and fluids down wells by ensuring that these injectants reach their target formations, stay in zone, and act to promote the stimulation of the reservoir. From this viewpoint, it is seen as desirable to minimize the overlap of treatment volumes between neighbouring wells and stages to avoid the preferential diversion of proppants and fluids into the previously stimulated volumes of the reservoir. However, it has also been argued that the creation of new fractures in a previously treated volume promotes a complex fracture network enhancing drainage. When these stimulations are monitored from multiple geophone arrays surrounding the treatment zone, seismic moment tensor inversion (SMTI) analysis offers the ability to test these hypotheses by inferring if the microseismic events are related to the opening of or closure of pre-existing natural or newly created fractures. In this paper, we discuss event clusters that occur with a significant degree of overlap between neighbouring stages in the Marcellus Shale. Because the events were monitored with multi-array sensor configuration, the SMTI calculations can be conducted with a high degree of accuracy. SMTI allows for the orientations of the underlying fractures to be determined, allowing us to construct a discrete fracture. Further analysis of the orientations of the underlying fractures also enable us to assess which fractures are being activated in relation to the pre-existing structures in the reservoir, and how the activation of those structures correlates to estimates of stimulated reservoir volume which we relate to the regions of the reservoir where an complex, intersecting fracture network is being activated by the stimulation.
- North America > United States > Pennsylvania (1.00)
- North America > United States > New York (0.88)
- North America > United States > West Virginia (0.87)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.74)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.73)
- Geology > Geological Subdiscipline (0.72)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (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)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Abstract Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic based drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water based drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability. The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-based drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray-photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
- 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)
- (10 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract Over the last few decades, shale gas has become an increasingly important global source of natural gas, especially in the United States. According to Polczer (2009) and Krauss (2009), shale gas will greatly expand worldwide and is expected to supply as much as half the natural gas production in North America by 2020. Due to extremely low shale matrix permeability, shale is considered an unconventional source of gas and requires fractures to provide a flow path to the wellbore. Due to uncertainties in quantifying the gas-in-place and identifying flow behavior; estimating the ultimate recoveries in shale gas reservoirs requires new techniques. In this paper, we used four approaches to estimate the ultimate recovery in shale gas wells: two empirical methods (conventional and modified decline curve analysis), analytical modeling and numerical modeling. All four approaches were applied on wells from four different shale plays (Barnett, Haynesville, Marcellus and Woodford).
- North America > United States > Texas (0.94)
- North America > United States > West Virginia (0.68)
- North America > United States > Pennsylvania (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (20 more...)
Abstract With estimates of recoverable reserves at approximately 500 Tcf, the Marcellus Shale has become one of the main unconventional shale targets in the U.S. The Marcellus is part of the Appalachian Basin and underlies 95,000 sq. miles of Pennsylvania, New York, Ohio, Maryland, and West Virginia. The Marcellus is a challenging target due to formation characteristics, making it cost-intensive to develop. In addition, operators working in the Marcellus have had to contend with public opposition to hydraulic fracturing, prompting them to look for technologies to make this process more efficient and less resource intensive. This paper compares open hole multistage fracturing systems (OHMS) and cemented casing, "plug and perf" (CCPP) completions and presents the evolution of completion methods utilized in the Marcellus Shale. Production results from horizontal wells in two counties completed with OHMS are compared to offset wells completed with the CCPP method. System details, the fracture methods used, as well as the operational efficiencies of OHMS compared to other horizontal completions methods are discussed. In addition, an update on the recent advances in technologies that have been made since the introduction of OHMS to the Marcellus Shale is presented. Higher cumulative production results at six, 12, and 24 months in both geographic areas of analysis demonstrate the successful application of OHMS systems in the Marcellus Shale. Comparing the two completion methods also highlights the increased efficiency of OHMS systems compared to CCPP. With decreased time and cost requirements, OHMS completions are the clear choice in the Marcellus Shale. Therefore, this paper demonstrates that OHMS technology provides a long-term solution for the life of wells in shale plays. Although the focus is on the Marcellus Shale, principles from this paper can be applied to any unconventional shale reservoir.
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract The Stretched Exponential production Decline Model (SEDM) provides a flexible framework for forcasting production and estimating reserves in unconventional reservoirs. In the following we use the Discrete Fracture Network (DFN) concept to interpret the SEDM results obtained previously. Our study proposes that the SEDM exponent parameter, n can be related to the scale independent characteristics of the created fracture network that in turn can be considered non-varying in a given field (or larger group of wells in the same geological settings and of similar completion type.) Our hypothesis is supported by dry gas flow simulation involving stochastic generation of DFN with various characteristics. The effect of variations in natural fracture lengths, apertures, density, and connectivity are considered along with induced hydraulic fracture dimensions. In view of our findings we present another conditioning approach to robust decline curve analysis and provide application examples for selected Barnett Shale wells.
- North America > United States > Texas (1.00)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.65)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.51)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Africa > Cameroon > Gulf of Guinea > Rio Del Ray Basin > Etinde Block > IF Field (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (3 more...)