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Collaborating Authors
United States
Abstract Horizontal injection wells could be widely used in geological storage projects to provide large injectivities into formations with less favorable permeability-thickness products. Injection induced fracturing, which plays an important role in injection and storage risk assessment, is much more complex for horizontal well than vertical well,. The temperature variation of formation around wellbore due to cool CO2 injection introduces thermo-elastic stress which dramatically decrease critical fracture pressure under some strategies. According to the definition of thermo-elastic stress, the temperature profile of CO2 in horizontal wellbore essentially determines its magnitude. A model is developed to describe heat transfer between wellbore fluid and surrounding formations by extending our previous heat transfer model of vertical wellbore. In the model, CO2 flux along horizontal wellbore is divided to uniform and non-uniform flux. Mass flow rate of the former case is linear; in the latter case, mass flow rate depends is non-linear and depends of the pressure drop along the wellbore, which is related to friction loss. The model analyzes factors that affect temperature difference between wellbore CO2 and formation by several dimensionless groups: (1) dimensionless ratio of the rate of heat transfer to the rate of advective transport of enthalpy in vertical wellbore; (2) the length ratio of horizontal well over vertical well; (3) dimensionless friction factor. With new criterion by considering the influence of thermo-elastic stress, we optimize perforation zone of horizontal wellbore to prevent fracturing. Additionally, the influence of formation properties wellbore pressure is discussed to estimate safe perforation zone of horizontal wellbore.
- North America > United States > Oklahoma > Anadarko Basin > M Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- (3 more...)
Abstract Horizontal wells with hydraulic fracture treatments have been proven to be an effective method for developing unconventional oil and gas reservoirs. During the last several years, fracturing methods have evolved and improved rapidly, however, there still exists many uncertainties in fracture design. Several fracture diagnostic techniques have been developed to improve the understanding of the fracturing process. In this study, after reviewing the application and limitations of the current fracture diagnostic techniques, we describe the application of distributed temperature sensing technology (DTS) as a complementary tool for real-time fracture diagnostics. DTS has enabled us to observe the dynamic temperature profile along the wellbore during the treatment. However, quantitative interpretation of dynamic temperature data is very challenging and requires in-depth mathematical modeling of heat and mass transfer during the treatment. We have developed a thermal model to simulate the temperature behavior along the wellbore during the treatment as well as during the shut-in period. This model takes into account the effect of all significant thermal processes involved, including conduction and convection. Examples are presented to illustrate how this model can be applied for fracture stimulation diagnostics. Estimation of the fracture initiation points, number of created fractures, distribution of stimulation fluid along each isolated zone, effectiveness of isolation are the problems that DTS can help us to obtain the answers. This information can be used for more accurate fracture modeling and better estimation of fracture conductivity and fracture geometry, and therefore to optimize the future treatments and also evaluate the well performance.
- North America > United States > Texas (1.00)
- Europe (0.93)
- North America > Canada (0.69)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- (2 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.89)
- Information Technology > Artificial Intelligence (0.69)
Abstract Air-injection-based recovery processes are receiving increased interest due to their high recovery potentials and applicability to a wide range of reservoirs. However, most operators require a certain level of confidence in the potential recovery from these (or any) processes prior to committing resources, which can be achieved with the use of numerical reservoir simulation. In a previous paper (JCPT, April 2009, pp. 23–34) it was proposed that, after successful laboratory testing, analytical calculations and semi-quantitative simulation models would be used for pilot design and further optimization of the actual operation. However, the specific steps for building the field-scale simulation models were not explicitly addressed. This paper discusses a detailed workflow which could be followed to engineer an air injection project using thermal reservoir simulation. The first step of the simulation study involves the selection of a kinetic model which could be either developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudo-components employed by the kinetic model and relevant PVT data would be matched to develop a fluid model for the thermal simulator. This new fluid model is used in the field-scale simulation model to history match the production history (i.e. prior to air injection) of the field. Third, relevant combustion tube tests would be history matched to validate the kinetic model and refine the thermal data that would go into the field-scale model. Finally, the results and knowledge gained from the combustion tube match(es) are applied to the field-scale model with the proper upscaling of some parameters. This simulation model would aid in selecting optimum well locations and operating strategies of the pilot. It would then be refined as the actual operation progresses to enhance its predictability and allow further optimization of the project. Technical considerations, advantages, and limitations of each step of the workflow are discussed in detail. This paper also presents workflow variations and recommendations applicable to new and already mature air injection projects for which simulation models are being developed.
- North America > United States (1.00)
- Europe (1.00)
- Asia (0.93)
- North America > Canada > Alberta (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.96)
- Geology > Geological Subdiscipline (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- South America > Argentina > Mendoza > Cuyana Basin > Barrancas Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Mordovo Karmalskoye Field (0.99)
- (4 more...)
Abstract In most developing shale plays, there is a learning curve for determining which factors best affect well production and yet still leave them economical. Advancing up this curve can take years to achieve as operators adopt a baseline treatment and th en adjust certain specific variables to find the best economic solution. However, by evaluating the reservoir on a playwide basis, the ability to find the optimal treatment method can be expedited, benefiting the operators by allowing them to achieve better wells earlier in the play’s development. Though many factors can hold a major influence (e.g., wellbore placement, rock properties, and flowback procedures), this study will review the production impact of specific variables of the fracture treatments, including well location. Using public production data with a database of stimulation treatments for several hundred wells in the Haynesville shale, variables such as pumping rate, volumes, proppant (type and volume), frac stage designs, base fluid, and surfactant usage can be analyzed to find which ones produce a positive effect on a well’s production. In addition to a well’s overall production magnitude, in the majority of the shale plays, regulating the decline of the production curve sometimes has been a crucial element in achieving the estimated ultimate recovery needed to make the play development economical. The stimulation-variables database will also be investigated to determine which factors can have an influence on ensuring a production curve’s decline will level off at a higher percentage of its initial production. By selectively identifying and grouping wells inside and outside the core area of the play, this study distinguishes which variables are positively affecting production while reducing the masking effect caused by geographic location. Conventional fracturing theory is applied to offer explanations of what might be occurring inside the reservoir or fracture system to make these findings hold true (or, at least, plausible).
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.80)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- (5 more...)
Abstract Ultra-low permeability shale gas reservoirs have emerged as a significant source of natural gas in North America. Improved drilling, completion and stimulation techniques combined with declining conventional gas reserves have made shale gas a desirable commodity with significant long-term production potential. Despite extensive development and production (particularly in North America), minimal work has been done to develop tools and methodologies for shale gas prospect analysis. Due to the complexity and large extent of unconventional natural gas resources, it is crucial to be able to investigate potential prospects in a methodical manner to determine whether a given prospect has commercial potential and to compare it to other potential prospects. Experience has shown that conventional exploration techniques using deterministic solutions are not suitable for unconventional prospects due to the unique nature of each prospect and the complexity of each reservoir. The most common method for exploiting shale gas reservoirs is through the use of multi-fractured horizontal wells; the resulting well performance, influenced by both the stimulation treatment and complex reservoir attributes, precludes the use of traditional techniques for production data analysis and forecasting. Several new techniques have been developed to improve the quality and efficiency of analysis while accounting for properties that are unique to shale gas (i.e. adsorbed gas in self-sourced reservoirs and nanodarcy level permeability). Also, due to the complexity of shale gas reservoirs, many authors have suggested that deterministic analysis is unsuitable and that probabilistic analysis should be used to quantify the risk and uncertainty associated with shale gas prospects and the associated data. This paper discusses a new tool that was developed specifically for shale gas prospect screening. This tool combines the latest production data analysis and forecasting techniques with a simple, yet rigorous method for stochastically comparing shale gas prospects. The paper discusses the production analysis and rate forecasting techniques used in the tool, as well as the tool development and application. A sample case using simulated data is presented for proof of concept and a discussion is given for extension of the tool for comparison of several potential prospects.
- North America > United States > Texas (1.00)
- Asia (1.00)
- Europe (0.93)
- North America > Canada > Alberta (0.69)
- Research Report (0.68)
- Overview > Innovation (0.34)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
- (16 more...)
Abstract Previous works have presented the results of successful simulations of fluid injection into naturally fractured shale using a Discrete Element Model (DEM). The simulations included coupled fluid flow-deformation analysis, failure type and extent calculations, as well as a series of parametric analyses. The parameters investigated included: 1) injection rate and its effect on the overall fracturing results, and 2) fluid viscosity, which had a significant influence on the ratio of tensile (mode 1) failure versus shear failure. With the huge growth in the stimulation of naturally fractured formations such as fractured shales, it is clear that the industry needs new hydraulic fracturing simulation tools beyond the limits imposed by pseudo3D fracturing models. DEMs, in which both matrix block behavior and fracture behavior are explicitly modeled, offer one option for the specific modeling of hydraulic fracture creation and growth in a naturally fractured formation without, for example, the assumption of bi-planar fracture growth. In this paper, we extend the previous works to quantify, for fractured shale gas plays, the effect of stress orientation, fluid viscosity, and rock mechanical properties in terms of changes in fracture aperture and transmissivity. Changes in fracture transmissivity directly correlate with improvements in well productivity – the primary goal of the stimulation. The results of the study provide a means to improve shale completions by understanding the effects of the DFN orientation relative to the stress field, fluid viscosity, and rock mechanical properties on changes in fracture aperture, fracture transmissivity, and formation effective permeability, which directly relate to well productivity.
- North America > United States > Texas (1.00)
- Europe (0.68)
- Overview (0.46)
- Research Report > New Finding (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.91)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.49)
- 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 > Texas > Permian Basin > Yeso Formation (0.99)
- (28 more...)
Abstract Tight oil formations (permeability <1 mD) in Western Canada have recently emerged as a reliable source of light oil supply owing to the use of multi-fractured horizontal wells. The Cardium Formation, which contains 25% of Alberta’s total discovered light oil (according to Alberta Energy Resources Conservation Board), consists of conventional and unconventional (low-permeability or tight) play areas. The conventional play areas have been developed since 1957. Contrarily, the development of unconventional play areas is relatively recent. The lag in development of the unconventional play is due to considerably poorer reservoir properties which increases the risk associated with capital investment. This in turn implies the need for a comprehensive and critical study of the area before planning any development strategy. This paper presents performance results from the low permeability portions of the Cardium Formation where new horizontal wells have been drilled and stimulated in multiple stages to promote transverse hydraulic fractures. Development of the tight Cardium Formation using primary recovery is considered. The production data of these wells was first matched using a black oil simulator. The calibrated model presented was used for performance perditions based on sensitivity studies and investigations that encompassed design factors such as well spacing, fracture properties, and operational constraints. These simulation sensitivities were used to make economic predictions to assist with optimal design. In conclusion, based on our simulation results, we provide the operators of the Cardium tight portion with some recommendations to optimize both short and long-term profit.
- Geology > Geological Subdiscipline (0.69)
- Geology > Petroleum Play Type > Unconventional Play (0.44)
- Geology > Petroleum Play Type > Conventional Play (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > Canada Government (0.34)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Cardium Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Cardium Formation (0.99)
- (2 more...)
Abstract The determination of fracture density and orientation is important in plays in which reservoir permeability is associated with micro-fractures. In these reservoirs, effective porosity is dependent upon the density of open fractures and permeability has a directivity component associated to the fractures’ orientation. Accurate determination of fracture density and orientation using surface seismic helps, then, in determining locations of good reservoir storability, as well as directional drilling orientation for optimum permeability. The anisotropy of P- and S-wave velocities is commonly associated with the magnitude and orientation of stress fields or open fractures and hence, is the medium through which factures can be characterized using surface seismic data. A case study in the Marcellus Shale (NE United States) is presented in which PP and PS wide azimuth seismic data, acquired and processed to preserve the amplitude and velocity information of the source-receiver azimuth, are used to compute anisotropic attributes from which a qualitative analysis of fracture density and orientation is done. The Marcellus Shale is known to have two sets of fractures (joints) associated to different tectonic events. Particular to this play is that one set of joints is perpendicular to the co-located macro-fractures. In this case, although curvature or other geometric attributes reveal the strike of macro-fractures, this does not correspond to the joint sets, which are at sub-seismic resolution. Anisotropy analysis through elliptical inversion of P-wave velocities identifies both sets of micro-fractures and verifies their expected position in relationship to the oroclinal belt and the macro-fractures. Analysis of PS migrated stacks supports these observations.
- North America > United States > West Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- North America > United States > Ohio (1.00)
- (4 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.57)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.55)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.88)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.31)
- 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 > Tennessee > Appalachian Basin (0.99)
- (8 more...)
Abstract Shape memory polymer foam is currently being deployed in down-hole sand control applications. The shape memory polymer is molded in a cylindrical geometry with a desired outer diameter and inner diameter. The geometric profile is altered to specifications with an inner drainage layer, to satisfy the run in requirements of the tool. Once set down hole, the shape memory polymer will start deploying to the original outer diameter of the original geometric profile. The polymer will continue to deploy and conform to the bore wall. This shape memory polymer has a permeability that is 25 times greater than that of the formation permeability to prevent plugging risk, and ensure that there is negligible to no impedance to production. Gravel packing is a form of sand management used for decades during the production of oil and gas. This paper compares the sand control characteristics of shape memory polymer foam against conventional gravel packs under similar conditions, loads, and formation sands. We will show how the performance of the shape memory polymer can eliminate the need of gravel packing altogether within a given bottom hole temperature range.
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > San Andreas Formation > Upper San Andreas Formation (0.98)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > Lower San Andreas Formation > Upper San Andreas Formation (0.98)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > Lovington Formation > San Andreas Formation > Upper San Andreas Formation (0.98)
- (5 more...)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
Abstract This paper discusses a modeling technique that can be used to predict the gas production from Marcellus Shale wells. The fundamental concept is to model the relationship between pressure and production over time using inflow performance relationships and volumetric calculations. The model can be adjusted to fit the production values and then used to predict production on that well or on offsetting wells based on the pressures that are expected. The introduction of this paper provides a general description of the characteristics and production volumes that are typical of horizontal Marcellus wells. The theory separates the reservoir into two systems; the stimulated reservoir and the matrix reservoir. From these systems inflow performance relationships, decline curves, and volumetric calculations are used to build the model. Over time, the inflow performance curves will change. With this model, an inflow performance curve can be generated at any point in the life of the well. By creating a model for a well, a prediction can be made of the well’s production if conditions change. This could be extremely helpful in modeling pipeline and compression systems or evaluating wells under changing conditions. It can also be used to estimate potential production from curtailed wells. Over time, the model may also be used to indicate if damage or enhancements have occurred or if chemical, mechanical or stimulation treatments were effective. The technique could easily be applied to other similarly designed wells. This could include other shale wells, CBM wells or wells in naturally fractured reservoirs. This paper presents a theory that is a "first run" concept, based on previous work, theories, and observations. The technique presented can be expanded and refined by future researchers.
- North America > United States > Pennsylvania (1.00)
- North America > United States > West Virginia (0.71)
- North America > United States > Virginia (0.71)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.82)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.61)
- 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)
- (3 more...)