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Collaborating Authors
Hydraulic Fracturing
Optimization of Horizontal Wellbore and Fracture Spacing Using an Interactive Combination of Reservoir and Fracturing Simulation
Taylor, R. S. (Halliburton) | Glaser, M. A. (Murphy Oil) | Kim, J.. (Murphy Oil) | Wilson, B.. (Murphy Oil) | Nikiforuk, G.. (WestMan Exploration) | Noble, V.. (WestMan Exploration) | Rosenthal, L.. (WestMan Exploration) | Aguilera, R.. (University of Calgary) | Hoch, O.. (Hoch & Associates) | Storozhenko, K.. (KJS & Associates) | Soliman, M.. (Halliburton) | Riviere, N.. (Halliburton) | Palidwar, T.. (Halliburton) | Romanson, R.. (Halliburton)
Abstract The application of horizontal wellbore drilling and multistage fracturing technology has been playing a pivotal role in unlocking shale-gas reserves globally. More recently, the same technology has been applied to both new and mature oil fields. A key question for economic optimization of these assets is what fracture spacing to use along a horizontal wellbore. Of equal importance is what spacing to use for multilaterals and the wellbores themselves to achieve optimal drainage of the reservoir. In addition, the design of the fracturing treatments must be optimized. To address these questions, a combination of reservoir and fracturing simulation has been applied. The required input data are provided through a combination of advanced log and core analyses, diagnostic fracture injection testing (DFIT), rate transient analysis (RTA), and characterization of fracture geometry through microseismic monitoring. Fluid rheology is characterized using pressurized rheometers and flow loops. This paper presents results of this work using examples of current Canadian oil and shale-gas reservoirs and a methodology to improve the economic return of different completion and production scenarios.
- North America > United States (0.46)
- North America > Canada > Alberta (0.29)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.57)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.49)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (3 more...)
Abstract Performance prediction of wells producing from tight microdarcy formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse and/or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting. We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviors. These tools include (a) traditional decline-curve analysis (Arps formulation), (b) Valko's stretched-exponential method, (c) Ilk et al's power-law exponential method, (d) rate-transient and transient-PI analyses to ascertain the stimulated- reservoir volume, and (e) numerical simulation studies to gain insights into observed flow regimes. The benefits of collective use of analytical modeling tools in history-matching and forecasting both short- and long-term production performance of tight-oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions, all became feasible by using an ensemble of analytical tools.
- North America > United States > Texas (0.93)
- Europe (0.88)
- Geology > Rock Type (0.49)
- Geology > Geological Subdiscipline (0.49)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (6 more...)
Abstract A numerical study of hydraulic fracture growth from a circular borehole under plane strain conditions is presented. The coupling of fluid flow and rock deformation plays a key role in the fracture reorientation process and in determining the curved fracture path formed. The fracture path is given as a function of both the nondimensional parameter ฮฒ, which has been previously described in the literature and applies to fracture growth that is dominated by rock fracture toughness, and the recently derived nondimensional parameter ฯF, which applies to fracture growth that is dominated by fluid viscous dissipation. The results show that the values of ฮฒ and ฯF determine the fracture trajectory as the fracture grows from the wellbore and eventually reorients parallel to the maximum far-field stress direction. Thus, for viscous dominated conditions that are typical of field application of hydraulic fracturing for stimulation, ฯF is a measure of the development of nearwellbore fracture tortuosity. A larger value of ฯF implies a stronger curvature and fracture tortuosity. The value of ฯF is reduced by increasing the viscosity and injection rate of the fluid.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (0.69)
Abstract Although hydraulic fracturing has become the second largest outlay of petroleum companies after drilling, design and execution issues are still heavily contaminated by lingering misconceptions and inadequate empirical "rules-of-thumb". Some of the most common problems include issues such as "maximizing" fracture conductivity or fracture length (sometime referred to as "effective" or "apparent"), or even more inadequate goals during execution such as cutting costs by shortening the injection time and using the cheapest possible proppants. Since the introduction of the Unified Fracture Design (UFD) approach, practitioners have a coherent method to design fracturing treatments aiming to maximize the post-treatment productivity index. The central idea of the UFD technique is to select an optimum compromise between propped fracture length and width, for a given proppant volume and depending on the properties of the reservoir and the selected proppant. We present in this paper a wide range of parametric studies for oil and gas reservoirs with permeability ranging from 0.01 md to 500 md, and we assess the impact of treatment size (mass of proppant injected) and proppant pack permeability, starting from the UFD-determined optimum designs and then departing towards suboptimal conditions. These include fracture length, the fracture conductivity and fracture height (by using the concept of fracture aspect ratio). We also apply the same approach to study gas wells, in which turbulence effects in moderate to high permeability reservoirs require the adjustment of optimum design geometry. Finally, we show how a proper candidate selection among a given portfolio for hydraulic fracturing treatments can easily provide a much higher incremental production from a much smaller number of treatments. We use both vertical and horizontal well fracturing. Our results show clearly that there is a lot of room for improvement in fracture designs for production enhancement, particularly dealing with larger treatments and the selection of better quality proppants (higher pack permeability), especially for gas wells. This leads to a systematic approach for design and a studious departure from optimum design conditions, when necessary, based on field constraints and reservoir and fluid characteristics.
- North America > United States > Texas (0.28)
- North America > Canada (0.28)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Restimulation treatments have been attempted in a wide variety of reservoirs, and more than 140 papers have been published documenting the success and failure of these efforts. A database of these published examples has been compiled and analyzed to identify the mechanisms responsible for production improvement following restimulation with propped fractures (refracs). A portion of this database was recently published (Vincent 2010), and specific field examples were highlighted to demonstrate that refrac treatments can improve production by numerous mechanisms including: โEnlarged fracture geometry โImproved pay coverage through increased fracture height in vertical wells โGreater lateral coverage in horizontal wells or initiation of more transverse fractures โIncreased fracture conductivity compared to initial frac โRestoration of fracture conductivity loss due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. โIncreased conductivity in previously unpropped or inadequately propped portions of fracture โUse of more suitable fracturing fluids โReorientation due to stress field alterations, leading to contact of "new" rock This paper will briefly review restimulation attempts in six Canadian reservoirs of interest to the local audience, and will then present a more detailed review of restimulation of horizontal wells in the unconventional Bakken oil formation. In addition to a summary of published results, this paper will introduce a significant amount of previously unpublished data regarding refrac treatments of horizontal laterals completed in the Middle Bakken. This study will identify several additional concerns and opportunities with restimulating horizontal wellbores that were not previously identified in literature reviews. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- North America > United States > Montana (1.00)
- (11 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Overview > Innovation (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.46)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Colombia > Putumayo Department > Putumayo Basin (0.99)
- Oceania > New Zealand > North Island > Taranaki Basin (0.99)
- North America > United States > Wyoming > Washakie Basin (0.99)
- (101 more...)
- Well Completion > Hydraulic Fracturing > Re-fracturing (1.00)
- Production and Well Operations > Well Intervention > Re-stimulation (excluding re-fraccing) (1.00)
Abstract A unique workflow and methodology enabled analysis of production data using reservoir simulation to help understand the shale gas production mechanism and the effectiveness of stimulation treatments along the lateral of horizontal wells. Starting from early 2008, we have analyzed production data from more than 30 horizontal wells in the Haynesville Shale using this methodology. This paper presents case studies demonstrating results of this new technique in several different areas of the Haynesville Shale. After integration of all available data, we built simulation models for the wells stimulated with multistage hydraulic fracture treatments. This modeling work investigates factors and parameters relating to short- and long-term well performance including 1) pore pressure, 2) matrix rock quality, 3) natural fractures, 4) hydraulic fractures, and 5) complex fracture networks. By historymatching the observed production, we have identified the primary factors for creating good early well performance. The Haynesville study has provided a better understanding of the gas production mechanism and effectiveness of stimulation along the laterals. After calibration of the simulation model, effective well drainage area and reserve potential can be calculated with more confidence. The Haynesville Shale is a very tight source rock. The shale matrix quality correlates with production performance when stimulation treatments are consistent along the lateral. A complex fracture network created during the stimulation treatment is the key to generating superior early well performance in the Haynesville Shale. Knowing how to effectively create more surface area during treatment and preserve the surface area after treatment are critical factors for making better wells in the Haynesville. Operators can use this information to determine where and how to spend resources to produce better wells. It also helps refine expectations for well performance and minimizes the uncertainties of developing these properties. The workflow and methodology have also been successful in other shale plays.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- North America > United States > Arkansas (1.00)
- 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 > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.99)
- (2 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (3 more...)
Abstract In order to get a clear picture of the effectiveness of a multi-stage stimulation treatment pumped into the horizontal wellbore of a tight gas reservoir, one must integrate data from a number of different sources. This will provide a more complete forecast of the reservoir's development. The Montney formation straddles the British Columbia / Alberta border in the Western Canadian Sedimentary Basin. There is significant variability in the formation's properties across its area, but even so, we have seen a multitude of horizontal wellbores lined up within the formation in recent years. Many involved have questions about fracture spacing along a horizontal wellbore, and ultimately, the spacing of the horizontal wells in a field. The answers to these questions can lead to improved recovery factors and better economics for the resource play. In this case study, seven stages of Basal Doig / Upper Montney microseismic data are integrated with fracture pumping information, and finally incorporated into a reservoir simulator. Two years of production history from the Montney horizontal is matched to "calibrate" the four layer reservoir model and make it a predictive tool. This provides the basis for understanding of drainage radiuses around the fractures, and for recommendations on fracture spacing in order to optimize completions in subsequent wells. The calibrated reservoir model is then used as a predictive tool to understand drainage radius and productivity differences when the number of fracture stages in the wellbore is increased to reduce fracture spacing. Predictably, the cumulative production from the tight gas well with more stages is greater than the same well with fewer stages. Ultimately, there is an economic trade-off between completing the well with more stages and increased well productivity, and an optimal combination that differs from one region to the next.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (18 more...)
- 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 > Seismic processing and interpretation (1.00)
Abstract The successful development and exploitation of unconventional reservoirs has relied on innovative technologies, such as horizontal drilling, multistage completions, modern multistage fracturing, and fracture mapping to pursue economic completions. It is important to highlight that economic production in these ultralow matrix-permeability reservoirs relies on conductivity that must be generated through hydraulic fractures and fracture-network systems. Simulations demonstrate that shale reservoirs with ultralow permeability require an interconnected fracture network of moderate conductivity (branch fractures) with relatively small spacing between fractures to obtain economic production rates and reasonable recovery factors. This paper discusses two recently developed hydraulic fracturing processes to improve economic recovery in unconventional reservoirs. The first new process is designed for multistage-fracturing treatments with high pumping rates and low proppant concentration. This method uses the efficiencies of tubing-deployed abrasive perforating. Proppant slurries are then pumped down the coiled tubing (CT) and nonabrasive clean fluid is pumped down the annulus, saving the permanent tubulars from erosion. As a result, the rate down the annulus can be much higher. The pumping rate can be instantly manipulated to customize the placement and concentration of proppant being pumped down the CT. In case of premature screenout, a well could be easily reverse-circulated and cleaned for the next stage. Wellbore proppant plugs eliminate the need for overflushing, and the new approach to fracture stimulation, known as branch fracturing, could be achieved by changing proppant concentration in real time. The second new process uses a combination of mechanically activated sleeve completions and fracturing of individual intervals with a change in the sequence in which the intervals are stimulated. This new method is proposed with the goal of altering the stress in the rock to facilitate branch fracturing and to connect to induced stress-relief fractures in a single, horizontal well.
- North America > United States > Texas (1.00)
- North America > Canada (0.68)
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock (0.35)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
Abstract Mapping the microseismic activity during a hydraulic treatment is widely used to determine the geometry of the stimulated fracture network. Microseismic maps provide reliable information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Beyond that, these fracture geometries are used to better understand fracture modeling and even production characteristics. Fiber-optic-based distributed temperature sensing (DTS) arrays provide almost immediate updates of the near-wellbore temperature distribution in approximately one-meter intervals. In injection treatments, the near-wellbore temperature distribution can be used to determine isolation effectiveness, the relative amount of fluid each perforation cluster takes, fracture initiation points, and effective fluid diversion. In production analysis, DTS measurements can quantify production rates from each perforation interval, crossflow rates while shut-in, and fluid types recovered from each perforation interval. The detailed near-wellbore results available through DTS coupled with the far-field geometry acquired through microseismic mapping provide an accurate picture of the completion effectiveness. Microseismic mapping results often show adequate resolution over a large area but lack the fine resolution that would allow it to identify near-wellbore effects in the meter range. When modeling and interpreting the treatment geometry obtained by the microseismic-event distribution, it is important to include the correct near-wellbore effects, which are readily accessible through DTS measurements. Combining the two diagnostic tools is valuable for real-time decision making, post-treatment analysis, and production analysis to assess the completion effectiveness. Incorrect assumptions about perforation breakdown, fracture-initiation points, interval isolation, or limited-entry effectiveness can lead to misinterpretations of the microseismic results. Using both diagnostic tools provides firm answers to the overall completion effectiveness. This paper focuses on three distinct aspects of combining the analysis of microseismic mapping and DTS. The first is the real-time aspect, wherein real-time decisions and adjustments are made during the fracture treatment with the objective of manipulating the results towards the desired outcome. The second is using both tools to perform more accurate postfracture analysis, including calibrated fracture modeling, entry effectiveness, correct interval spacing, and stimulated reservoir volume (SRV) analysis. The third area covered is combining these diagnostic tools with a production analysis, which is acquired through analysis of the temperature data.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Overton Field (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract This paper summarizes the approach used for applying integrated reservoir modeling to the tight gas sands of the Pinedale Anticline in western Wyoming. The simulation of tight gas sands such as those at Pinedale has always been challenging because of the high degree of heterogeneity that needs to be retained to replicate reservoir performance, coupled with computing constraints. Added to this, simulating the Pinedale reservoir has its own unique challenges due to its characteristically thick gross sand interval composed of multiple, heterogeneous sand bodies produced commingled in a well. An intensive data-gathering program to investigate optimum well spacing accompanied the simulation effort. A significant part of this program was the installation of pressure monitor wells1 to detect communication with surrounding producers at the hydraulic fracture stage level. This was coupled with multiple time-lapse production logs. The two data sets together allowed better definition of stage performance at producing wells. Static models were built with fine resolution to duplicate reservoir heterogeneity. However, upscaling was necessary due to computing constraints. The upscaling procedure of Li and Beckner2 was utilized to maintain substantial geologic heterogeneity. The upscaled model was calibrated to mimic fine scale well performance prior to history matching. Several sector upscale models were history matched using a statistical approach without compromising key aspects such as reservoir connectivity and proper mass withdrawal from each geologic sub layer. Hydraulic fractures in each stage were characterized through history matching. Given the geostatistical nature, an exact match on every frac stage and every pressure gauge located away from the producer should not be expected. Rather, a more statistical definition of a history match should be adapted to a level that still gives confidence in forecasting the value of future infill wells. The history-matched parameters were then statistically distributed to forecast more realistic future development wells. The availability of data including pressures at observation wells and production logs was critical in narrowing the range of uncertainty in the history-matched scenarios and reduced the degree of non-uniqueness in the model thus resulting in increased confidence in model forecasts. This paper describes the methods used to overcome many of the problems encountered in modeling heterogeneous tight gas sands, such as at the Pinedale Anticline.
- North America > United States > Wyoming (0.67)
- North America > Canada > Alberta (0.47)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- North America > United States > Wyoming > Green River Basin > Pinedale Field (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)