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Results
Abstract Recent analytical models for abnormal and normal leakoff mechanisms of the pressure falloff behavior in fracture calibration tests (DFITs) provide means to match virtually all of the behavior. The match provides both the parameters related to normal leakoff behavior including closure pressure and the leakoff coefficient as well as abnormal leakoff parameters including tip extension distance and minimum fracture propagation pressure, closure pressures, leakoff coefficients, and leakoff areas for the coupled primary and secondary fracture system. The purpose of this paper is to provide a methodology for identifying these behaviors and quantifying all of the before closure parameters of interest to design of the main fracture treatment. We use the behaviors seen on the log-log Bourdet and the G-function derivatives to identify a sequence of flow regimes and to estimate starting values for the parameters associated with each leakoff behavior. Simulation result with these starting estimated values are able to catch all identified leakoff features. Then we adjust the parameter starting values to achieve a global smooth match for the falloff data. Equations developed for quick estimation of the starting values facilitate the model match with data. Several field cases with pressure dependent leakoff (PDL), tip-extension, multiple-closure phenomenon and transverse storage are taken as examples to illustrate the comprehensive modeling capability. The additional parameters quantified by this methodology have their reasonable physics and greatly enhance understanding of the role of tip extension and the induced secondary fracture system in the hydraulic fracture stimulation.
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Colorado > Mamm Creek Field (0.99)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (3 more...)
Abstract Since the inception of the oil boom in North Dakota, the Williston basin has witnessed a tremendous growth in horizontal drilling and completion activity primarily targeting the Bakken and Three Forks formations. Although the activity in the basin is maturing in terms of our understanding rock quality and completion quality, there is a wide variation of these indices within the basin from one field to another. Some of these variations are clearly noticeable in parameters such as thicknesses of the shale barriers, pore pressure gradients, reservoir permeabilities, porosities and stress gradients. The combined impact of these parameters has a huge impact on key decisions including, but not limited to, completion methodologies, types of proppants and fluids used for completion, number of fracturing stages in the lateral, number of perforation clusters per stage, and well spacing. This paper discusses the evolution of stimulation strategies and completion practices in the Williston basin since 2009. Operators have experimented with cemented and uncemented laterals; sliding sleeves and plug-and-perf completions; lateral lengths ranging from 5,000 to 10,000 ft; perforation clusters ranging from one to six per stage; crosslinked, hybrid, and slickwater fluid systems; proppants ranging from sand to ceramic, etc. The consequent impacts of these variations on well completion pressure responses and long-term production have been mixed. As part of the work covered in this paper, the differences between various completion methodologies and their impact on the stimulation strategies have been discussed in a chronological order. Although there is no single optimized design for the entire basin, experimentation of multiple methods and technical interpretation of various fracture and production models have provided us with a strong foundation to narrow down our practices to the most successful and repeatable ones across all the fields in the Bakken and Three Forks formations. The paper also covers how real-field measurements such as diagnostic fracture injection tests (DFITs), microseismic data, radioactive or chemical tracers, bottomhole pressure gauges, and interference experiments combined with log measurements such as magnetic resonance, acoustic logs, and elemental spectroscopy can provide us with a strong base for building and calibrating reservoir models that are reliable and reasonable. The paper covers technical differences between sliding sleeves and plug-and-perf completions; differences between crosslinked, slickwater, and hybrid designs and their impact on fracture geometries; effect of using different proppant types; and ways to optimize the number of fracturing stages and proppant and fluid volumes. As part of the study, the importance of geomechanics in understanding planar versus complex fracture geometries is discussed to close the loop with reservoir simulation models.
- North America > United States > South Dakota (1.00)
- North America > Canada (1.00)
- North America > United States > North Dakota > Mountrail County (0.28)
- North America > United States > Montana > Richland County (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.36)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- North America > United States > North Dakota > Rough Rider Field (0.99)
- North America > United States > North Dakota > Parshall Field (0.99)
- North America > United States > North Dakota > Antelope Field (0.99)
- (8 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- (6 more...)
First Application for a Sequenced Fracturing Technique to Divert Fractures in a Vertical Open Hole Completion: Case Study from Saudi Arabia
Bartko, Kirk (Saudi Aramco) | Tineo, Roberto (Schlumberger) | Aidagulov, Gallyam (Schlumberger) | Al-Jalal, Ziad (Schlumberger) | Boucher, Andrew (Schlumberger)
Abstract A unique sequenced fracturing technique using formation notching and degradable diversion pills was applied for the first time in a vertical open hole completion to stimulate multiple pay intervals in a well in the "Q" sandstone formation of Saudi Arabia. The challenge to divert fractures in a vertical open hole is made more difficult by the large fracture surface area in contact with the wellbore. A robust, efficient and repeatable two-step technique was implemented to provide the diversion and controlled breakdown of higher-stressed sections of the interval. The first step used a specialized jetting nozzle to create circular notches and weaken the formation at target depths. The second step involved the pumping of a small volume of a composite fluid of degradable non-damaging fiber and particles that bridge at the fracture face, to divert the remainder of the treatment to under-stimulated sections of the interval. The target for this well was a shallower formation due to completion pressure limitations while fracturing. This left six pay intervals spread across the tight, heterogeneous sandstone layers of the Q formation, which was completed as a single 552-ft. vertical open hole section. Previous experience showed large stress variations in the layers with contained fractures, and fracturing all pay intervals required separate treatments for each interval. After notching the pay intervals to reduce breakdown pressures, the interval was fractured with three proppant ramps separated by two diversion pills in the span of 8 hours, improving efficiency by more than three times. Diversion was confirmed by: (1) pressure increases of 380 psi and 500 psi, respectively, when the pills landed on formation; (2) increasing trend of the instantaneous shut-in pressures (ISIP's) throughout the treatment, resulting in 1,270 psi of net pressure gain; and (3) comparison of post-diagnostic injection test temperature log data with post-fracturing neutron log data, showing where nonradioactive traceable proppant was placed, including into at least three pay intervals not broken down during the injection test. Post-treatment production expectations were met and confirmed with a well test. This paper will present the design, execution, and evaluation methodology and challenges overcome to divert hydraulic fractures in long vertical open hole intervals using this two-step diversion process for sequenced fracturing. The ability to do this consistently and predictably can provide a practical, efficient, and cost-effective preferred solution that does not exist today for completing and fracturing similar zones that are traditionally bypassed, resulting in increased production and reserves.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (0.71)
- (2 more...)
Abstract The Three Forks Formation in the Williston Basin has started to see a large increase in activity in the past six years. This is largely due to the shallower Bakken Formation transitioning into an infill development mode and operators looking at finding incremental reserves from the Three Forks Formation below. The objective of this paper is to evaluate the geological and completion variables of Three Forks horizontal wells in the North Dakota portion of the Williston Basin, and show which factors impact production performance using multivariate statistics. A financial evaluation of the completion factors will also be presented to show which variables have the biggest impact on production. A database of available completion and geological data has been assembled from the North Dakota Industrial Commission (NDIC) website. To date there are roughly 2,400 horizontal wells targeting the Three Forks Formation on the North Dakota side of the Williston Basin. Some of the variables collected include number of fracture stages, amount and type of proppant, total volume and type of frac fluid, lateral length, max treatment pressure and rate, API oil gravity, formation thickness (from formation tops) and production. The data was subjected to multivariate nonlinear statistical analysis. This type of analysis allows for simultaneously comparing multiple variables to one outcome variable. In this case study the outcome variable is 180-day production. Using multivariate analysis in the Three Forks Formation of the Williston Basin will aid in predicting production in different parts of the basin and finding which controllable completion variables have the most significant impact on production. The output can also aid in production forecasting based on changes to treatment designs.
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.98)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.97)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.97)
- (2 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (3 more...)
Abstract Modern hydraulic fracture treatments rely heavily on the implementation of formation property details such as in-situ stresses and rock mechanical properties, in order to optimize stimulation designs for specific reservoir targets. Log derived strain and strength calibrated in-situ properties provide critical description of stress variations in different lithologies and at varying depths. From a practical standpoint however, most of the hydraulic fracture simulators that are used for fracturing treatment design purposes today can accommodate only a limited portion of a geologic-based rock mechanical property characterization which targets optimal data integration thus resulting in complexity. By using examples from hydraulic fracture stimulations of coals in a complex but well characterized stress environment (Surat Basin, Eastern Australia) we distil out the reservoir rock related input parameters that are determinants of hydraulic fracture designs and identify those that are not immediately used. In order to understand the impact on improving future fracture stimulation designs, the authors present workflows such as pressure history matching of fracture stimulation treatments and the calibration process of key rock mechanical parameters such as Poisson's ratio, Young's modulus, and fracture toughness. The authors also present examples to discuss synergies, discrepancies and gaps that currently exist between ‘geologic’ geomechanical concepts (i.e. variations in the geometry and magnitude of stress tensors and their interaction with pre-existing anisotropies) in contrast to the geomechanical descriptions and concepts that are used and implemented in hydraulic fracturing stimulations. In the absence of a unifying hydraulic fracture design that honors well established geologic complexity, various scenarios that allow assessing the criticality, usefulness and weighting of geologic/mechanical property input parameters that reflect critical reservoir complexity, whilst maintaining applicability to hydraulic fracturing theory, are presented in the paper. Ultimately it remains paramount to constrain as many critical variables as realistically and uniquely possible. Significant emphasis is placed on reservoir-specific pre-job data acquisition and post-job analysis. The approach presented in this paper can be used to refine hydraulic fracture treatment designs in similar complex reservoirs worldwide.
- North America > United States > Texas (0.67)
- Oceania > Australia > Queensland (0.49)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.93)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.69)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.70)
- Geophysics > Borehole Geophysics (0.68)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- (4 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Wellbore Design > Rock properties (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (2 more...)
Abstract Evaluating the effects of asymmetric stress distribution around a lateral can greatly help optimize completion techniques and overall production from in-fill horizontal wells in unconventional shale and tight reservoirs. Several factors affect long-term production from in-fill drilled wells including but not limited to pressure depletion from produced wells, change of effective stresses in the depleted formation and interference between hydraulic fractures when the new in-fill wells are drilled, stimulated and brought into production. The study addresses a variety of key challenges that the unconventional oil and gas industry is looking to understand. These include understanding: How the presence of a depleted wellbore affects hydraulic fracture propagation from a nearby newly drilled well How refracturing considerations in a producing well are affected by hydrocarbon drainage and modified stress contrasts How fracturing/refracturing pumping designs and volumes should be optimized to address the challenges surrounding the wellbore Under circumstances mentioned above, pressure distribution around the wellbore from hydrocarbon drainage was estimated by history matching production data over a certain period of time. Then the impact of various types of fracturing treatments on pressure depletion profiles from offset wells was studied using a fully numerical fracture simulator that is capable of handling asymmetric stress distribution around the lateral. Fracture geometries from this study were either asymmetric due to depletion on only one side of the lateral or longer due to increased stress contrast. These fracture geometries were fed to a production model to forecast long-term production from in-fill wells and study drainage patterns over time. Understanding these challenges provided a sub-surface perspective of how completion techniques should be optimized to get maximum hydrocarbon recovery from reservoirs consisting of laterals that have already been on production.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology (0.94)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.35)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.98)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.95)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.95)
- (3 more...)
Abstract Three-dimensional (3D) geomechanical models built at reservoir scale lack resolution at the well sector scale (e.g., hydraulic fracture scale), at least laterally. One-dimensional (1D) geomechanical models, on the other hand, have log resolution along the wellbore but no penetration away from it—along the fracture length for instance. Combining borehole structural geology based on image data and finite elements (FE) geomechanics, we constructed and calibrated a 3D, high-resolution geomechanical model, including subseismic faults and natural fractures, over a 1,500- × 5,200- × 300-ft sector around a vertical pilot and a 3,700-ft lateral in the Fayetteville shale play. Compared to a 1D approach, we obtained a properly equilibrated stress field in 3D space, in which the effect of the structure, combined with that of material anisotropy and heterogeneity, are accounted for. These effects were observed to be significant on the stress field, both laterally and local to the faults and natural fractures. The model was used to derive and map in 3D space a series of geomechanically based attributes potentially indicative of hydraulic fracturing performance and risks, including stress barriers, fracture geometry attributes, near-well tortuosity, and the level of stress anisotropy. An interesting match was observed between some of the derived attributes and fracturing data—near-wellbore pressure drop and overall ease and difficulty to place a treatment—encouraging their use for perforation and stage placement or placement of the next nearby lateral. The model was also used to simulate hydraulic fracturing, taking advantage of such a 3D structural and geomechanical representation. It was shown that the structure and heterogeneity captured by the model had a significant impact on hydraulic fracture final geometry.
- North America > United States > Texas (0.46)
- North America > United States > Arkansas > Washington County > Fayetteville (0.25)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.55)
- North America > United States > Oklahoma > Arkoma Basin > Fayetteville Shale Formation (0.99)
- North America > United States > Arkansas > Arkoma Basin > Fayetteville Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.98)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract In 1898, Kirsch published equations describing the elastic stresses around a circular hole that are still used today in wellbore pressure breakdown calculations. These equations are standard instruments used in multiple areas of petroleum engineering, however, the original equations were developed strictly for vertical well settings. In today's common directional or horizontal well situations, the equations need adjusted for both deviation from the vertical plane and orientation to the maximum and minimum horizontal in-situ stress anisotropy. This paper provides the mathematical development of these modified breakdown equations, along with examples of the implications in varying strike-slip and pore pressure settings. These examples show conditions where it is not unusual for breakdown pressure gradients to exceed 1.0 psi/ft and describes why certain stages in "porpoising" horizontal wells experience extreme breakdown issues during hydraulic fracturing treatments. The paper also discusses how, in most directional situations, the wellbore will almost always fail initially in a longitudinal direction at the borehole wall, after which the far-field stresses will take over and transverse components can be developed. Tortuosity and near wellbore friction pressure can actually add to forcing the initiation of such longitudinal fractures, which can then have cascading effects on other growth parameters such as cluster-to-cluster and stage-to-stage stress shadowing. Special considerations for highly laminated anisotropic formations, where shear failure of the wellbore may precede or preclude tensile failure, are also introduced. Such failure behaviors have significant implications on near wellbore conductivity requirements and can also greatly impact well production and recovery efforts.
- Europe (0.68)
- North America > United States > Texas (0.28)
- North America > United States > Colorado (0.28)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (2 more...)
Abstract The ubiquitous challenge that is faced by chemical stimulation techniques, of any kind, has always been achieving an economic and efficient distribution of the stimulation solution across the exposed reservoir interval. Many have approached this problem from a chemical perspective and others from the use of additives for mechanical diversion; however the very nature of stimulation itself means that a changing injection profile will make efficient diversion by such techniques uncertain and unpredictable. Instead, rather than relying on serendipitous deployment techniques, the approach described and reported here places true mechanical diversion as part of the well construction process. This paper will completely describe the process and achievements to date, including successful application in a number of horizontal wells completed in the Austin Chalk, as part of an overall deployment plan. Essentially, this new completion system comprises of multiple pressure actuated assemblies, distributed along the liner/casing. These assemblies, when activated, allow the lateral deployment of forty-foot needles, radially distributed at ninety-degree phasing around the casing, into the unstimulated reservoir. These subs can be precisely located across pre-selected intervals and thereby provide certainty of acid treatment distribution. The acid is pumped through the needles themselves during stimulation; however production takes place through a suite of ports. A bespoke debris basket may be run, after the stimulation treatment, in order to recover a suite of needle deployment indicators. This run, if performed, effectively establishes the success of the deployment. In order to demonstrate the concept and avoid the high-cost environment of the North Sea, a low cost field trial location was sought and identified. An Austin chalk operator was looked for that had an extensive horizontal candidate well set available for re-completion in open-hole. A number of candidate wells were then identified and the wells were recompleted and stimulated with this new system. This paper will present the entire suite of data related to these deployments, stimulation operations, lessons learned, production impact and potential. This novel technology was greatly assisted, supported and delivered via the Joint Chalk Research (JCR) council, comprising of some ten operating companies that encourage, fund and drive the development of carbonate completion and stimulation solutions.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Texas > East Texas Salt Basin > Giddings Field > Austin Chalk Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Austin Chalk Formation (0.95)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Austin Chalk Formation (0.95)
- (10 more...)
Abstract Interaction between adjacent fractures in horizontal wells has been recognized and discussed for some time. However, the scope of these discussions has been narrow and covers a limited number of actual field situations. In this paper, effects of dynamic interactions between multiple fractures are analyzed for different operational scenarios. These include effects of passive (previously fractured), active (being fractured) and multiple active fractures. A new aspect of this study, not previously covered in the literature, is examination of fracture inclination with respect to the wellbore. Paper will show that; The effect of dynamic interaction between adjacent fractures is largest when there is small difference between magnitudes of the two horizontal principal stresses, high net fracturing pressure, and short spacing between fractures. Dynamic fracture interaction is most significant when multiple fractures are created simultaneously (e. g., in Plug & Perf completions with limited entry design). There are important basic differences between dynamic interactions caused by transverse and inclined fractures. The influence is larger with inclined fractures. In multiple fracturing treatments based on limited entry, if the created fractures are transverse, dynamic interaction may cause shorter fractures to deflect and coalesce with longer adjacent fractures, thus further accelerating their growth. Compared to a single fracture, multiple limited entry fractures in horizontal wells require higher extension pressure. However, interaction between fractures is not likely to cause a significantly higher pressure in successive pumping stages in the same well. Dynamic interaction between multiple simultaneous fractures has little impact on ISIP values between successive pumping stages. In cases of small difference between the two horizontal principal stresses and high net fracturing pressure dynamic interaction can cause fracture deviations of more than 45°. This will increase the possibility of linkage between shorter fractures with longer adjacent fractures and accelerating their growth. The results presented here are in line with actual field data. The analysis presented here differs from some existing solutions in certain critical assumptions regarding the effect of a passive fracture on the propagation of an active fracture. However, the present results are in line with actual field data trends.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type (0.67)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.95)