In general, hydraulic fracturing design for unconventional reservoirs is performed using planar fracture model simulators. It is well known that the presence of natural networks combined with varying stress anisotropy can significantly impact the overall stimulation process and hence, associated oil or gas recovery.
In this study, a well-validated fracture simulator is used that explicitly accounts for the interaction between natural and hydraulic fractures under imposed stress anisotropy and performs transport of proppant in the induced complex network. Density of the natural fracture system is varied to study the scenarios, such as hydraulic fracture-governed mode and natural fracture-governed mode. For each of these scenarios, associated stress anisotropy is varied. These two parameters represent the properties of the formation that cannot be controlled. Then, multiple simulations are performed to understand the influence of design parameters, such as total slurry volume, pumping rate, and stage design for each set of fracture density and stress anisotropy. Many indicators are used, such as the stimulated fracture area, total proppant bed area, the area of the fracture above the bed, etc., to assess the efficacy of a design.
This study shows that, depending on the natural fracture density and the stress anisotropy, the benefits of pumping larger volumes of fluid to create longer fractures and effectively distribute the proppant diminishes. It also reveals that modification of the stage design can be utilized to alleviate this problem. The capability to transport proppant by increasing the pumping rate is observed to be strongly dependent on natural fracture density. The result also shows the importance of these factors for whole pad optimization because the natural fractures and stress anisotropy can significantly alter the maximum fracture length.
Thus, it becomes imperative to know the natural fracture distribution and the associated stress anisotropy to efficiently create a hydraulic fracturing design.
Using planar fracture models to match treatment pressure and improve understanding of the fracture geometry generation is not a new concept. Knowledge gained from this exercise has historically been used to improve engineered fracture completions and production, and maximize net present value (NPV); however, at some point during the progression from vertical to horizontal wellbores, many within the industry have forgotten about the learnings that can still be gained from current fracture models. Engineered completions have been largely replaced by spreadsheet efficiencies relevant to operations rather than production in too many cases. Some images of unconventional well stimulation treatments portray fractures growing in every direction, forming patterns that resemble shattered windshields, and have often excluded the known physics related to rock geomechanics, reservoir properties, and geology. Excuses to dismiss modeling are numerous and are gaining the reasoning of conformists.
Unconventional resource plays might or might not contain large numbers of natural fractures; but, current fracture models can still be used to gain insight into the fracture geometries being generated. While the development of complex fracture models continues to evolve, the industry can still gain insight to fracture geometry and resulting production using current planar fracture modeling. Caveats to this process are that it requires: Valid measured data to establish model constraints. The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model. The engineer to understand which "knobs" should be used based on real diagnostics information. The actual single well production to be an integral part of the process.
Valid measured data to establish model constraints.
The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model.
The engineer to understand which "knobs" should be used based on real diagnostics information.
The actual single well production to be an integral part of the process.
This paper demonstrates the results of honoring data measurements from a multitude of potential sources, including downhole microseismic data, downhole deformation tiltmeters, offset pressure monitoring, DTS, DAS, diagnostic fracture injection test (DFIT) analysis, injection as well as production data with bottomhole pressure measurements, etc., and the resulting observations and conclusions. Several industry examples are discussed to help frame the vast amount of information possible to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and ultimately result in improved models and completion designs.
This paper is not intended to merely demonstrate the results of the work but to spark an interest in bringing more intense engineering back to fracture stimulation modeling for horizontal completions.
Courtier, James (Laredo Petroleum) | Gray, Danny (Laredo Petroleum) | Smith, Michael (Laredo Petroleum) | Stegent, Neil (Pinnacle—A Halliburton Company) | Carmichael, James (Pinnacle—A Halliburton Company) | Hassan, Magdy (Pinnacle—A Halliburton Company) | Ciezobka, Jordan (Gas Technology Institute)
Fracture stimulation of infield or offset wells in unconventional developments can involve communication between the legacy (parent) wells and newly drilled offset (child) wells. Production from the legacy well results in a decrease in reservoir pressure and stress, which can cause pressure sinks that ultimately lead to fracturing fluid communicating between the child and parent wells. Depending on the reservoir conditions, completing infield wells can result in production losses for the parent well, and in some cases, the parent well might never fully recover its full production potential. One of the current strategies used to minimize offset well completion communication with a parent well is to perform a preemptive protection refracture of the parent well. However, for the majority of these restimulations, the operator does not receive confirmation of refracturing effectiveness—even after production data from the refractured well become available.
Under the auspices of the Gas Technology Institute, the Department of Energy helped fund a research project hosted by Laredo Petroleum (the operating company) in the Wolfcamp to better understand, among other things, the relationship between lateral well placement, production interference between laterals, effectiveness of completion sequences, and hydraulic fracture geometry in unconventional reservoirs. Two vertically stacked parent wells that had been producing for approximately 15 months were chosen as the subjects for this study. The two vertically stacked parent wells were landed in the Upper and Middle Wolfcamp formations in the Midland basin of West Texas. The objective of the study was to understand the impact of refracturing these two wells immediately before the stimulation of 11 offset child wells (part of a development program within a production corridor setting) with regard to the reservoir pressures and stresses surrounding both the parent and child wells. Conclusions were drawn based on well treatment and downhole microseismic data, which were acquired during the restimulation of the two parent wells and the completions of the 11 child wells, and data from radioactive (RA) tracers that were pumped during the refractures. Overall, microseismic analysis revealed positive pressure protection effects were achieved during the refracture.
Downhole microseismic data for the refractured wells focused on events that occurred both near the wellbores and in the far-field and the time at which they occurred relative to the execution of the restimulation. Results from the first restimulated parent well indicated that less than half of the well was successfully restimulated and, therefore, only a portion of the reservoir between the laterals was repressurized. This resulted in the development of asymmetric fractures in the offset child well in the lower pressure portion of the reservoir, while the section that was repressurized resulted in symmetric fracture development. Using real-time microseismic monitoring during the completion of the parent wells allowed for an immediate review of the acquired microseismic data and on-site adjustments to the pump schedule. As a result, the restimulation of the second parent well appeared to have more effectively repressurized the reservoir and promote the creation of symmetric fractures during the completion of the offset child well that was landed in the same formation (as the second refracture parent well). RA tracer results were in alignment with the microseismic data.
Horizontal shale completions require multistage high-pressurehydraulic-fracturing stimulation treatments to deliver commercially viableproduction in low-permeability reservoirs. Unconventional shale plays, such asthe Eagle Ford shale and Haynesville shale, often can require stimulationtreatments that must be implemented in high-pressure, high-temperature (HP/HT)conditions. Typically, these wells are completed with long casing strings, andit is critical that these monobore casing strings withstand high injectionpressures as well as maintain mechanical integrity during thermalcontraction/expansion. So, what happens when the prefracturingcasing-pressure-integrity pressure test fails? What is the "fix" that willallow treatments to be pumped at high pressure and rate? How will fracturingstages be isolated during the completion? Typically, remediation techniqueshave included everything from casing patches and expandable casing tocoiled-tubing completions. Unfortunately, these solutions can have pressurelimitations and can also be expensive. The authors of this paper will discusshow design of a 4-in. tieback string with flush joint connections equal to theproperties of the casing was capable of repairing a 5 1/2-in. monoboreproduction casing that experienced extensive casing failure. The extremelysmall annular tolerance did not allow a conventional packer assembly orcementing for pressure isolation; thus, swellable- packer technology was usedto anchor the casing in place. A special flow-through fracturing plug wasdesigned so that it could be pumped through the 4-in. tieback casing and set inthe 4 1/2-in. lateral, allowing a plug-and-perforate fracture completion to beperformed. The stimulation treatments were pumped to completion anddemonstrated that the pressure isolation integrity of the casing system wassatisfactory and that the flow-through fracturing plugs could maintainisolation between stimulation treatments. This wellbore was in the Eagle Fordshale. True vertical depth was approximately 13,000 ft, bottomhole temperaturewas approximately 325°F with a 0.95-psi/ft fracture gradient, and surfacepressures exceeded 10,000 psi during the stimulation treatments.
Kessler, Calvin (Halliburton Energy Services, Inc.) | Frisch, Gary (Halliburton Energy Services, Inc.) | Hyden, Ron (Halliburton Energy Services, Inc.) | Stegent, Neil (Halliburton Energy Services, Inc.)
Nuclear magnetic resonance (NMR) permeability combined with newly developed petrophysical analysis improves the candidate selection process for production-enhancement treatments such as matrix acidizing, acid fracturing, and traditional hydraulic proppant fracturing. The new petrophysical model allows automatic zoning based on log data such as permeability, stress contrasts, or lithology. The automatic zoning provides information for stimulation design, reservoir simulations, and economic forecasting.
Traditional stress zoning, which has enabled widespread usage of 3D modeling for the design of stimulation treatments, is now enhanced by an accurate permeability profile and automatic zoning. NMR logging provides a continuous, high-quality permeability that falls within the accuracy range required for 3D hydraulic-fracture design programs and reservoir simulators to predict production.
Combining the stimulation design and productivity calculations allows the operator to select the ideal stimulation treatment for the highest return on investment. The automatic zoning enhances both the stimulation design and reservoir simulations with minimal time and effort, allowing the operator to determine the most economical production enhancement scenarios, such as treatment type and job size.
Once the stimulation is performed, operators monitor the production rates and declines to enhance the process. Production data can lead to an improved NMR permeability by optimizing the permeability coefficients for area-specific permeability equations. The process is repeated for additional wells in the reservoir with the ultimate goal of optimizing the reservoir development.
Hydraulic fracture design with 3D models has been available to the industry for more than a decade. The integration of traditional porosity and saturation petrophysical analysis, stress profiling from log-derived elastic moduli, and pay cutoffs are the reservoir parameters needed for 3D modeling. Petrophysical models that perform reservoir zoning based on stress profile and net pay cutoff values have simplified the inputting of reservoir data into the 3D fracture design, increasing the usage of 3D fracture simulation.1-8
The value of production enhancement treatments is established, and stimulation methods have advanced greatly over the years.9-12 The relationship between treatment design/execution and expected production has not been fully developed, however. With the advent of NMR logging, petrophysical analysis can help answer the following questions:
What is the permeability of the zone?
Where are the hydrocarbons located?
Where is the water located?
Will the zone produce water?
Operators can combine this information with reservoir pressure data to determine
the rate at which the well will produce
the net present value (NPV) of the zone
The integration of NMR data with the stimulation processes has led to the development of the StiMRIL process, which is the link between reservoir description and optimized completion design.
Guoynes, John (Halliburton Energy Services Inc.) | Azari, Mehdi (Halliburton Energy Services Inc.) | Squire, Ken (Halliburton Energy Services Inc.) | Blauch, Matt (Halliburton Energy Services Inc.) | Gillstrom, Bob (Halliburton Energy Services Inc.) | Stegent, Neil (Halliburton Energy Services Inc.) | Durey, Daniel (Halliburton Energy Services Inc.) | Jestes, Chad (Halliburton Energy Services Inc.) | Bielecki, Don (Baker Atlas) | Yater, John (Natural Gas Pipeline Company of America) | Clark, Randy (Natural Gas Pipeline Company of America) | Frame, Russ (Natural Gas Pipeline Company of America) | Hopps, Kenneth (Natural Gas Pipeline Company of America)
This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May-1 June.
Studies of the production histories of wells in the Cotton Valley (CV) region of east Texas led companies to recognize the potential value of optimizing fracture design in this area. As a result, chemists developed a dual crosslink fluid (DCF) system that performs best at high temperatures and moderately high pH levels and uses guar as the gelling agent. The new system has enhanced viscosity and an adjustable crosslink rate.
Because the CV sand formation is a "tight gas sand" region, drilling companies have focused on reducing fracturing costs without hindering well production. The use of the DCF system has resulted in fewer screenouts than Zr-guar systems in the CV formation, and it is a more economical alternative to fracturing fluids that use guar derivatives, such as hydroxypropyl guar (HPG) and carboxymethyl hydroxypropyl guar (CMHPG) as the polymer.
By using a moderately high pH and combining the borate crosslinker with a zirconium (Zr) crosslinker, operators have been more successful at placing proppant in a fracture. The performance of previously used Zr-guar-based fluid systems was often unpredictable at the higher temperatures. The DCF crosslinkers have a synergistic relationship; the viscosity of the combined system is higher than the sum of the separate systems' viscosities. The new system improved operational efficiency to greater than 96% in over 85 treatments last year in the CV region. Gas production from wells treated with DCF is similar to that of the higher-priced CMHPG and HPG fluid systems that use zirconium as the crosslinker. Description of the Region
Gas production from the Cotton Valley (CV) formation, which includes 14 fields in east Texas, has grown steadily since 1978. Divided into three major areas - Carthage, Oakhill, and Waskom - the depositional system is a transgressive-regressive marine sequence bounded by the Bossier shale below and the Travis Peak formation above (Fig. 1, Page 6). The formation sediments were deposited in a dominantly progradational sequence of shallow marine and fluvial-deltaic environments. The CV formation is Upper Jurassic and is about 1,200 to 1,500-ft thick at depths ranging from 8,000 to 11,000 ft. The area is divided into two major intervals: the upper Cotton Valley (UCV) and the Taylor Sand. In 1980, the low-permeability CV sandstones were classified as "tight gas sands" by the Federal Energy Regulatory Commission (FERC). Permeability of the productive CV sands is typically between 0.01 and 1.0 md. with porosities up to 15% but generally in the 6 to 8% range. Numerous depositional analogs to the CV system exist worldwide.
History of the Problem
Since the 1970s, operators have used a variety of hydraulic fracturing techniques in the CV formation to stimulate production in the wells that typically produce below the predicted rate.
When a preliminary study in 1990 revealed that two out of three CV wells produced below the expected rate for the field, a team of engineers from several companies drilling in the CV area conducted an extensive study to determine the reasons for the vast production swings. The team developed an analytical technique to assess completion practices and determine key parameters that would help operators predict degrees of economic success for specific wells. Results from the study led engineers to conclude that optimizing fracture designs could improve results from the underproducing wells.
Because the CV sand formation is a "tight gas sand" region, drilling companies have focused on reducing fracturing costs without hindering well production. Improvement in fracturing techniques over the past several years has increased efficiency and reduced fracturing costs by 36% over previous treatments. However, engineers decided to try to reduce cost further by using guar as the base polymer instead of high-cost guar derivatives (CMHPG and HPG).