A steep learning curve has evolved in drilling and completing horizontal wells in the Haynesville shale. The challenge is to understand the production mechanism of the Haynesville and how completion practices in relation to lateral lengths, stages, and stimulation treatments relate with production. This paper gives an overview of the Haynesville horizontal well production, the dominant factors which effect production, and a detailed analysis of the completions. Dominant factors which effect production in the Haynesville shale can be broken into four categories: geology/petrophysics/geomechanics, landing and placement of the lateral, completions, and production control. Integrating all four categories together is critical to characterize well performance and optimize future production; however, this paper focuses primarily on the completions. Self-organizing maps (SOMs) of 49 wells in the Strait area of the Haynesville shale reveal that high producing wells have been treated primarily with slickwater, high fluid and proppant volumes, moderate amounts of 100-mesh sand, and moderate pump rates per perforation. These wells are typically located in cluster spacing of about 75 ft and have stage lengths of about 300 ft. Most show lower post-fracture instantaneous shut-in pressure (ISIP) than lower-producing wells. These observations and characteristics of high producing wells along with best completion practices can help design optimal completions and stimulation treatments in the Haynesville.

Summary A steep learning curve has evolved in drilling and completing horizontal wells in the Haynesville shale. The challenge is to understand the production mechanism of the Haynesville and how completion practices in relation to lateral lengths, stages, and stimulation treatments relate with production. This paper gives an overview of the Haynesville horizontal-well production and the dominant factors that affect production, along with a detailed analysis of the completions. Dominant factors that affect production in the Haynesville shale can be divided into four categories: geology/petrophysics/geomechanics, landing and placement of the lateral, completions, and production control. Integrating all four categories is critical to characterize well performance and optimize future production; however, this paper focusses primarily on the completions. Self-organizing maps (SOMs) of 49 wells in the strait region of the Haynesville shale reveal that high-producing wells have been treated primarily with slickwater, high fluid and proppant volumes, moderate amounts of 100-US-mesh sand, and moderate pump rates per perforation. These wells are typically located in cluster spacing of approximately 75 ft and have stage lengths of approximately 300 ft. Most show lower post-fracture instantaneous shut-in pressure (ISIP) than lower-producing wells. These observations and characteristics of high-producing wells along with best completion practices can help design optimal completions and stimulation treatments in the Haynesville.

No abstract

Completion design for unconventional shale plays in North America is a topic of high current interest. Although the practice of stimulating shale horizontal wells with large slickwater treatments is slowly changing to the use of Hybrid/Crosslink treatments in certain plays, little has changed with the method of completion design itself. Most laterals are completed using a ‘cookie cutter’ approach in which the number of stages and clusters, cluster spacing and other design parameters are based on statistics, past experience, rules of thumb or client shared knowledge, and are not tuned to the specific conditions in a particular well. This paper presents a case study from the Eagle Ford Shale and describes a step-by-step workflow to simulate hydraulic fractures using a state of the art, reservoir-centric stimulation design tool (RCSD). The presented approach incorporated petrophysical data acquired in a vertical pilot hole with horizon interpretation, a discrete fracture network (DFN) model conditioned by seismic interpretation, image log data from a horizontal well, and completion data into a hydraulic fracture simulator. Simulation of fracture geometry was performed stage-by-stage in the RCSD tool using the recently developed unconventional fracture model (UFM), which is optimized specifically for complex fracture networks. The modeled fracture network was calibrated to microseismic events via fluid rheology and fluid loss variables while also accounting for a stress shadowing effect. The output of the simulator includes a list of parameters such as fracture surface area, fracture propped surface area, and hydraulic fracture network geometry that can be used for the determination of estimated stimulated volume (ESV) as well as inputs into reservoir simulation for production history matching and forecasting. Also, this application of the RCSD tool in the Eagle Ford Shale provides an ability to test most aspects of the completion design by modeling stimulated volume change with respect to pumping schedule and completion parameters.

The deep high pressure/high temperature (HPHT) dolomite formation in Northern Kuwait has been a challenge with varied production, attributable to reservoir heterogeneity. Due to the tight nature of these rocks, matrix acidizing may not produce desired effects, thus requiring hydraulic fracturing to produce at economic rates. However, the tectonic setting in high stress environment has resulted in subpar success and inconsistent results from stimulation treatments in matrix and hydraulic fracturing applications. This paper presents a multidisciplinary approach to address the limited success in the Northern Kuwait Dolomites. An integrated petrophysical evaluation of the current wells will be followed with multi-well Heterogeneous Rock Analysis (HRA), to evaluate the reservoir heterogeneity across the field and identify the ‘sweet spots’ for future drilling locations. Evaluation and lessons learnt from the past stimulation treatments, will be used to understand geo-mechanical challenges and to help calibrate the Mechanical Earth Model (MEM) for implementation in the future wells. Finally, using a reservoir-centric stimulation design tool, stimulation type (acid fracturing vs proppant fracturing) and stimulation design optimization for future wells will be developed. A reservoir-level petrophysical evaluation of the existing wells was performed and compared to understand the reservoir heterogeneity vis. a vis. production potential. Multiple rock classes were identified within the tight dolomite interval, with a gross thickness of ~250 ft. Starting with log based MEM, results from the image log interpretation and the field observations/measurements from fracture diagnostic tests (Decline analysis, Calibration injection) were used in calibrating the MEM and mapping the Completion Quality (CQ) heterogeneity across the field. This has led to a reservoir-level understanding, which can enable planning optimal well locations, target interval and subsequent well placement/completions methodology. Finally, using the reservoir-centric design tool, an optimum design to effectively stimulate the ultralow-permeability dolomites was determined. The optimization workflow did not only include a single-faceted approach of fracture modeling, but also encompassed a production forecast using the integrated numerical reservoir simulator. Lessons learnt from the optimization workflow were further extended to designing horizontal wells (landing point, trajectory for optimal stimulation geometry), and hence to aid in field development strategy. Using the multidisciplinary unconventional workflow, the heterogeneity in reservoir quality and completion quality was evaluated, both along the wellbore and spatially. In essence, we found that natural fractures along with high Critical Net Pay (CNP) allows you to vertically connect with good RQ and thus, is required for success in these tight reservoirs. Following which, reservoir-centric stimulation design tool enabled optimization of completion and stimulation design in a holistic approach, to maximize appraisal and production opportunities.