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Collaborating Authors
SPE Hydraulic Fracturing Technology Conference
Abstract With the large number of fracture stages, and size of jobs being pumped in horizontal wells, many companies have elected to use non-standard, or non-commercial natural sands as propping agents. The Stim-Lab Proppant Conductivity Consortium, supported by approximately 50 proppant suppliers, pumping service companies and operators, has developed consistent laboratory conductivity test procedures over the past 30 years that have become de-facto industry standards. One outcome of this long history of proppant testing is a set of correlations that can predict the baseline conductivity, as a function of closure stress and rock (substrate) properties, within the range of uncertainty of laboratory tests. Inputs to the correlations are basic material property measurements such as specific gravity and median particle size of the sieve distribution. The correlations can be used to compare materials of unknown properties to standardized data sets, or to develop useful predictions of how a non-standard material is likely to perform. The correlations are general enough for application to brown sand, white sand, resin-coated materials, and ceramic proppants of various sizes and densities. These correlations have been found to be sufficient for comparing proppants and for estimating their performance in production computations, when adjustments for appropriate damage and cleanup are made to the calculated baseline conductivity values.
Abstract A "semi-empirical" acoustics-based flow model is presented based on large scale flow loop testing using water, water thickened with a linear gel, and linear gel slurries containing various amounts of proppant. The flow model predicts volumetric flow rate through individual perforation clusters from calibrated high fidelity accelerometer measurements and knowledge of the fluid type and perforation cluster geometry. This model is applicable to the plug-and-perf completion often used in hydraulic fracturing of unconventional resources. The accelerometer data provides a benchmark for downhole fiber-optic distributed acoustic sensing (DAS). Custom flow loops were constructed and tested to measure acoustic signals generated by fluid turbulently flowing through simulated downhole perforations using water, water with a linear gel, and slurries containing ceramic proppant. Flow rates, perforation-hole sizes, number of clusters, number of perforations per cluster, fluid viscosity, and proppant slurry density were varied in a controlled way. These parameters were adjusted to represent a downhole stimulation treatment. The data was evaluated using symbolic regression with a 1,000-core compute cluster. Approximately three trillion analytic models were evaluated and scored for prediction accuracy and model simplicity. The data indicated that all of the fluids became significantly louder above a critical threshold. This threshold was observed to strongly depend on fluid viscosity, while no dependence was observed on the amount of proppant in the slurry. The discharge coefficient showed significant variability, even among repeated experiments when no erosion was present. Very different behaviors for the coefficient of discharge were observed between water and gelled water. The measurements and model provide a benchmark for wellbore monitoring with fiber-optic distributed acoustic measurements during stimulation. Accurate real-time flow allocation estimation allows for an immediate adjustment of treatment strategy using, for example, diverter spheres. Accurate flow allocation could possibly allow changes in stage designs to tune individual flow rates. Analytic expressions were derived relating the root-mean-square of the acoustic signal to both the perforation pressure loss and the flow speed per perforation as a function of cluster injection rate, viscosity, perforation diameter, and number of perforations. The relative importance of each of these variables was investigated and is quantitatively described. Several models for flow and accuracy were investigated and are discussed.
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...)
Abstract Hydraulic fracturing has become an important component of well completion in unconventional reservoir development and contributes to over 37% of the overall well construction spend. It has also, been seen as the most significant contributor to return on investment in unconventional reservoir exploitation. Until recently, field operation has been based on "trial and error" approach while modeling has been based hitherto on software used basically for the conventional reservoir fracture simulation. Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be clearly understood to optimize stimulation design and field development planning; completion strategy and operations planning. Unfortunately, the existing planar fracture models used in the industry today are not able to simulate complex fracture networks. A recently developed unconventional complex fracture propagation model (UFM) is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate simultaneously and intersect, dilate or cross each other. This paper presents an integrated approach to optimize hydraulic fracture design by fully integrating all the data captured in the Canadian Horn River Shale. Based upon insight from the study, which was initiated by the operator and supported by the service provider, the operator could now make more informed design decisions and understand the interaction between the shale, the hydraulic and pre-existing natural fracture network, and reduce costs. The data incorporated into the study from both vertical and horizontal wells included geophysical, geological, petrophysical and geomechanical data integrated into a 3D earth model. Engineering data such as DFIT (measurement made from small volume of water pumped into target formation) derived fracture closure pressure, production and pressure data from the horizontal well in the pad were used for calibration and constraining of the model. A generation of 2D natural fracture network is also included in the paper by defining natural fracture parameters such as length, orientation, spacing, friction coefficient, cohesion, and toughness which are almost entirely validated using lab data and geomechanical interpretation. The complex hydraulic fracture simulation results calibrated with microseismic and fracturing treatment data were incorporated into numerical simulator and further calibrated with current production history of the candidate wells. The results of the hydraulic fracture, natural fracture and reservoir models were utilized to understand the fracture propagation mechanism in the Canadian Horn River shale gas formation. The prediction of the model (rates, cumulative and pressure) matched very rapidly and more closely with the observed production from the candidate well, improving confidence on the methodology utilized and results obtained. As a result of the project, the team is now able to run different hydraulic fracture design scenarios including stress shadow between stages validated using microseismic, stress shadow between offset wells, tuning factors not only on the geomechanics side but also in the treatment schedule and assess the impact that each key design parameter has over the candidate well's long term production using a numerical simulator with a unique gridding process. The result of the study also opened up new way of estimating the drainage area over a period of time and could be used when considering well spacing, placement and density during the field development planning. Based on these findings, the operator now have an insightful tool that could be used as the building block for future optimization of the fracture design.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.92)
- 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)
- (13 more...)
Interwell Hydraulic Fracture Interaction Between Multistage Stimulated Wells and a Multi Zone Slant Open Hole Observation Well Placed in the Canadian Horn River Basin
Pyecroft, James (Nexen Energy ULC) | Lehmann, Jurgen (Nexen Energy ULC) | Petr, Christopher (Nexen Energy ULC) | Lypkie, Kevin (Nexen Energy ULC) | Purdy, Ivan (Nexen Energy ULC) | Zafar, Hammad (Nexen Energy ULC) | Hiller, Chelsey (Nexen Energy ULC) | Meeks, David (Nexen Energy ULC)
Abstract This paper presents well construction details and pressure responses for a slant well in a dry gas shale resource in northern British Columbia, Canada. We will present the drilling and completions plan for a Multi-Stage Hydraulic Fracturing (MSHF) campaign on a ten well half pad including consequences of an aggressive fluid environment. Horn River shale gas development involves Multi-well MSHF horizontal wells from a single surface pad location. The wells are treated sequentially from toe to heel of the horizontal section, alternating between wells. Strategic placement of an Open Hole (OH) slant well equipped with slotted liner, tubing, and pressure data recorders will be presented. Pressure responses during the MSHF campaign will be presented and reviewed against calibrated closure pressure data from Diagnostic Fracture Injection Test (DFIT) data and end of job instantaneous shut-in pressures (ISIP). The initial concept of drilling an OH well placed between MSHF wells was to evaluate the fracture system between stimulated wells and to test whether an unstimulated open hole well placed between stimulated wells can economically produce gas. Other objectives were to provide an Oil Based drilling Mud (OBM) free wellbore that would enable water-based imaging logs. Water-based logs have enhanced ability to identify and map natural fractures. Initial logs would evaluate the natural fractures and subsequent post-completion logs would evaluate the hydraulic fracture transiting the shale resource rock to the OH well. Knowledge of how pre-existing natural fracture networks react to the hydraulic fracture process along with pressure response data recorded from all wells on the pad would be used to provide geoscientists and engineers the means to optimize stimulation programs for horizontal wells and wellbore placement within the various resource reservoirs in the Horn River Basin. This paper will discuss the compromises that were made to the initial conceptual model that maximized learnings from the slant OH wellbore, and how the well was unexpectedly lost. Pressure interference data for future hydraulic fracturing models will be provided along with methods to describe how hydraulic fractures from nearby wells transect a well and interact with various reservoirs exposed within the OH segment of a slant wellbore.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.94)
- Geophysics > Borehole Geophysics (0.69)
- North America > United States > Kansas > Thomas Lease > Simpson Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Horn River Shale Formation (0.99)
- North America > Canada > Alberta > Muskwa Field > Arl 5A Muskwa 5-9-88-24 Well (0.94)
- (2 more...)
High Concentration Polyacrylamide-Based Friction Reducer Used as a Direct Substitute for Guar-Based Borate Crosslinked Fluid in Fracturing Operations
Motiee, Monet (Hess Corporation) | Johnson, Maxwell (Hess Corporation) | Ward, Brian (Hess Corporation) | Gradl, Christian (Hess Corporation) | McKimmy, Michael (Hess Corporation) | Meeheib, Jeremy (Calfrac Well Services)
Abstract Traditionally, friction reducer systems have been used to promote laminar flow in pipe to reduce friction pressure in pumping of low viscosity, slickwater-type fracture treatments. In these types of treatments, velocity is the key factor in proppant transport into the reservoir. Typical testing of these conventional friction reducer fluid systems focuses primarily on the chemical's ability to reduce treatment pressures and permit higher fluid velocities. In an effort to reduce completions costs and improve operational efficiency while maintaining baseline well productivity, our Completions Team applied these conventional friction reducers in an unconventional way. The project used high concentrations of friction reducer (HCFR) as a direct replacement for a guar-based borate crosslinked system without modification to the standard treatment and proppant schedule. The team took steps to qualify the fluid for field implementation, including low shear rate viscosity testing, proppant settling testing, and regained conductivity testing. Following qualification and operational planning, the team performed field trials. The data showed a reduction in footprint and overall horsepower requirements. The reduced volume and number of chemicals on location led to decreased exposure to hazardous chemicals and also simplified logistics, resulting in fewer truck movements on location. The reduction in chemicals impacted the economics of the well completion positively. The stimulation costs of the wells treated with HCFR when compared to the wells treated with the baseline fluid design showed a chemical cost reduction of approximately 22% per well. In addition to the cost and operational efficiency benefits observed in the project, initial production data indicates that the wells are meeting or exceeding baseline productivity curves.
- North America > United States > North Dakota (1.00)
- North America > Canada > Saskatchewan (0.70)
- North America > United States > Montana (0.69)
- North America > United States > South Dakota (0.69)
- North America > Canada > Alberta > Williston Basin (0.99)
- North America > United States > West Virginia > Utica Field (0.98)
- North America > United States > North Dakota > Williston Basin > Three Forks Group Formation (0.94)
- (5 more...)
Abstract The objective of achieving uniform stimulation of a reservoir through hydraulic fracturing from a horizontal well typically depends upon the ability to generate a uniform array of hydraulic fractures from multiple entry points. However getting all the hydraulic fractures in an array to grow simultaneously is a challenge. The challenge apparently arises not only due to reservoir variability, but also in a substantial part due to the stress interaction among growing hydraulic fractures. This phenomenon, referred to as a stress shadowing, inhibits the growth of inner fractures and favors the growth of outer fractures in the array. Recently, we created a new hydraulic fracture simulator which simulates the growth of an array of hydraulic fractures in 10–10 of the computation time required for fully coupled 3D simulations of multiple parallel planar hydraulic fracture growth. Using a novel energetic approach to account for the coupling among the hydraulic fractures and through judicious use of asymptotic approximate solutions, the simulation enables designs reducing the negative effects of stress shadow by balancing the interaction stresses through non-uniform perforation cluster spacings. Furthermore, so-called limited entry approaches are thought to be capable of promoting greater uniformity among simultaneously growing hydraulic fractures as long as the number and diameters of the perforations in each cluster are appropriately designed. In order to enable such optimizations and designs, we add perforation loss into to the approximate, energy-based simulator. Our results show the potential of choosing the proper perforation diameter and number to double the fracture surface area generated by a given injected fluid volume though minimizing the negative effect of interaction. The usefulness of the new simulator is demonstrated by development of example limited entry designs and optimal spacings for different numbers of entry points.
Abstract Efficient hydraulic fracturing is one of the most important aspects for wells in tight-gas reservoirs, in order to achieve and sustain economic production. Unlike North America, where thousands of wells are drilled and completed each year and with infrastructure in place, delivering a tight gas field development (Khazzan) in the Sultanate of Oman has very specific challenges related to the limited number of wells and poor existing logistical infrastructure. In order to address these challenges, improve the frac process and overall development efficiency, a suite of high-level goals were set for the initial development, including zero accident(s), 1 Bcf/day production, 300 wells and 40 mm.scf/day IP per well. Within Block 61, in the Sultanate of Oman, the initial formation that was targeted for development was the Barik; a highly laminated gas bearing reservoir with measurable but tight permeability. The formation exhibits widespread heterogeneity in reservoir quality and rock properties in both the vertical and horizontal directions. Following an extensive exploration and appraisal programme, it was determined that vertical wells with massive hydraulic fracturing would be the most likely strategy for the higher permeability areas; with fractured horizontal wells being proposed within the lower permeability areas. This dual approach would provide the most efficient and effective development mechanism for the field and provide the greatest opportunity to deliver the simplistic development goals, as outlined above. During the exploration, appraisal and development phases of Khazzan, incremental learning and step by step improvement was required as the phases changed both the emphasis and requirements. This began with measuring resources, ensuring adequate service provision and logistics, completion set-up and subsequent transition from appraisal to development mode. The identification of key fracturing aspects, such as in-situ stress-state and geo-mechanical understanding, as well as frac geometry determination (both placed and effective) were crucial to achieving development progress. Post frac flow-back, initial production behaviour and reconciliation with petro-physics all played their part in the delivery of a rapid transition to efficiency along with proof of resource. This paper fully describes the technical and operational journey that was taken through the appraisal and early development phases, in order to fundamentally understand and deliver the most effective and efficient methods of hydraulic fracturing vertical wells in this tight-gas field. This case study includes the sequence of the first twelve vertical wells in the Barik reservoir; and the incremental improvements that were achieved in approaches over time. Fit for purpose technologies, equipment, procedures and surveillance have demonstrably led to a suite of very healthy and highly efficient completion approaches being adopted, which have ensured that the field development economics are being maximized.
- North America > United States (1.00)
- Asia > Middle East > Oman (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Oman Government (0.46)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 43/26 > Ravenspurn South Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 42/30 > Ravenspurn South Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 42/29 > Ravenspurn South Field > Rotliegend Formation (0.99)
- (13 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Expanding Interpretation of Interwell Connectivity and Reservoir Complexity through Pressure Hit Analysis and Microseismic Integration
Lehmann, Jurgen (Nexen Energy ULC) | Budge, Jessica (Nexen Energy ULC) | Palghat, Abhinav (Nexen Energy ULC) | Petr, Christopher (Nexen Energy ULC) | Pyecroft, James (Nexen Energy ULC)
Abstract This paper presents a multi-disciplinary workflow for analyzing interwell hydraulic fracturing pressure interactions on multi-well horizontal pads in unconventional reservoirs. Over twenty wells in multiple fields with varied spacing across multiple landed zones are evaluated. The workflow provides a method for determining the degree of connectivity between the wells to assess the extent and complexity of the stimulated network. The analysis method provides a cost efficient, timely means of understanding the stimulated network in order to impact decisions regarding well spacing, injection rate, perforation design and frac order. Prescriptive completions programs enable observation of pressure interactions between wells during multi-stage hydraulic fracturing. Wellhead pressures are continuously recorded during all completion and flowback operations. In the observation pads studied, wells experience varying degrees of pressure communication across the fracture network. Pressure hits are grouped by according to identifying characteristics and correlated to microseismic data where available. Characterization of the stimulation network gained from analysis of pressure interactions closely aligns with available high resolution microseismic data. Networks are shown to have significant vertical and lateral growth establishing a highly complex network. Additional insights on the degree of connectivity and the definition of effective fracture network are gained. Results are fundamental to understanding well spacing and zonal placement.
- North America > Canada > British Columbia (0.29)
- North America > United States (0.28)
Abstract A conventional proppant pack may lose up to 99% of its conductivity due to gel damage, fines migration, multiphase flow, and non-Darcy flow. Therefore, pillar fracturing was developed to generate highly conductive paths for hydrocarbon to flow. This paper describes experimental results and numerical models of a new method of generating stable proppant pillars The proposed treatment method depends on fingering phenomena observed when a less viscous fluid, that does not carry proppant, is injected to displace a more viscous one that carries proppant. The low-viscosity fluid will channel through the high-viscosity fluid and create isolated proppant pillars. This method promises to reduce proppant costs, pumping horsepower, and gel damage compared to conventional treatments. Large-scale experiments (Slot tests: 2-ft height and 16-ft length) were performed to evaluate the development and stability of the created channels. In additional, a computational fluid dynamics (CFD) model was constructed using commercial CFD software, to simulate the experiment and to scale it up into full fracture dimensions. The study focused on effects of surface injection rate (1 to 120 bpm) and viscosity ratio (from 2 to 200) between the two injected fluids. Experimental results and numerical modeling confirmed that viscous fingering phenomena can be used to create a pillar fracture with conductive and stable channels. The numerical CFD model was able to accurately predict the experimental results. Increasing the injection rate reduces the main channel width while increasing the channel branching. Full piston displacement behavior was achieved after 60% of the fracture height, when a high-viscosity fluid displaced a low-viscosity fluid and their viscosity ratio was greater than 5. By reducing the viscosity ratio between the two fluids, the created channel shape converts from cylindrical (where the beginning and end of the channel have the same width) into conical behavior (where the beginning of the channel is wider than the end). This explains why the length of the channel decreases with the viscosity ratio between the two fluids. The distance between proppant pillars tends to be reduced with increasing distance from the wellbore, or with reduced pulse stage volume, time, or rate. A full description of the created channel (distance between proppant pillars) characteristics (size, width and length) will be presented in this paper.
- Europe (1.00)
- North America > United States > Texas (0.95)
- Research Report > New Finding (0.47)
- Overview > Innovation (0.34)
- 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)
- (2 more...)