Many tight gas reservoirs require fracture stimulation to achieve commercial outcomes. These reservoirs can often be characterised geologically and geomechanically by high deviatoric stresses and hard, naturally fractured rock. Stimulation treatments in such reservoirs may create complex fracture networks from a combination of shear and tensile failures. Water fracs can be used where shear failure is anticipated to dominate; however, in these environments few practical modelling tools exist to determine: the level of permeability enhancement; the degree of permeability retainment during draw-down; and, the stimulated rock volume (SRV). This paper seeks to provide the engineer with a suite of tools capable of achieving these goals.This paper presents a dual porosity, pressure-dependent permeability reservoir simulation model that was devised to honour shear failure mechanisms (also called shear dilation) using basic geological characterisation. The assumptions of this model and the pragmatic selection of first-order effects are discussed. Using the results of this simulation model, three families of diagnostic tools are presented. The first category is that of treatment diagnostics, which includes bottom hole pressure evaluation, injectivity and fall-off analysis. The second approach is called seismic-based reservoir characterisation (SBRC), which uses the microseismic to determine the SRV as well as provide estimates of the initial and stimulated fracture network properties. The third category is post-treatment diagnostics, which incorporates the evaluation of pressure draw-down characteristics.Finally, this paper compares these individual approaches and provides a workflow to evaluate data on future wells.
Various analytical and numerical models have been proposed to predict production performance of hydraulic fractured wells and to investigate the effect of fracture geometry and fracture conductivity on well performance. These completion design parameters greatly impact E&P operators' return on investment (ROI). In this study, we conducted numerous field case studies in the Bakken formation to compare production performance of hydraulic fractured wells with different completion designs. Since all wells are located in the same field, the geological difference was considerably minimized. The wells were grouped and analyzed by different completion and stimulation design parameters. Specific grouped categories included percentage of upgraded proppant in the total proppant amount, lateral length, number of stages, etc.We then simulated post-fracturing production performance of these fractured wells. An advanced meshing technique was developed to honor complex fracture networks with unstructured Voronoi grids. We applied this technique to investigate the characteristics of hydraulic fractures such as fracture conductivity, aperture and permeability distribution on the long-term production of the wells. Core data and well logs were analyzed for reservoir characterization. Several assumptions were made to estimate pumped fracture width, stress-dependent fracture permeability and stimulated reservoir volume. Finally, sensitivity studies were performed to investigate the effect of fracture conductivity on production performance due to superior vs. low-quality proppants.The objective of this study was to determine if upgrading completion designs to high quality proppant materials would achieve better fracture conductivities and long-term production performance. After all well data was analyzed and the production related parameters were summarized, it was determined that upgrading the completion designs with higher quality proppants provided dramatically improved production rates.The following unstructured mesh generation algorithms successfully implemented the local grid refinement feature around fractures, which can handle non-orthogonal fractures and more complex fracture geometries. The final simulation runs and sensitivity studies further demonstrated the importance of both stimulated reservoir volume and fracture conductivities. The same long-term production performance was also predicted by using reduced amounts of upgraded proppant with improved fracture conductivities.
A brief overview of different proppant types and amounts used in stimulation designs in the Bakken shale play since 2011 is presented in this paper. The primary goal of the paper is to determine the long-term production and economical effectiveness on hydraulically fractured wells using different proppant types, percentages of proppant types and overall amount of proppant in the well completions. The results are based on four case studies that focus on 72 wells in four different fields in the Bakken formation of the Williston Basin.In these four case studies, the primary variable that affects the difference in long-term production of the different well groups is the percentage and amount of each proppant type used in the completion design. Completion and stimulation data was collected from public resources such as the North Dakota Industrial Commission (NDIC) database. In each case study, wells in the same field were grouped. For each group of wells, the average long-term production and economical effectiveness was analyzed.The case studies in the Capa Field in Williams County North Dakota and the Chimney Butte Field in Dunn County North Dakota shows that over a 270 day period, in each group of wells completed with about 30 percent ceramic proppant mixed with silica sand, the wells produced an average of over 100 percent more than the comparable group of wells completed using only silica sand. The case study in the East Fork Field in Williams County North Dakota shows that after 270 days of production, the group of wells using 100 percent ceramic proppant attained an average of 27 percent production increase over the group of wells using an average of 62 percent ceramic proppant. These wells also attained a 67 percent production increase over the group of wells using an average of 35 percent ceramic proppant.In comparing completion procedures in these high-producing fields, using a combination of high percentages and large amounts of ceramic proppant has yield higher production and EUR. The use of ceramic proppant not only covers the additional proppant cost in a short period of time, but also generates higher revenue in the long term. The findings from these case studies should apply to all fields that have similar reservoir characteristics.
Proppants and their effect on the production of wells are not thoroughly understood. When selecting a proppant, operators deliberate: “Do I purchase a low-cost proppant to reduce completion costs or do I spend more for higher conductivity to increase long-term production and greater return on my investment?” Good well data can be difficult to obtain and completion designs can vary. Hence, only a few existing case histories provide apples-to-apples comparisons of long-term production performance based on the use of different proppant types. Continuing our prior research (SPE Paper 169544), we present data that will help operators make informed decisions when selecting proppants for optimizing Bakken wells. To investigate effectiveness of different proppants, researchers tracked long-term production rates of several comparable well sets. For example, in the first study, three wells on the same pad in the Haystack Butte Field in McKenzie County, North Dakota were completed by one operator. A second study included 11 Bakken wells fractured by another operator in the Grail Field in McKenzie County. All three wells in Haystack Butte Field were hydraulically fractured with similar completion methods. The only significant difference was the proppant type. One well used 100% uncoated sand, another well combined 45% uncoated sand with 55% resin-coated sand, and the third well used 45% uncoated sand and 55% ceramic proppant. The well completed with sand and ceramic proppant did not have the highest initial production rate (IPR), but had, on average, 20% higher production over a 365 day period. The well where sand was combined with resin-coated sand produced a higher IPR. However, over 365 days, that well's production was outpaced by the other two wells with the sand/ceramic well delivering the best long-term production of all three. Similar findings were confirmed among the wells in the Grail Field. This study focused on 11 Bakken wells that used sand with a tail in of 30% to 40% ceramic proppant, sand with a tail in of 30% resin-coated sand, and sand with 50% higher volume. It also indicated that using a high percentage and high volume of ceramic proppant delivers superior long-term economic benefits in Bakken wells. These findings, in addition to others outlined in the paper, challenge the preconception that wells completed using ceramic proppant should deliver higher initial production rates. Time and again, the findings demonstrated that the long-term production of Bakken wells completed with ceramic proppant significantly outperforms wells completed exclusively with other proppant types. Moreover, data demonstrates that compared to sand-only completions, resin-coated sand helped improve initial production but did nothing to improve long-term production, especially in deeper wells.
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