Abstract Hydrocarbon production has been long existent in the Denver Julesburg basin and with the development of horizontal drilling technology the Niobrara has become one of the most economical plays even with lower oil prices. The multi-bench Niobrara formation is the primary target in the basin followed by the Codell. Even with the better economics, the Niobrara and the Codell completions are not optimized yet. The operators are still aiming for more and more stages with lesser spacing thus increasing the costs. The objective of this study is to show that stage spacing can be optimized with low cost diversion technology yielding equal or better production with fewer stages thus lowering costs. In this optimization study, two Niobrara "C" bench lateral wells from the same pad that are next to each other were selected as candidates. The first well, Well-K was completed with 28 stages geometrically spaced at 153 feet utilizing the perf-n-plug methodology. The second well, Well-L was completed with 20 stages, geometrically spaced at 215 feet, also utilizing the perf-n-plug methodology. Well-L was stimulated utilizing the intra-stage diversion process and had approximately 404,000 lbm less proppant than Well-K. Well-K was completed without the diversion technology. Following stimulation and flowback, Fibercoil with Distributed Temperature Survey (DTS) and Distributed Acoustic Survey (DAS) capabilities were run in both the wells to diagnose the contribution from each perforation cluster. The Fibercoil results clearly showed that Well-L with larger stage spacing and intra-stage diversion had 80% fracture initiation as opposed to 60% with the limited-entry Well-K that had shorter stage spacing. The production results so far are very encouraging for the L-well. The 180-day cumulative oil production for Well-L is almost similar to Well-K with the normalized barrels of equivalent oil (BOE) per foot, BOE/ft. difference being lower by 3%. This study has clearly shown us that with some additional enhancement intra-stage diversion can be used to optimize stage spacing without compromising production. The post-frac fracture modeling analysis along with the Fibercoil results including warm-back analysis and production for the two wells is presented.

Abstract Since the discovery of the Jonah field in 1977, many styles of hydraulic fracturing treatments have been employed to stimulate the Lance formation. Commercial production was not established in the field until the early 1990s, and technological improvements have permitted increased production since that time. Further trials of fracturing techniques, including slickwater fracs, induced stress diversion, and flow-through composite fracture plugs, continued over time. Since March 2010, channel fracturing treatments have been employed in the Lance formation in conjunction with more traditional, conventional fracturing treatments. For the purpose of this paper, conventional fracturing treatments consist of either crosslinked gel or slickwater fracturing treatments. The proppant is added in a continuous manner with an increasing proppant concentration. For crosslinked gel treatments, the typical proppant is 20/40 -mesh white sand added up to a maximum of 6 lbm/gal. For the slickwater treatments, the typical proppant is 40/70- or 30/50- mesh white sand added up to a maximum of 3 lbm/gal. The channel fracturing treatments use a pulsed method of adding the proppant to the fluid. Instead of adding the proppant continuously, the proppant is turned on and off in approximately 15-second time intervals. This concept is intended to provide high-conductivity, unpropped open flow paths through hydraulic fractures held open by the proppant pillars. To assess the effectiveness of the channel fracturing method in the Jonah field compared to conventional fracturing treatments, a spatial sampling technique was used. Spatial sampling is a documented method for comparing large groups of wells with their direct offsets. The original intent of the spatial sampling method was to identify underperforming wells; however, the method has also been employed as a way to compare various completion or stimulation techniques. In this case, spatial sampling was applied in an attempt to evaluate the effectiveness of the channel fracturing technique compared to conventional fracturing techniques using continuous proppant addition during the treatment. Five discrete areas of the Jonah field were included in the study. Only wells completed in the same time frame as the channel fractured wells were included. The treatment and production data for all wells were obtained from public sources. There might also be differences in production among the conventionally fractured wells, depending on whether a crosslinked or slickwater treatment was used; however, the effect of slickwater treatments, as opposed to crosslinked treatments, was not considered in this study.

Abstract Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of unconventional reservoirs like tight gas sands, tight coals and shale reservoirs. Over the last few decades it has been studied extensively. However, all the issues that arise during a stimulation treatment have not been understood correctly, yet, leading to costly trial and error approaches to fix them. Assuming that a majority of the perforations (or sleeves) are open and there are no issues with the stimulation fluids, screen-outs and/or pressure-outs during stimulation treatments in any type of reservoir can be attributed to either high pressure-dependent leakoff (PDL) or high process-zone stress (PZS). With high PDL the end result will be a screen-out if it is not addressed properly. However, with high PZS, it is the first indicator and in conjunction with fracture gradient and local stress environment one can understand the reasons for pressure-outs or screen-outs. With high PZS pressure-outs are more common than screen-outs. The objective of this work is to clearly explain and quantify these reservoir-related issues and once identified present solutions such that screen-outs and pressure-outs can be avoided in re–fracture and new well treatments. The effect of damage zone and the fluid lag or negative net stress zones and their contribution to the fracture tip effects will be presented. This work will also clearly show that zones that exhibit high PZS (greater than 0.20 psi/ft), irrespective of the formation type, are economically poor producers. The tools for identifying these reservoir-related parameters include a diagnostic fracture-injection test (DFIT) and a grid-oriented fully functional 3D fracture simulator with shear decoupling. The relationship between high PZS and the local stress environments and their contribution to issues during a stimulation treatment are presented based on the analysis of 3000 plus DFIT's from the Rockies. Coal, tight gas sand and shale formations are part of the 3000 plus DFIT dataset presented in this work. Examples from coal and shale formations presented earlier by the author are referred in this work. Finally, guidelines (Ramurthy 2012) are presented such that stimulation treatments in high PZS zones that contribute to poor production can be avoided and high PDL zones that lead to good production can be optimized, thereby saving completion costs.

Abstract The Pictured Cliffs formation in the San Juan basin has been a target interval for operators for many years. This tight gas reservoir lies just below the prolific Fruitland coals and has been completed either separately or as additional pay in vertical wells. With the advent of horizontal well technology, operators have begun drilling laterals in the Pictured Cliffs and completing them with multistage stimulation treatments. Because of the relatively shallow depths and the low closure pressure associated with it, 20/40-mesh proppant has been the main proppant used when completing the Pictured Cliffs formation. In this project, a different approach was necessary to complete the laterals because of limited accessibility to the well locations and the small size of the locations where storage of large mass of proppants is not viable. After analyzing the reservoir properties, the first lateral in this project was completed with a new type of thermoplastic alloy lightweight partial monolayer proppant (TPA-LWP). Following its success, three more horizontal Pictured Cliffs formation wells were completed with the partial monolayer proppant. Production results from all four wells are presented in this work, along with the selection criteria and the operational aspects associated with pumping these proppants. This paper also discusses the production analysis performed on these four wells and compares them with five other Pictured Cliffs laterals in the basin that were stimulated with 20/40-mesh proppant.

Summary Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of tight shale reservoirs. Ever since the success of the Barnett shale program, operators are inclined to pump similar large-volume water-fracture (waterfrac) treatments with little or no proppant in their respective shale plays. This assumes that all shale plays are the same and react accordingly to large-volume treatments. The basic objective behind such treatments is to contact large surface area, which has been very successful in the Barnett shale play. Such large-volume treatments in other shale plays may not be an optimized solution for the specific shale attributes, and the response may lead to uneconomical production results. Some shales might require a conductivity fracture treatment on the basis of their reservoir characteristics. So, it is important to understand the characteristics of these shales before deciding on the stimulation treatments. In addition to core and log analysis of these shales, fluid-sensitivity tests, Brinell hardness (BHN) tests, unpropped-fracture-conductivity tests, and, more importantly, a diagnostic fracture injection test (DFIT) can help define the guidelines for choosing between a surface-area and a conductivity-type fracture treatment. Integrating the various data sources is important in arriving at these guidelines. The main objective of this paper is to provide these guidelines along with examples so that a costly trial-and-error approach for stimulating shales can be avoided. Examples from both oil and gas shales (i.e., the Gothic, Haynesville, Eagle Ford, and Barnett shale plays in the USA) are included in this work.

Abstract In the San Juan basin Fairway, cavitated Fruitland coalbed-methane (CBM) wells have been successfully producing for the past 30 years. However, over the years, coal-fines migration into these cavitated wellbores has resulted in pump issues and coal-fines production, leading to a significant decline in production. To clean out the coal fines and replace the pumps on a continuous basis is a costly workover issue. Hence, a foamed remedial treatment was designed to displace the conductivity-plugging coal fines away from the wellbore and immobilize them with the foam also serving as a diverting agent. This has allowed the production and dewatering process to continue without any interruption. The remedial treatment was chosen because the aqueous tackifier in it can control the fines and help prevent them from plugging the flow path. Also, it dissolves any calcium-carbonate scale in the wellbore and near-wellbore region. In this study, 15 cavitated wells with coal-fine issues were selected for the foamed remedial treatment. In all of these 15 wells, the coal-fines issues were resolved. This allowed production to be uninterrupted and reduced the cost of workover rigs and pumps. As a secondary benefit, production stabilized in 10 wells and increased in 5 of these wells. This study shows the production results from these two groups of wells that were treated. It also discusses the design options for the treatments and lessons learned from the process. This technology can be applied to openhole as well as cased multilayered CBM wells.

Summary Hydraulic fracturing in coals has been studied extensively over the last two decades; however, there are factors that were often ignored or incorrectly diagnosed, resulting in screenouts. Assuming that a majority of the perforations are open and there are no problems with the stimulation fluids, screenouts during coal hydraulic-fracture treatments can be attributed to either high pressure-dependent leakoff (PDL), high process-zone stress (PZS) or in some cases both. The objective of this work is to discuss, help identify, and present solutions to address these reservoir-related issues such that screenouts can be avoided in optimized refracture treatments and new well stimulations. The tools for identifying these reservoir-related parameters include a diagnostic fracture-injection test (DFIT) and a grid-oriented fully functional 3D fracture simulator with shear decoupling. An example for each respective case is presented in this paper. In the first example, in which high PZS was considered to be the dominant reason for screenout or pressure out, the well was restimulated successfully by implementing the solutions presented in this paper. In the second example, in which high PDL was considered to be the main reason for screenout, there were several wells in the same project area that exhibited the same behavior resulting in screenouts. After implementing the solutions presented in this paper to address high PDL, all new wells were stimulated successfully without any issues.

Abstract Over the last few years shale plays across North America have received significant attention because of their revenue potential and the supplementary reserves they add to the U.S. natural-gas reserves. However, the flow capacity (i.e., permeability) of these shales is very low and, therefore, requires some sort of stimulation to make them economically viable. Problems during stimulation treatments can lead to "pressure outs" and screenouts. One of the main reasons that lead to "pressure outs" is high process-zone stress (PZS). With high PZS, the chance for pressuring out is higher than screenout (i.e., one can still flush the job at lower rates provided the sand has not settled in the wellbore). The purpose of this work is to show the effects of high PZS in shale stimulation treatments and the associated production from such zones. Examples are presented from three shale wells in the Rocky Mountain region. Well A provides examples from the Gothic and Hovenweep shales, while Well B consists of an example from the Mancos shale. A Diagnostic Fracture-Injection Test (DFIT) was performed in the Gothic and Hovenweep shales before the stimulation treatment, and the results obtained point to very high PZS. History-match analysis of the Gothic and Upper or Main Hovenweep stimulation treatments using a grid-oriented, fully functional three-dimensional (3D) fracture simulator confirmed the same. Solutions are provided to overcome this effect and successfully "place" the stimulation treatment. However, the production associated with such high PZS zones is not very encouraging. Well A is temporarily abandoned because of poor production, and the Mancos shale well with high PZS (Well B) is one of the poor producers in the field. Finally, another example (Well C) from a successful Mancos test is also included in this work to show the difference in production between high- and low-PZS zones. This paper discusses methods for early identification of high-PZS shale zones to possibly avoid stimulation treatments in order to pay more attention to the low-PZS zones that require stimulation.

The two main objectives of using a hydraulic fracture model in coals are: (a) optimization of job design and placement, and (b) post-fracture diagnostics. Though certain limitations still exist, hydraulic fracture modeling in coals has undergone major advancements in the past decade. Pseudo or lumped three-dimensional (3-D) models have usually been employed to try and meet the objectives mentioned above. The effectiveness of using such models in coals has been very limited. Fully functional 3-D models are currently available in the industry and can be used to obtain better estimates of the fracture dimensions. This paper shows that a grid-oriented fully functional 3-D fracture simulator with shear decoupling can be especially useful in coals for post-fracture diagnostics if sufficient input data can be fixed from logs and Diagnostic Fracture Injection Tests (DFIT). When problems occurred with placement of fracture treatments, especially in the upper Fruitland coals of a San Juan basin project, instead of experimenting with various ideas arbitrarily, technical evaluation using DFIT data and fracture modeling with a grid-oriented, fully functional 3-D fracture simulator, was used to pin-point the issues and address them accordingly. This paper will discuss the deficiencies of using 2-D and pseudo-3-D fracture models in coals and also will discuss the lessons learned from using a grid-oriented, fully functional 3-D fracture simulator in this project along with the successful implementation of the results developed from the modeling work.

Abstract Some of the significant strides made in coal stimulation during the last 25 years can be attributed to the development of new-generation fluid systems (i.e., low gel loading fluids with efficient low-temperature breaker systems that cause less polymer damage in coals). All these new developments were implemented to (a) minimize damage in coals, and (b) maximize production. Water fracture treatments in coals completely eliminated polymer damage but did not always maximize production. The use of new-generation crosslinked fluids did provide better half-lengths and conductivities but still left residual damage in coals. Based on production, it was confirmed that the benefits obtained with this fluid system outweighed the damage created. To further reduce the damage in coals and obtain better regained fracture permeability, implementing hybrid fracture treatments in coals was considered in this San Juan basin project. The term "hybrid" in this case refers to a water pad followed by crosslinked fluid sand stages. Potential benefits of this technique in coals include: (a) minimizing damage caused by gel, (b) maximizing regained permeability, (c) containing height growth, and d) lowering cost. There are two parts to this work. The first part presented in this paper contains the design, implementation, and encouraging initial results obtained from the seven wells in this project, which is in an underpressured area. This is the first project in which hybrid-type treatments have been applied in a low-pressured formation. This paper will discuss the lessons learned from such an application in coals. When sufficient production data becomes available, the second part of this work will quantify the results via reservoir simulation. The second part will also include quantified results from another current hybrid fracture-stimulation project where the coals are slightly overpressured.

Summary The permeability, pore pressure, and leakoff type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff type distribution. The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture-height recession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows orders-of-magnitude variation in gas permeability within all basins, with observed gas permeability ranging from less than 0.001 to greater than 0.10 md.

Abstract Historically, Fruitland coal wells in the Tiffany area of the San Juan basin have to be hydraulically fractured to be economical. The need for artificial stimulation is that the Tiffany area coals are characterized by lower permeability than the coals in the San Juan basin "fairway" to the south. The post-stimulation gas and water production rates in the Tiffany area vary approximately from 50 to 250 Mcf/D and 40 to 500 BWPD respectively, but not all stimulated wells are economically successful. A study was initiated to develop a better understanding of the reservoir characteristics and completion effectiveness for the purpose of optimizing production from the Fruitland coals in the Tiffany area. Public domain1,2 production data was used to determine the average gas and water production rates for Fruitland coal wells in the project area. This data was combined with a detailed working geologic model for use in reservoir simulation analysis. History-matching the average well production resulted in the identification of several critical well performance issues: 1) the top Fruitland coal is not receiving treatment with the single-stage completion, 2) the basal Fruitland coal is not being effectively completed, 3) the basal Fruitland coal and the underlying Pictured Cliff sandstone is receiving most of the fracturing treatment, and 4) water production that does not show any significant decline is probably a result of contribution from the water-wet, lower-permeability Pictured Cliff sandstone underlying the basal Fruitland coal. Based on these significant findings, stimulation treatments have been completely revised. The top and basal Fruitland coals are now being treated separately at lower rates so that only the coals and not the water-wet, Pictured Cliff sandstone is stimulated. In addition, the perforations are now being carefully placed in the middle of the coal interval leaving one to two ft. at the top and bottom boundaries. In the wells that were orig inally stimu lated with a single-stage treatment, the top Fruitland coal is being restimulated. The results obtained from these modifications have been substantial. In the four wells that were restimulated, a minimum of 100%, to a maximum of approximately 400% increase in gas production rates were observed. Water production has decreased in most of the wells to less than 50 BWPD since only the coals are being dewatered and not the water-wet Pictured Cliff sandstone. In some of the new wells, even though there is a high initial water rate, it clearly shows a declining trend unlike the old wells completed with high rate, one-stage stimulation treatments. In addition, these new wells produce substantially higher gas rates when compared to the old wells. Specific examples from the project area are presented to show the effectiveness of the new stimulation procedures. Although the results of this study are specific to the Tiffany area, the methodology and techniques used can be applied effectively in other coalbed methane development areas.

Abstract Permeability and pore pressure are critical parameters in the evaluation of a coalbed methane (CBM) project. Coal permeability is particularly problematic, as it is highly stress dependent and estimates made from cores generally do not adequately reflect in situ reservoir conditions. Pressure buildup, injection falloff and more often slug tests have been used to determine in situ permeability in coal. However, buildup tests are costly, time consuming, and cannot be applied effectively in underpressured reservoirs; slug tests require an accurate estimate of wellbore storage effects. Similar to buildup tests, injection falloff tests are very time consuming and costly because of the longer shut-in times. Also, if fracture pressure is exceeded during an injection-falloff test, conventional analysis can give erroneous results. This paper presents a more effective method for determining pore pressure and permeability in coals using a diagnostic fracture injection testing technique. A diagnostic fracture injection test (DFIT) is a small-volume, cost-effective, and short-duration test that has been used successfully in tight gas sands in the Piceance and other basins. The test consists of (1) a G-function derivative analysis to identify the leakoff mechanism and closure, (2) a calibrated before-closure analysis using modified Mayerhofer method to determine the permeability, and (3) an after-closure analysis to estimate pore pressure and permeability. The uniqueness in applying this test in coals is that both the before- and after-closure analysis can be utilized where pseudo-radial flow is not dependent upon the fracture half-length. The technique works because the permeability in coals is high enough that after-closure pseudo-linear and pseudo-radial flows are normally observed with an extended shut-in. Once pseudo-radial flow is observed, estimating pore pressure and transmissibility becomes straightforward and provides calibration for the before-closure analysis. Hundreds of diagnostic fracture injection tests have been conducted in all the CBM basins in the rockies and in Canada with remarkably consistent results. Examples are provided from San Juan basin and Canadian coals where diagnostic injection tests have been applied successfully for various operators. DFIT's have been applied successfully in other CBM basins like Sand Wash, Greater Green River, Piceance, and (western) Powder River basin.

Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins David P. Craig; David P. Craig Halliburton Search for other works by this author on: This Site Google Scholar Mike J. Eberhard; Mike J. Eberhard Halliburton Search for other works by this author on: This Site Google Scholar Chad E. Odegard; Chad E. Odegard Halliburton Search for other works by this author on: This Site Google Scholar Muthukumarappan Ramurthy; Muthukumarappan Ramurthy Halliburton Search for other works by this author on: This Site Google Scholar Rebekah Mullen Rebekah Mullen Colorado School of Mines Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, April 2002. Paper Number: SPE-75717-MS https://doi.org/10.2118/75717-MS Published: April 30 2002 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Craig, David P., Eberhard, Mike J., Odegard, Chad E., Ramurthy, Muthukumarappan, and Rebekah Mullen. "Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins." Paper presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, April 2002. doi: https://doi.org/10.2118/75717-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Unconventional Resources Conference / Gas Technology Symposium Search Advanced Search AbstractThe permeability, pore pressure, and leakoff-type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff-type distribution.Specially designed "mini-frac" or diagnostic fracture-injection/falloff tests were routinely implemented throughout Rocky Mountain basins beginning in late 1998 for the sole purpose of estimating reservoir-engineering parameters. Using three recently developed analysis methodologies, more than 1,200 tests have been analyzed to determine permeability, pore pressure, and leakoff type.The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture height-recession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows order-of-magnitude variation in gas permeability within all basins with observed gas permeability ranging from less than 0.001 md to greater than 0.10 md.IntroductionEstimating pore pressure and permeability in multilayered low-permeability gas reservoirs can be time consuming and, in a few cases, cost prohibitive. Because of the incremental costs and time required to implement a testing program, very few conventional well tests are completed in multilayered low-permeability gas reservoirs, even though optimizing completions requires knowledge of permeability and pore pressure.1As an alternative to conventional well testing, Craig and Brown2 suggested that conventional breakdown treatments in multilayered formations could be used to estimate permeability and pore pressure. Their procedure required isolating each reservoir, performing a small-volume injection, and recording the pressure decline during a shut-in period.2 In low-permeability reservoirs, a small-volume, low-rate injection will propagate a hydraulic fracture, and during the shut-in period, the pressure decline can be analyzed to estimate pore pressure and permeability. Craig and Brown2 advocated conventional leakoff analysis for estimating gas permeability, but before-closure pressure-transient analysis3 and after-closure analysis4 provide more realistic estimates of gas permeability.Craig, Eberhard, and Barree5 recently described the use of G-function derivative analysis and modified Mayerhofer permeability analysis for estimating pore pressure and permeability from the before-closure pressure decline following a fracture-injection test. The authors concluded that, when used in conjunction, the two techniques provide "reasonable" pore pressure and permeability estimates that are consistent with well performance based on reservoir simulation.5 Reservoir simulation in other multilayered low-permeability gas reservoirs also confirms that reasonable estimates of pore pressure and permeability are often obtained from before-closure analysis.6,7 Keywords: leakoff-type distribution, upstream oil & gas, reservoir, flow in porous media, fracture-injection falloff test, fracture closure, closure, gas permeability rad, gas permeability gdk, hydraulic fracturing Subjects: Hydraulic Fracturing, Reservoir Fluid Dynamics, Formation Evaluation & Management, Flow in porous media, Drillstem/well testing This content is only available via PDF. 2002. Society of Petroleum Engineers You can access this article if you purchase or spend a download.