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Pei, Yanli (University of Texas at Austin (Corresponding author) | Yu, Wei (email: firstname.lastname@example.org)) | Sepehrnoori, Kamy (University of Texas at Austin and Sim Tech LLC) | Gong, Yiwen (University of Texas at Austin) | Xie, Hongbing (Sim Tech LLC and Ohio State University) | Wu, Kan (Sim Tech LLC)
Summary The extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.
Abstract The Lewis Shale is a turbidite system encompassing sandstones, siltstones, and organic-rich shales, deposited during the last Cretaceous seaway transgression. It is informally subdivided into three members; a lower member (characterized by high clay and organic matter content), a middle member (a mixture of siltstones, shales, and sandstones), and an upper member or Dad sandstone member (with decreasing amounts of sandstone and greenish-grey shales) that can reach up to 2600 ft. in thickness (Almon, 2002). Its lithological characteristics vary depending upon its location in the Lewis depositional basin (eastern Greater Green River Basin). The present study is located in the Sweetwater and Carbon counties in Wyoming. Data includes three cores in the Great Divide Basin and one in the Wamsutter Arch provided by MorningStar Partners/Southland Royalty. Cores contain various lithologies, including shales, siltstones, and sandstones, representing the Lewis Shale's lithologic heterogeneity and complexity. Reservoir quality and lithology are intrinsically related. Therefore, high-resolution reservoir characterization must be performed to understand these different intervals and forecast some of the reservoir properties and possible challenges. Measured and sampled core data includes X-ray Fluorescence (XRF), X-ray diffraction (XRD), and Routine core analyses (RCA). Well-log data obtained from the Wyoming Conservation Commission (WOGCC) and donated by TGS were used to perform correlations, build maps of the different cored intervals, and evaluate its internal characteristics and reservoir quality. Core description and X-ray Fluorescence spectroscopy (XRF) analyses were performed every 0.5 ft. Samples for thin sections and X-ray diffraction (XRD) were taken in areas of interest based on lithology changes. Well-logs were correlated using the Gamma Ray (GR) signature for the cored and adjacent intervals. The objective of this work is to develop a high-resolution reservoir characterization. This analysis is crucial for understanding this play and decreasing uncertainty when planning new well placements. Although there have been several studies that identify the primary minerals and analyze the reservoir quality of some intervals of the Lewis Shale, none has been a high-resolution study combining XRF data, nor have any been oriented to horizontal drilling and unconventional reservoirs (Thyne et al., 2003; Pasternack, 2005, Sapardina, 2012). Correlations helped identify the heterogeneity and possible complications these turbiditic reservoirs can present, such as target pinch out and an increase in clay content that could cause swelling or instability in the wellbore and a possible loss of the well or the need to drill a sidetrack. Furthermore, this was also evidenced in the thin section, XRD, and XRF analyses showing mineralogical variations down to the inches scale, which is lower than the well-log resolution, making it challenging to identify. The overall composition of all the intervals is very consistent with high quartz content, followed by clay and carbonate contents. The presence of illite/smectite swelling clays can increase the wellbore problems and reduce porosity and permeability. According to Wang and Gale (2009), the brittleness of rock or fracability is controlled by several factors such as strength, lithology, texture, effective stress, temperature, fluid type diagenesis, and Total Organic Carbon (TOC). The brittleness index helps quantify some of these factors based on the mineral composition and diagenesis of the rock, without calculating Young's and Poisson moduli. According to Jarvie (2005), minerals that affect this index the most are quartz (the higher the quartz content, the higher the brittleness) and Carbonate, Clay, and TOC content (these decrease the brittleness index). Wang and Gale (2009) also included dolomite as a brittle mineral. However, the brittleness index was not calculated on these cores due to the absence of TOC measurements in some of them and the formula could not be applied. An approximation of how brittle a rock can be based on the formula's principle, where the higher the percentage of quartz and dolomite, the higher the brittleness index. In instances where calcite percentage is high, it can act as a brittle mineral. Dolomite is found as grains and cement, augmenting the rock's brittleness, but it can also decrease its porosity and permeability. Although, in general, the high quartz, calcite, dolomite, and plagioclase content in all the cored intervals makes them particularly brittle, thus facilitating hydraulic fracturing.
Darneal, Chad (ConocoPhillips Company) | Friehauf, Kyle (ConocoPhillips Company) | McLin, Kristie (ConocoPhillips Company) | Rajappa, Bharath (ConocoPhillips Company) | Zhou, Hui (ConocoPhillips Company) | Hoang, Phuong (ConocoPhillips Company) | Hammond, Justin (ConocoPhillips Company) | Swan, Herbert (ConocoPhillips Company)
Abstract An ongoing challenge in unconventional reservoirs is the significant production degradation (loss of production) realized from child wells drilled adjacent to depleted parent wells. One strategy hypothesized to reduce the realized degradation is to modify the completion design in the child well. The main objective of this case study will be to test this hypothesis and quantify the impact completion design has on child well degradation; specifically, the case focuses on the stage architecture component of completion design defined as the combination of cluster spacing, number of clusters per stage, and stage length. This paper covers an integrated, multi-disciplined review of a unique development situation in the Permian where three different depletion scenarios surround a single well at various well spacings. This data rich review will characterize the SRV (Stimulated Rock Volume) and DRV (Drained Rock Volume) from each of four completion designs within the different depletion scenarios. Data sets include fiberoptic DAS/DTS (Distributed Acoustic/Temperature Sensing) and microseismic during stimulation, along with downhole pressure gauges, chemical tracers, downhole camera for perforation erosion, additional fiber-optic DAS/DTS production logs, and interference (well communication) tests. A single well with four different completion designs surrounded by three different depletion scenarios creates a rare opportunity to analyze the impact completion design has on child well degradation. Eight different forms of data acquisition technologies were used to increase understanding of completion variable impacts to SRV and DRV as well as validate several new cost-effective data acquisition technologies that were successfully trialed for this pilot. The SRV-related data shows fracture interference with offset depletion, but the amount of interference did not conclusively change among the various completion designs tested. Similarly, DRV-related data shows child well degradation when exposed to parent well depletion, but the amount of degradation did not conclusively change among the various completion designs tested. This suggests that factors other than stage architecture are the dominant drivers of well performance. Detailed analysis from the cross-functional team provides multiple perspectives on the results acquired as they pertain to the overall motivating objectives of the pilot.
Abstract We present an integrated, automated analysis workflow that can be performed in real-time where collected data populate templates while drilling (every 90 ft.). This workflow significantly improves the geosteering and wellbore placement, reduces uncertainty, and provides near wellbore rock characterization which is used for completion optimization. Several steps should be executed before data interpretation. Steps are: (1) importing Pilot Hole (PH) and Drilling Well (DW) data, and developing high level well log analysis including correlating pilot hole and drilling well gamma-ray data to obtain higher than 85% correlation coefficient, rocks classification, and constructing percentage pie-chart, K-mean clustering, and calculating volume of clay (Vclay), gamma-ray minimum, mean, and maximum every 90 ft., (2) visualizing gas compound and ratios to evaluate gas/oil ratio (GOR), reservoir boundaries and fluid types, and identification of potential water intervals, (3) analyzing mineralogical data to provide insight into carbonate influx (debris flow), and brittleness, and (4) calculating mechanical specific energy (MSE) which is used for identification of rock properties and potential geohazards (e.g., faults), and assisting in completion decision regarding stage length and cluster spacing selection and treatment recipe. Sequence stratigraphic concepts such as fining or coarsening upward cycles along the lateral length, for each survey, are also used to adjust stage and cluster intervals, and to identify depositional cycles and tectonic activities. The workflow has been tested and proved on public well data from Permian Basin, Eagle Ford, Bakken, and Hayneville formations. Valuable information volumes are captured which are not normally pinpointed due to constraints on data collection technologies, cost reduction measures, and limitations of current geosteering and well placement concepts. Testing resulted in identifying lithologic and geomechanical groups and variations, potential oil and gas producing intervals, out-of-target intervals, landing point comparison, and fault zones identification. Interpretation of all drilling data and plots assists in defining "similar rocks" intervals and selection of appropriate stage locations and length which will reduce frac hits among wells with a potential cost saving between 15 to 20 percentages in completion operation. The implementation of this methodology leads to: • Lowering risks and uncertainty, and increasing cost-effectiveness by reducing possible errors in geosteering operation. • Increasing confidence in wellbore placement and time and cost savings regarding the data validation, reservoir characterization, and identification of potential faults below seismic detection limits (30 ft.). • Identifying potential hydrocarbon types in different intervals and water-bearing zones. • Promotes increased efficiency in the selection of stage and cluster numbers and spacing, proppant and water volumes, and pump rate. • Reduction of potential well interferences when completing neighboring wells.
Smye, Katie M. (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin) | Ikonnikova, Svetlana (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas / Technical University of Munich, TUM School of Management) | Yang, Qian (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas) | McDaid, Guin (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas) | Goodman, Emery (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas)
Abstract In 2018 the U.S. became the largest oil and natural gas producer in the world. Whether this production can be sustained by technologic improvements or requires more intensive completions strategies has not been determined. If the latter, improvements may be exhausted due to diminishing returns, and a slowdown in investment and development, followed by sensitivity to future economic conditions, may be observed. To address questions of production performance as a function of both reservoir properties and completion intensity, we present a comprehensive comparative analysis of four tight oil plays: the Bakken of the Williston Basin, the Eagle Ford, and the Wolfcamp A and B of the Midland and Delaware Basins. We characterize variability in geologic properties within each play and across studied plays, focusing on attributes that can be interpreted basin-wide, including depth, thickness, porosity, water saturation, and brittleness. Drilled areas with comparable variability in key geologic attributes are identified across plays, and well productivity over time in those comparable reservoir regions is compared. Well completion trends, including treatment fluid and proppant intensities over time, are investigated for these areas. We show that capturing geologic variability in porosity, water saturation, depth and brittleness index allows for comparison of productivity in "geobins." The analysis provides insight into the effectiveness of more intensive completions strategies in terms of well performance. We also show that poorer per-well productivity in some plays can be explained by well downspacing. The results of this analysis allow us to determine the geologic limitations to well productivity in oil plays through a multi-basin study, to understand whether further technological improvements may be achieved, and to predict productivity improvements due to shared technological learnings across plays. Introduction Tight oil production in the U.S. has increased dramatically in recent years with the utilization and enhancement of horizontal drilling and hydraulic fracturing techniques, from 0.5 to over 8 million barrels (MMbbl) per day from 2005 to 2020 (Figure 1). However, the extent to which this increase in production reflects concentrated drilling in geologically attractive areas, step changes in technology, or more intensive and expensive completions strategies, has not been determined on basin-wide and multi-basin scales. To understand how drilling and completions parameters affect productivity and recovery efficiency, we seek to compare areas across plays with comparable variability in the geologic properties that can be measured and mapped, and that are likely to be the primary geologic drivers of resource-in-place and productivity.
Abstract Reliable assessment of petrophysical, compositional, and mechanical properties is critical and yet challenging for formation characterization of organic-rich mudrocks. The formation evaluation results are the key to build an accurate geological model and are the starting point for reservoir characterization. This paper aims to (a) develop a method to integrate an iterative formation evaluation workflow with geological modeling and (b) improve the reliability of field-scale geological modeling by reducing the average relative error and uncertainty in well-log-based estimates of petrophysical and geochemical properties using the integrated workflow. The first step includes joint inversion of well logs to obtain depth-by-depth estimates of formation properties such as porosity, fluid saturations, total organic content (TOC), and volumetric concentrations of minerals, which are inputs to the well-log-based rock classification algorithm. Then the model parameters are updated in each rock-class and the multi-mineral analysis results are cross validated with core measurements in wells where core measurements are available. The iterative procedure is repeated until agreement with core data is achieved. We use the geostatistical analysis to extend the workflow obtained in the cored wells to the neighboring non-cored wells where the developed model in each rock class is reliable. Finally, we use the well-log-based estimates of the petrophysical and geochemical properties as an input to the geological model to estimate reservoir properties such as original-hydrocarbon-in-place. We successfully applied the method to more than 300 wells in the Midland Basin. Results showed that the average relative error in well-log-based estimates of porosity and water saturations, improved by 22% and 35%, respectively, compared to a conventional non-iterative, non-integrated method which results in 76% improvement in the calculated hydrocarbon-in-place. A sensitivity analysis was performed to evaluate the impact of optimizing and calibrating the model parameters throughout the basin to reduce average relative error and uncertainty in well-log-based estimates of porosity and water saturation, as key petrophysical inputs to the geological model. Results indicated that applying a South Midland Basin TOC model to a North Midland Basin well, causes 56% and 16% increase in average relative error in estimates of water saturation and porosity, respectively, which results in 47% increase in average relative error of original-oil-in-place calculations. Coupling the integrated formation evaluation workflow, geostatistical analysis, and geological modeling is a novel approach that not only incorporates formation heterogeneity and spatial variations of reservoir properties, but also yields dependable reservoir characterization by quantifying the uncertainty associated with hydrocarbon-in-place estimation. This method enables a reliable field-scale formation characterization in the Midland Basin which is critical for field development planning in organic-rich mudrocks.
Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
Abstract The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3 BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
Abstract The application of crushed rock analysis for unconventional formation evaluation has become standard in core analysis following its introduction for shale gas volumetrics by Luffel and Guidry (1992). Crushing is used to expedite the extraction, drying, and volumetric measurement processes. Critical assumptions of crushed rock analysis include: all pore space is interconnected, crushing should not create entry into any pores that previously were isolated, and the crushed particles are orders of magnitude larger than the representative pore space. The analytical procedures were established to provide reservoir rock and fluid properties, for which log interpretation methods could be developed to match the core and production results. This study expands on the effect of crushing on core samples beyond the original Devonian shale scope of the Gas Research Institute, GRI, program. Mercury injection capillary pressure (MICP) measurements are incorporated to quantify volumetric and textural changes to the rock fabric from the crushing process. Changes in sample compressibility are also investigated to account for the removal of residual, low compressibility fluids. The objective is to understand potential fundamental changes to the rock to reconcile the crushed, cleaned ambient condition with stressed, subsurface conditions. Fourteen core samples, at an average frequency of 18’, are selected to represent a variety of lithologies across a 200’ interval of the Wolfcamp A in the Delaware Basin. Each sample was split into three subsamples: one subsample remained intact, one subsample is coarsely crushed to +50-mesh, and the last is crushed and sieved to -20+35-mesh fraction to replicate the particle size common for many crushed rock protocols (Luffel, 1992). All subsamples were cleaned using a sequence of organic solvents and dried at 60°C to remove residual free fluid and interstitial clay bound water (Burger, 2014). Certain facies showed a higher likelihood for pore alteration with dominant micro-scale pore features flattening, shifting, or re-distributing following the crushing and cleaning process. Mudstone samples experienced increases in compressible pore volume after crushing and extraction as total porosity converged towards GRI helium porosity. The results of this study provide characterization of the connected, effective pore volume using compressibility concepts and comparison to residual fluid volumes. The decision to crush, and the degree of crushing if so, should consider the representative pore sizes of each facies.
Kuila, Utpalendu (Cairn Oil & Gas, Vedanta Ltd.) | Sahoo, Ajit (Cairn Oil & Gas, Vedanta Ltd.) | Jenkins, Creties (Rose and Associates LLP.) | Dev, Tania (Cairn Oil & Gas, Vedanta Ltd.) | Dutta, Sandipan (Cairn Oil & Gas, Vedanta Ltd.) | Batshas, Siddhant (Cairn Oil & Gas, Vedanta Ltd.) | Wilhelm, Chandler (Wilhelm Geoscience Services, LLC) | Brown, P. Jeffrey (Rose and Associates LLP.) | Mandal, Arpita (Cairn Oil & Gas, Vedanta Ltd.) | Dasgupta, Soumen (Cairn Oil & Gas, Vedanta Ltd.) | Mishra, Premanand (Cairn Oil & Gas, Vedanta Ltd.)
Abstract The Lower Barmer Hill (LBH) Member of Barmer Hill Formation is the major regional source rock in Barmer basin of Rajasthan and has sourced nearly all the discovered fields. Our previous studies helped to identify the geochemical potential of the LBH as a shale play. Its considerable thickness (50m-800m), high organic richness (6-14 wt.%) and optimum thermal maturity as indicated by vitrinite reflectance (VRo up to 1.7%) makes it a potential unconventional shale play. However, many other questions need to be answered before exploration wells can be drilled. In this paper, we have addressed those important questions and the associated workflow for answering them, with an emphasis upon 1) delineating the prospective areas, 2) estimating prospective resource volumes in these areas, and 3) estimating the chance of commerciality. We have adopted a play-based approach to identify prospective areas in the northern part of the basin. The LBH shale was divided into two play types (oil and gas) based on thermal maturity ranges of 0.7-1.1% VRo and 1.1-2% VRo respectively. The less prospective areas were eliminated by applying global cut-offs for thickness (>30m) and TOC (>3 wt.%). Finally, the fault segments and the gross depositional environment (GDE) map guided the subdivision of each play type into play segments. A total of 8 play segments (five oil and three gas play segments) were delineated for further exploration. We then estimated the hydrocarbons-in-place and prospective resources of each play segment. Each play segment was subdivided into sub-play segment polygons based on five different thermal maturity windows corresponding to different hydrocarbon phases. The probability distribution of in-place volumes and technically recoverable resources (TRR) for individual sub-play segment polygon was generated using a reservoir hydrocarbon pore volume and recovery factor approach. Next, we compute the minimum breakeven estimated ultimate recovery (EUR) on a single well basis assuming an economic hurdle of zero NPV10 and production type curves from North American analog shale plays. The chance of meeting or exceeding this EUR for the average well (economic chance of success or ECOS) was then computed for each sub play segment. The 1U, 2U, and 3U Prospective Resources for the play segment were estimated by probabilistically aggregating the TRR distribution of its’ constituent sub-play polygons incorporating risk dependencies. The aggregated Prospective Resources numbers and the chance of success, along with other strategic parameters, help to rank the 8 play segments to high-grade projects for exploration drilling.
Given the state of the oil & gas industry today, i.e., low hydrocarbon prices and a global health crisis still in high gear, making good business decisions is more crucial than ever. Deciding which wells to keep open for production, which wells to shut-in, which wells to re-stimulate for immediate production, and which new wells to drill, if any, may directly impact a business' financial survival. This is true for both conventional and unconventional assets, but of significantly more concern to the unconventional asset investor, because incremental production is already capital-intensive at the best of times. Over the last decade, unconventional resources have become a significant source of the total production output in various parts of the world, and the primary stimulation treatment used is hydraulic fracturing. This technique sections a wellbore into multiple stages into which highly pressurized fluid is pumped at various fracture initiation locations. Historically, the number of stages and the number of clusters per stage, has primarily been based on total lateral length, previous experience in the same or similar fields, and on investment considerations, with a strong tendency towards decreasing stage and fracture spacing (i.e., increasing stage and fracture count). Field experience showing non-productive and full-physics simulations suggest room for improvement and indicate that there must be an optimal stimulation treatment that maximizes profit. Beyond this point, adding another stage in the treatment becomes more expensive than what can be recuperated by incrementally increased production. Thus, in the current work, the problem is posed as a classic constrained optimization problem and solved using Monte Carlo methods. Results show that in general, profitability of the production revenue is very sensitive to the reservoir recovery factor, porosity, drainage volume for the lease window, and, ultimately, the market price. Introduction Unconventional wells are challenging in many ways, and significant capital investment combined with relatively short production periods makes exploitation of these types of reservoirs a balancing act between costs and profit. Wells can run in the millions when drilling and completion costs are accounted for, with completion costs accounting for more than half of the capital requirement (EIA 2016). Fortunately, the completion details are one of the few inputs that can be adjusted in the field, which allows for fine-tuning to local conditions. In this work, we employ hydraulic fracturing as the stimulation technique, and note that it is the most common type of completion technique currently in use. During hydraulic fracturing, fluid is injected into a wellbore at high pressure to create cracks in the sub-surface in the neighborhood of the wellbore, through which natural gas and oil flow more freely than through the low-permeability formations typical of unconventional reservoirs. The pressurized fluid typically carries propping material such as sand, which is intended to hold open fractures after fracturing pressure is relieved and shut-in begins. The origins of hydraulic fracturing date back to early experiments in the 1940s at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind (Charlez 1997; Montgomery et al. 2010), and one of the first commercially successful applications of the new technology in the 1950s. As of 2012, about 2.5 million "frac jobs" had been performed worldwide on oil and gas wells; over one million of those within the U.S. (King 2012). In years past, such stimulation treatment was generally necessary to achieve profitable flow rates in shale gas, tight gas, tight oil, and coal seam gas wells (Charlez 1997), but in today's market environment, using the optimal stimulation treatment is all but economic requirement for economic survival.