下载文档原格式
第19卷第6期Production characteristics and law of shale gas reservoir under complex conditionsWang Nan 1,2,Zhong Taixian 3,Liu Xingyuan 4,Lei Danfeng 1，2(ngfang Branch,Research Institute of Petroleum Exploration and Development,PetroChina,Langfang 065007,China;2.National Energy Shale Gas R &D (Experiment)Centre,Langfang 065007,China;3.PetroChina Company Limited,Beijing100007,China;4.China Petroleum Materials Corporation,CNPC,Beijing 100029,China)Abstract:This paper focuses on analysis of shale gas reservoir characteristics,production mechanism and productivity characteristics after fracturing.In the study of shale gas reservoir,four components of porous medium for shale reservoir have been analyzed.It is proved that the organic matter is the main reservoir body and seepage channel for free gas.The content of organic matter and the characteristics of pore development directly influence the reserves and production of shale gas reservoir.This paper also analyzes the flow mechanism such as shale gas adsorption,desorption and diffusion,calculates the volumes of free gas and adsorbed gas based on those mechanism and explain the correlation between gas content and pressure history curve.In the analysis of shale gas productivity,the case is used to determine the characteristics of initial high production of single well,fast production decline at late stage and long production cycle.It is confirmed that the hydraulic fracture is the most important flow channel for shale gas.The pattern of hydraulic fracture is key factor to determine the productivity of shale gas.In this study,the production mechanism,characteristics and law of complex shale gas reservoir are summarized,which can provide theory support for improving the productivity of shale gas well and developing the shale gas reservoir on a large scale.Key words:shale gas;development;production mechanism;productivity;reservoir characteristics;decline analysis1储集机理1.1储层特征页岩储层具有分布广、单层厚度大、含气量低等特征，页岩气藏的存储形式可分为吸附气和游离气。
页岩挥发油井生产分析方法徐兵祥【摘要】生产数据分析方法已广泛应用于页岩油气井,该方法可通过分析生产动态数据,反演求取储层渗透率及裂缝半长等参数,但仅适用于存在一种相态的页岩干气井或页岩油井,应用于在储层及地面均有油气两相产出的页岩挥发油井则存在局限性.通过数值模拟手段,研究不同气油比对特征曲线和解释参数的影响,并提出利用产量折算法进行修正.研究表明:对于页岩挥发油井,仅考虑油相产量会导致均方根曲线斜率变大和线性流特征偏离,且初始气油比越大,线性流特征偏离越明显;同时会导致解释的裂缝半长偏小,实例中解释误差为7％～57％;运用产量折算法可将产气量折算成等质量的油相产量,运用修正后的产油量进行分析可大幅降低裂缝半长解释误差,最大降低幅度为42％.新方法简单便于现场应用,同时可应用于致密油藏.【期刊名称】《油气地质与采收率》【年(卷),期】2016(023)005【总页数】5页(P71-75)【关键词】页岩;挥发油井;生产分析;线性流;产量折算法【作者】徐兵祥【作者单位】中海油研究总院新能源研究中心,北京100028【正文语种】中文【中图分类】TE349近年来，全球掀起了页岩油气勘探开发的热潮［1-3］，并在北美率先实现了商业开发。
实践证明，页岩油气产量在较长时间内呈不稳定线性流特征，表现为产油量—时间双对数曲线是斜率为-0.5的直线，学者针对该特点建立了基于线性流的生产数据分析方法［4-11］，与Arps［12-13］，SEDM［14］，Duong［15］等经验或半经验方法不同的是，该方法由理论模型推导得出，并可根据生产数据反求储层参数和控制储量，再进行产量预测。
但该方法模型仅适用于单相油或气流动，北美部分页岩生产区块为油气同产井，如美国鹰滩地区，既有黑油、挥发油，还有凝析气。
笔者对区块挥发油进行生产分析发现，现有理论方法仅考虑了油相产量，而忽略了产气对分析解释的影响。
为解决运用现有方法所造成的误差和如何进一步改进等问题，笔者运用数值模拟手段分析气油比对线性流分析及解释的影响，并提出了改进方法。
一种有效开发致密碳酸盐岩气藏的新工艺——体积酸压李年银;代金鑫;张倩;贾建鹏;隋蕾;朱好阳【摘要】如何对致密裂缝性碳酸盐岩气藏进行有效开发,并使其稳产、高产一直是业界难题.针对这一难题,通过借鉴国外致密油气成功开发的一些研究成果,国内率先提出了针对致密裂缝性碳酸盐岩气藏的体积酸压工艺,经现场应用取得了良好效果.简要阐述了体积酸压的缝网形成机理,通过对比分析,初步明确了鄂尔多斯盆地致密气藏实施体积酸压的可能性;通过岩石脆性评价、裂缝发育及水平主应力差测试、原地应力方位与天然裂缝方位测定、裂缝潜在力学活动性预测、酸岩反应及酸液滤失实验,综合分析了目标气藏实施体积酸压的可行性;并结合现场应用简要阐述了实施体积酸压的原则和思路.最后,针对目前体积酸压实践给出了相关施工建议.该研究成果将推动致密油气藏体积酸压设计理论的发展,加快体积酸压工艺和材料研发速度,提升碳酸盐岩致密油气藏体积酸压优化设计水平,为今后致密油气藏的有效开发提供理论与技术储备.【期刊名称】《科学技术与工程》【年(卷),期】2015(015)034【总页数】12页(P27-38)【关键词】致密油气;致密碳酸盐岩;体积酸压;缝网;鄂尔多斯盆地【作者】李年银;代金鑫;张倩;贾建鹏;隋蕾;朱好阳【作者单位】西南石油大学"油气藏地质及开发工程"国家重点实验室,成都610500;西南石油大学"油气藏地质及开发工程"国家重点实验室,成都610500;中国石油西南油气田分公司天然气研究院,成都610213;中国石油长庆油田分公司苏里格气田研究中心;低渗透油气田勘探开发国家工程实验室,西安710000;中石油冀东油田分公司陆上作业区,唐山063000【正文语种】中文【中图分类】TE371非常规天然气的快速发展为世人所瞩目，对全球的能源格局形成了不容忽视的影响。
作为非常规天然气勘探开发的领跑者，20世纪80年代初，美国非常规天然气勘探开发取得重大突破。
第27卷第1期2017年2月中国环境管理干部学院学报JOURNAL OF EMCC Vol.27 No.1 Feb. 201710.13358/j.issn.1008-813x.2017.01.06页岩气勘探开发项目环境影响技术评估要点周井刚(重庆市环境工程评估中心，重庆401120)摘要：页岩气勘探开发建设一方面优化了能源结构，保障了能源安全，另一方面也对区域 环境造成了一定的影响。
通过简述页岩气勘探开发项目的环境影响，提出生态环境、水环境 影响、公众参与要求等在页岩气勘探开发环境影响技术评估中应受到重点关注。
关键词：环境影响；页岩气勘探开发；评估要点中图分类号：X37 文献标识码：A文章编号：1008-813X(2017)01-0022-03 Technological Evaluation of Shale Gas Exploration and DevelopmentZhou Jinggang(Appraisal Center for Environmental& Engineering of Chongqing City, Chongqing401120, China) Abstract ：Shale gas exploration and development do not only optimize the energy structure and ensure the energy security,but also has the negative impact on ecological environment.The environmental impact of shale gas exploration and development was discussed in the research.Research results showed that ecological environmental and water environmental effects should be paid more attention to in shale gas exploration and development.Key words：environmental impact,shale gas exploration and development,essentials of assess-页岩气是指赋存于富有机质泥页岩及其夹层 中，以吸附或游离状态为主要存在方式的非常规 天然气，具有含硫量低、难开采等特点，与常规 天然气有着明显的差异（见表1)。
深层页岩气井产能的主要影响因素——以四川盆地南部永川区块为例曹海涛1,2,3 詹国卫1 余小群1 赵 勇11. 中国石化西南油气分公司勘探开发研究院2. 中国石化西南油气分公司博士后科研工作站3. 西南石油大学博士后科研流动站摘 要 影响深层页岩气井产能的地质和工程因素众多，明确主要的影响因素对于深层页岩气的高效开发具有重要的意义。
为此，以四川盆地南部永川地区8口水平井为样本，采用灰色关联分析法研究地质、钻井、压裂、生产等4个方面的19个参数与气井产能的关联度，明确了主要的影响因素，并建立了无量纲产能评价指标(QI )与无阻流量的关系式，进而针对永川区块南区和北区分别提出了提高页岩气单井产能的建议。
研究结果表明：①裂缝发育程度、Ⅰ类储层钻遇率、水平段长度、埋深、单段液量、加砂强度、压力系数、总有机碳含量和脆性指数等9个因素对气井产能起到了主要的控制作用；②所建立的QI 与气井无阻流量的关系模型，可实现对气井产能的快速评价；③建议在永川区块南区加强钻井的跟踪监测以提高优质储层的钻遇率，在北区则加强对压裂工艺的攻关，提升储层改造的效果以实现气井产能的突破。
结论认为，该研究成果对于研究区的井位部署和压裂参数优化具有一定的指导意义。
关键词 深层页岩气 气井 生产能力 影响因素 灰色关联 关联度 永川区块 四川盆地南部DOI: 10.3787/j.issn.1000-0976.2019.S1.020基金项目：中国石化“十条龙”科技攻关项目“深层页岩气综合评价及开发技术政策”（编号：P18058-1）。
作者简介：曹海涛，1987年生，博士；主要从事页岩气开发方面的研究工作。
地址：（610041）四川省成都市高新区吉泰路688号。
电话：（028）65286384。
E-mail:*****************通信作者：赵勇，1981年生，副研究员；主要从事页岩气开发方面的研究工作。
地址：（610041）四川省成都市高新区吉泰路688号。
From: Schaal, MichaelSent: Monday, June 20, 2011 4:15 PMTo: Ian UrbinaCc: Cogan, JonathanSubject: RE: NY Times queryMr. Urbina,This email is in response to your recent inquiry to the Energy Information Administration (EIA) regarding shale gas.My name is Michael Schaal and I am the director of the Office of Petroleum, Natural Gas and Biofuels Analysis within EIA’s office of Energy Analysis. All of EIA’s short term natural gas forecasts (out to 2012) and long term natural gas projections (out to 2035) are developed by EIA analysts and modelers who work in my office.The attachment provides a quick overview of our approach to the shale gas issue, including material that addresses your specific questions.One guiding principle that we employ is, “look at the data.” It is clear the data shows that shale gas has become a significant source of domestic natural gas supply. Prior to 2005 shale gas constituted only 4% of natural gas production and had grown to become 23% of production for 2010. EIA’s continued monitoring of the situation indicates that growth in shale gas production continues and that shale gas has exceeded 30% of total marketed natural gas production through May of this year.Don’t hesitate to contact me if you have any further questions.A. Michael Schaal, DirectorOffice of Petroleum, Natural Gas and Biofuels AnalysisEnergy Information Administration1000 Independence Ave. SWWashington, D.C. 20585Attachment:EIA Response to 6/17/11 New York Times inquiry on Shale GasThe continuing discussion regarding estimates of technically recoverable shale gas resources among Energy Information Administration (EIA) staff at all levels is a part of a healthy analytical process that considers both the shorter term dynamic of the industry and the longer term implications. Ultimately, senior analysts and managers in EIA’s Office of Energy Analysis decide how to characterize technically recoverable resources for EIA’s Annual Energy Outlook (AEO) Reference case. Recognizing that the characterization of shale gas resources is both uncertain and important, the AEO2011 features a prominent Issues in Focus discussion of cases with both lower and higher availability of shale gas than in the Reference case, as discussed in the body of this response.While resource estimates will continue to be updated as new information become available, experience suggests that EIA has been more likely to understate rather than overstate the contribution of unconventional oil and natural gas resources in recent AEO Reference cases.Annual Energy OutlookEvery year, EIA develops the AEO based on the best available data regarding energy resources, supply technologies, consumption determinants, and prices. As part of this AEO effort, EIA uses a variety of public sources to develop data used in EIA energy models, for example, shale gas well production profiles, costs, and resources by shale formation. These data sources include, but are not limited to, the following sources:∙HPDI for individual well production data∙Lippman Consulting for shale gas production by shale formation∙INTEK, Inc. which collected publicly available shale gas well production profiles and well costs.INTEK also developed shale gas resource estimates for specific shale gas formations that currently under development (e.g., Barnett, Haynesville, Marcellus), based on both estimated shale gas well recovery rates (derived from well production profiles) and shale formation acreage.∙U.S. Geological Survey for resource estimates regarding shale formations that are not currently under development and for which there is no well drilling, production, or cost history∙Oil and gas company presentations that provide shale gas well production profiles and costs, and∙Press reports on company acreage, acreage costs, well production profiles and costs.The assumptions regarding shale gas resources currently being used as the basis of EIA’s Reference case projections are consistent with estimates of technically recoverable resources from a wide range of academic and industry experts. EIA uses contractors to supply critical expertise in resource assessment for regions and resource categories where development activities undertaken since the last available resource assessments by government agencies have added significant new knowledge about resources. This longstanding EIA practice has been applied for resources other than shale gas, including tight sands gas, shale oil, and enhanced oil recovery. EIA's procurement of contractors for this and other purposes conforms with all applicable federal rules and policies.EIA’s development of the projections and alternative cases for the AEO are documented and made available within the AEO itself, a paper outlining key assumptions1 and the model documentation.2 In1 Available on the EIA website at /oiaf/aeo/assumption/oil_gas.html2 Available on the EIA website at /analysis/model‐documentation.cfmaddition, the process that we used to develop the underlying model structure itself is, and remains, an open process as documented on our website.3The AEO oil and gas supply models undergo continuous modification and improvement based on new information regarding drilling and production technologies, and the ability and cost of developing oil and gas resources using those technologies. The resource recovery and cost of recovery associated with a specific well cannot be fully ascertained until that well is plugged and abandoned.The Annual Energy Outlook 2011 (AEO2011) acknowledges this uncertainty surrounding shale gas resources and the cost of developing them in the AEO2011 Issues in Focus analysis entitled: “Prospects for Shale Gas.”4 We invite your attention to that section, which was developed in order to understand those issues. That analysis notes that “there is a high degree of uncertainty around the (AEO2011 reference case) projection, starting with the estimated size of the technically recoverable shale gas resource. Estimates of technically recoverable shale gas are certain to change over time as new information is gained through drilling and production, and through development of shale gas recovery technology.” The article then delineates 5 specific uncertainties associated with shale gas resources and costs. The analysis goes on to discuss 4 alternate case projections, which double and halve the resource base and the shale gas production cost per well. The variation in alternate case assumptions is consistent with the degree of resource variability shown in USGS shale gas resource assessments. Across the 4 alternate shale gas cases, considerable variation is projected in domestic shale gas and total natural gas production, natural gas imports, natural gas prices, and natural gas consumption.One issue that is directly incorporated into EIA’s modeling is the steep declines in production from shale gas wells. EIA assesses the current and potential future decline curves for shale gas and other natural gas production by reviewing the well‐level data available from HPDI as well as other sources. An aggregate representation of how shale gas decline curves impact shale gas production is shown in Figure 1. The figure shows the model result of how the relatively large first‐year declines of wells drilled, combined with the decline in production from the all other wells in production results in an increasing amount of gas that must be replaced each year before further growth can be achieved. Our analysis and modeling shows, given all the information gathered and reviewed to date, that such production can be achieved within the time frame of the projection.3 Available on the EIA website at /oiaf/emdworkshop/model_development.html in the section describing the development of the Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS)4 Available on the EIA website at /forecasts/aeo/IF_all.cfm#prospectshaleFigure 1. Projection of U.S. Shale Gas Production by VintageInternational Shale Gas Resource AssessmentEIA’s recent report, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States , was developed to explore the issue of whether other countries have geological opportunities similar to the Unites States to develop shale gas. The report is intended to be a starting point in addressing that question. Above ground issues were not considered within the report. During the development of the report, bi ‐weekly conference calls were held with other offices within DOE as well as other government agencies to review and comment on draft chapters as they were developed by the contractor. We believe that the report stands on its own merits as we required the contractor to fully document all work and to clearly describe the methodology that was employed to produce the estimates. We welcome any substantive comments on the technical merits of the report.The Shale Gas Industry: Short TermThere have been numerous discussions within EIA about whether the major production increases over the past several years are sustainable from an economic perspective. Included in these discussions are debates about lease costs, the costs of production, the decline rates and ultimately recoverable resources from shale wells, the price of natural gas, the price of natural gas liquids, and the price of crude oil.Notwithstanding the sharp decline in natural gas prices since mid ‐2008, there are a number of factors that have prevented a significant slowdown in production growth up to the present time, some of which are likely to continue:4812200920142019202420292034∙Some producers have been active hedgers and, therefore, may not immediately respond to price declines with reduced production. Companies can continue to lock in prices that may limit their profit potential if prices rise quickly but also shield them from further declines that would make their short term business plans untenable.∙Lease terms often stipulate that production must begin within a number of years or the lease becomes void. Producers who purchased leases are sometimes motivated to drill in order to secure the lease for the future. According to trade press reports, this behavior has been a factor over the past year, particularly in the Haynesville shale. There are indications that this type of drilling is winding down as producers secure their leases.∙The major price differential between natural gas, natural gas liquids (ethane, butane, propane, etc), and crude oil means that a low natural gas price can be overcome by drilling in “wet” plays – areas such as parts of the Eagle Ford and Marcellus shales with high liquid or crude oil content. Some analysts estimate that natural gas in these plays can be sold at low prices while still maintaining a profitable well because of the high price of those liquids.∙Joint ventures from international partners have provided major infusions of cash to companies in the United States and Canada. These partners, who could be interested in expanding the use of new drilling technology overseas at some point in the future, may focus on gaining technical experience and technology associated with shale drilling in addition to the value of hydrocarbon production.。
Shale gas 页岩气 Raise the pressure 增加了开采压力 Government dithering keeps frackers above ground 政府仍就是否批准开采页岩气犹豫不决 Inflated concerns 担心通胀 FOR all the debate about it, Britain's shale-gas industry is minuscule. Whereas roughnecks inAmerica have sunk many thousands of wells since a boom began more than a decade ago,Britain has fracked at only one test site, in Lancashire, and not since 2011. In a reportpublished on May 8th, an all-party group from the House of Lords said that speeding shale-gasexploration should be an “urgent national priority”. So far, so familiar—and entirely in tunewith the position of the coalition government. But the authors go on to blame the government,not green campaigners, for holding the frackers up. 在所有对于页岩气的争议中，英国的页岩气企业发展最为迟缓。
一百年前天然气开始发展时，美国的油井工人已经下探了数千油井了，而直到2011年，英国才在兰开夏郡一处试点进行油井开采。
SPE 119899Economic Evaluation of Shale Gas ReservoirsJohn D. Wright, SPE, Norwest CorporationCopyright 2008, Society of Petroleum EngineersThis paper was prepared for presentation at the 2008 SPE Shale Gas Production Conference held in Fort Worth, Texas, U.S.A., 16–18 November 2008.This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. AbstractThree 9-square mile areas in the Newark East Field were studied to investigate the economic viability of the Barnett shale gas play. The areas chosen corresponded to the 25th, 50th, and 75th percentiles based on average estimated ultimate recovery per well in the areas. The actual drilling and refrac schedule was used for each area along with actual and forecasted production and today’s costs and prices to calculate economics on the 329 wells in the areas. Most of the individual wells are not economic under the assumptions of this study. Of the three areas, only the 75th percentile area was economic when considered as a whole. The results are most sensitive to capital costs and gas prices.IntroductionGas shale plays are the current rage in the U.S. oil and gas industry. At the present time major gas shale plays are unfolding in the Barnett, Woodford, New Albany, and Fayetteville shales and other basins are being targeted as well. The most mature of these plays is the Barnett shale near Fort Worth Texas with more than 6000 wells on production. The most mature field in this play is the Newark East Field located primarily in Wise and Denton counties, Texas. This field was “discovered” in 1981 and rapid drilling began in the late 1990s. There is now enough production history to begin to develop an idea of how commercial these plays can be. As with any emerging resource play, there have been a number of changes in drilling and completion practices over the years. Major advances in technology include drilling horizontal wells, re-fracing existing wells, and using slick water for frac jobs. Rather than attempting to quantify the effects of those technological changes, this study examines the economics of the Barnett play as it was actually developed.Study MethodologyThe Barnett gas shale in the Newark East Field was studied by subdividing the field into 3-mile x 3-mile blocks. The average estimated ultimate recovery (EUR) for each 3 x 3 block was determined from a proprietary database containing EUR’s for approximately 4500 Barnett shale wells. This database was created by using decline curve analysis to estimate remaining reserves for each “event” on each well. “Events” subsequent to initial production are usually assumed to be refracs, but may include significant increases in production from other effects. Figure 1 shows the production rate from an example well along with the decline curve extrapolations. A bubble map of the average EUR for each block which contains more than 20 wells is shown in Figure 2. Figure 3 contains a cumulative frequency plot of EUR for those blocks. It can be seen that the cumulative frequency curve is almost linear, indicating that the average EUR’s for the blocks appear to be approximately uniformly distributed. Three blocks were chosen for more detailed study. These blocks correspond roughly to the 25th, 50th, and 75th percentile as shown by the large dots on Figure 3 and the black, red, and blue dots on Figure 2. Each of these study areas contains more than 100 wells. The study areas will be referred to as the “Low”, “Medium” and “High” areas in the remainder of this paper.For the purposes of this study the timing of the wells, the choice of horizontal or vertical wells, and the refracing was modeled exactly as it occurred. Actual production was used as long as it was available and the extrapolation of the final “event” was used to project future production. Obviously, these assumptions limit the applicability of the study results to new plays where different technology might be employed from the start. It also does not take into account potential refracs or recompletions or increased density drilling in the future in the three areas. However, in spite of these limitations, it is instructive to look at the economics of these areas based on historical timing and technology.119899 2 SPEEconomics were run for each individual well and summed to arrive at “project” economics using “base case” assumptions forprices and costs. This is equivalent to assuming that a company holds a 9-section area and develops it with approximately100 wells. Sensitivity runs were made to determine the effects of a 25% change in prices, capital costs, and operating costs.An additional sensitivity run was made in each area to examine the effect of the top 5% of the wells on the projecteconomics.Production ForecastFigures 4, 5, and 6 show a “project” production history and forecast on a semi-log plot along with the vertical and horizontalwell count and the number of refracs on a Cartesian plot. The historical production and forecast for each area is compared inFigure 7. While a quantitative comparison cannot be made, it is interesting to note that the Low Area has primarily verticalwells with few refracs, the Medium Area has primarily vertical wells with many refracs, and the High Area has about twiceas many horizontal wells as vertical wells and few refracs.Economic ParametersThe economics were run on an individual well basis and summed for each area. The base case economic parameters areshown in Table 1 and were chosen to represent an approximation of current conditions. The cases were run on a before-income-tax basis and the net cash flows were discounted back to time zero (the date of first production for each of theindividual areas) at 10% per annum.Base case runs were made for each area. Sensitivity runs were also made for each area by individually varying price, capitalcosts, and operating costs 25% higher and lower than the base case values. An additional sensitivity run was made byremoving the top 5% of the wells in each area from the analysis. A total of 24 different runs were made.ResultsBase CaseThe EUR’s for the wells ranged from about 50 MMCF to about 6 BCF with most of the wells being below 1 BCF. Figure 8shows the cumulative frequency of EUR (for the base case economic assumptions) for each of the three areas. In the LowArea, 90% of the wells are less than 1 BCF. In the Medium Area, 60% of the wells are below 1 BCF, and even in the HighArea about 50% of the wells are less than 1 BCF. All of the areas show a wide variation in EUR; between 1 and 2 orders ofmagnitude. On an undiscounted basis, the EUR necessary to pay out the well or just recover the capital cost ranges fromabout 550 MMCF to 900 MMCF as shown in Figure 9. There is an excellent correlation between EUR and undiscounted netcash flow (sometimes called NPV0) as shown in Figure 10, a “zoomed-out” version of Figure 9.A number of managerial indicators were calculated including undiscounted net cash flow, time to payout, net present value,discounted profit to investment ratio, and internal rate of return. Discounted profit to investment ratio (DP/I) will be used tocompare the different areas. For the purposes of this paper, DP/I is calculated by dividing the net cash flow discounted at10% by the investment stream discounted at 10% and adding 1. This is equivalent to dividing the discounted net operatingincome by the discounted investment. The “hurdle” value is therefore 1.0. A project or well that has a DP/I of 1.0 has a netpresent value (NPV) of zero at 10%. That means it has a 10% internal rate of return. For the assumptions in this study thereis a strong correlation between internal rate of return and DP/I as shown in Figure 11. Using the assumptions in this study,including the shape of the production profile, a DP/I of about 1.25 results in an internal rate of return of about 20%. Asignificant number of wells had internal rates of return that were less than zero, i.e., the wells never paid out.The economics for individual wells in the three areas can be compared by examining a cumulative frequency plot of DP/I asshown in Figure 12. Assuming a DP/I hurdle of 1.0, 50% of the wells in the High Area, 65% of the wells in the MediumArea, and 90% of the wells in the Low Area are uneconomic. The results on a total project (area) basis are a DP/I of 0.54 forthe Low Area, 0.90 for the Medium Area, and 1.24 for the High Area. That means that if each of the areas were a project,one project would be a dismal failure, one would be a mild economic failure, and one would be a reasonable, but notoutstanding, economic success. Successful refracs in the future will help the economics somewhat from those presented here.Sensitivity CasesThe sensitivity cases are presented on an area basis. The results are contained in Table 2. The input variable with the mostimpact on DP/I is the capital cost. A 25% decrease in capital costs results in a 44% to 72% increase in DP/I. A 25% increasein gas price results in a 28% to 34% increase in DP/I. As usual, operating expense has little effect on full cycle economicswith a 25% change in operating costs making a 3% to 9% change in DP/I. Production profile has the largest effect, however.A 25% decrease in capital costs or a 25% increase in prices will not, by themselves, make the Low Area economic.However, changes of those magnitudes will cause the Medium Area to become economic. The fragile nature of these typesof plays is illustrated by the effect of a price decrease or cost increase on the High Area. A 25% decrease in price or a 25%increase in capital costs will cause even the High Area to become uneconomic.SPE 119899 3 The top 5% of the wells are very important to the overall economic viability of the projects. If the top 5% of the wells were not discovered then the DP/I would be 0.48 instead of 0.54 for the Low Area, 0.83 instead of 0.90 for the Medium Area, and 1.10 instead of 1.24 for the High Area. In that scenario, the High Area becomes somewhat marginal as a project. Considering that the High Area represents the 75th percentile of the entire field this has large implications for the development of the play.Conclusions1.There is wide range in EUR’s and, according, a wide range in economic value for individual wells in the Barnettshale play.2.At today’s costs and prices it takes an ultimate recovery of about 550 to 900 MMCF to pay out a well.3.Based on the economic assumptions used in this paper, 226 of the 389 wells studied (69%) had less than a 10%internal rate of return.4.At today’s costs and prices the 25th percentile areas based on EUR are not economically viable, the 50th percentileareas are almost economically viable, and the 75th percentile areas are reasonably economically viable.5.Discounted profit to investment ratio is very sensitive to capital costs and gas prices and much less sensitive tooperating costs.6.In any given area, the top 5% of the wells based on ultimate recovery have a significant effect on the economicviability of the project.4 SPE119899Table 1 – Economic ParametersCapital CostsVertical Well Drill & Compl. $2,400,000Vertical Well Refrac $ 600,000Horizontal Well Drill & Compl. $3,400,000Horizontal Well Refrac $1,000,000Operating Cost 6000 $/well/monthAsof Date Varies by AreaDisc Rate 10% /AnnumWorking Interest 100%Net Revenue Interest 85%Severance Tax Rate 7.5%Ad Valorem Tax Rate 3.0%BTU/SCFBTU 1000Shrinkage 0Net Back Wellhead Gas Price $7 /MMBTUTable 2 – Results of sensitivity cases on discounted profit to investment ratioDiscounted Profit to Investment Ratio (DP/I) @ 10%AreaArea HighArea MediumLow-25% Base +25% -25% Base +25% -25% Base +25%Price 0.36 0.54 0.72 0.62 0.90 1.18 0.89 1.24 1.59Capex 0.91 0.54 0.35 1.55 0.90 0.59 1.79 1.24 0.93Opex 0.58 0.54 0.49 0.96 0.90 0.85 1.29 1.24 1.20Figure 1 – Production history and forecast for an example well.SPE 119899 5 Figure 2 – Bubble map of average EUR for all wells in a 3-mile by 3-mile block with study areas highlighted4Bl Low (25th Percentile) AreaMedium (50th Percentile) AreaFigure 3 – Cumulative frequency of average EUR with study areas highlighted119899 6 SPEFigure 4 - Production history and forecast, wellcount, and refrac count – Low (25th percentile) AreathSPE 119899 7 Figure 6 - Production history and forecast, wellcount, and refrac count – High (75th percentile) Area119899 8 SPEFigure 8 – Cumulative frequency of EUR for each of the three areasSPE 119899 9 Figure 10 – Correlation between EUR and undiscounted net cash flow10 SPE119899 Figure 12 – Cumulative frequency of individual well DP/I for each area。
