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Collaborating Authors
Devon Energy Corp.
A 3D Geomechanical Analysis of Horizontal Well Refracturing and “Frac- Hits”
Kumar, D. (University of Oklahoma) | Masouleh, S. Feizi (University of Oklahoma) | Ghassemi, A. (University of Oklahoma) | Riley, S. (Devon Energy Corp.) | Elliott, B. (Devon Energy Corp.)
ABSTRACT: Field experience has shown that infill or “child” well fractures could propagate towards the “parent” well and previously depleted zones causing unwanted communication between the infill and producer wells and negatively impact production. To investigate this problem, we present a geomechanical analysis of production induced stress reorientation around hydraulic fractures in a horizontal well, and simulate subsequent propagation of multiple hydraulic fractures from an infill well. The fully coupled model “Geo-Frac3D” which combines the boundary element method and the finite element method for rock matrix deformation/fracture propagation, and fracture fluid flow is used in this work. Simulation results show that production from hydraulic fractures in a horizontal well gives rise to a non-uniform pressure distribution leading to unequal changes in the reservoir stresses which may result in a complete stress reversal around the fractures and in the infill well zones. As a result, fractures from the infill well tend to propagate preferentially towards the “parent” well. The fracture propagation from the infill well before and after repressurization of the production fractures is also considered. Results demonstrate that production induced reservoir pore pressure and stresses have a very significant impact on the subsequent fracture propagation from the infill well and “frac -hit” issues. By repressurization of production fractures before the infill well fracturing, the “frac-hit” problems might be potentially mitigated. The simulation results agree well with more elaborate simulations that account for the layered reservoir properties.
- North America > United States > Texas (0.94)
- North America > United States > California (0.68)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
Abstract Minimizing and mitigating the environmental impacts of our developments and operations is a very important business driver for Devon Canada Corporation (Devon). Devon takes this responsibility seriously, and believes in maintaining social license to operate, respecting stakeholder interests, and not just meeting, but exceeding, regulatory requirements where it makes sense to do so. Our commitment to the environment is reflected in our corporate policies, which include a Biodiversity and Land Stewardship Policy that provides overarching top-level direction to wildlife, biodiversity and land issues. Wildlife and biodiversity are among the most tangible concerns for stakeholders in Alberta's oil sands region. In 2002, very little was known about wildlife responses to in situ oil sands development. Acknowledging this information deficiency, and recognizing that in situ oil sands development was a long term and incremental commitment, Devon initiated what would become an ongoing In Situ Wildlife Mitigation and Monitoring Program to monitor wildlife populations, conduct research to fill key data gaps, and mitigate negative impacts to wildlife and biodiversity in and around our project areas. To achieve our vision of minimizing impacts to wildlife in the oil sands region, we have made biologically sound commitments, collaborated with peers and other resource sectors, developed strategic research partnerships, and engaged employees at every level throughout the company in implementation. In its current state, the Program has now been endorsed by regulators as the best-in-industry for such initiatives, and has been recognized with numerous awards for its comprehensiveness, innovation and corporate commitment.
- North America > United States (0.94)
- North America > Canada > Alberta (0.50)
- North America > United States > Montana > Devon Field (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > University Field > Wolfcamp Formation (0.94)
- North America > United States > Alaska > Arctic Ocean > Arctic Basin > Amerasia Basin > Canadian Basin (0.93)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Social responsibility and development (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- (2 more...)
Are Your Geoscience Software Applications Maintaining the Geospatial Integrity of Your Data? Joint Industry Project GIGS is Answering the Questions For Industry.
Schostak, Brian (Shell Exploration and Production Company) | Stigant, Jonathan (Devon Energy Corp.) | Barrs, Barry (ExxonMobil Exploration Company) | Davis, Jonathan (BP Americas Inc.)
Introduction Summary Some eighty percent of all geosciences data are spatially referenced. This presentation addresses a key issue that directly affects the E&P workflow, including, the geophysical acquisition, processing, and interpretation. In particular, three workflow activities are sensitive to geospatial integrity: data handling, data integration, and data mapping. All three are vital to achieving successful exploration and all three are affected by the geospatial integrity of the applications used. Twelve E&P operators have funded a Joint Industry Project (JIP) through the International Association of Oil and Gas Producers (OGP) to improve software applications used by petroleum geoscientists. Various software manufacturers are collaborating in this study. This JIP is a strategic industry initiative. It is anticipated that its’ impact will be felt over several years. The rationale, progress, and early results of the project are discussed. As professionals, we rely on hundreds of geoscience and engineering software applications that have coordinate conversion or transformation functionality. Correct geospatial data is vital to successful technical and commercial decision-making at all levels of E&P companies and throughout their workflows. However, errors in coordinate data and coordinate references are widespread and have often been a direct result of software problems. Such incorrectly manipulated data are widely distributed in an E&P company. They are stored in company databases and used by many teams, each with unique and specialty applications, to create new information and extract value. This value can be severely reduced by the errors systemically imparted to the data and can cause very expensive and often invisible mistakes in well location selection. A JIP is underway to study these industry-wide problems and recommend solutions. Issues Observed Objectives of Project • To transform the management of geospatial data in geoscience software applications to benefit JIP members and improve vendor products and competencies • To develop and disseminate best practice tools for current software applications and future software developments • To create a sustainable improvement process in geoscience software applications based on sound geospatial data management Figure 1 represents a model of the overall geospatially impacted workflow. Note that data are not just imported once, but literally flow through the company from database-to-database and project to project over many years, generally without any quality indications or audit trail. Traditionally the software used to manipulate these data are assumed to manage coordinate information correctly. When it comes to geospatial data integrity, not all software packages are the same. Recent focus on this technical issue has illuminated a significant and worrying list of inadequate performance including; improperly coded geodetic algorithms, wrong values for embedded geodetic parameters, poor presentation of user input requirements, incorrect default settings used without reference to user, confusing or incorrect terminology, lack of error trapping for user blunders, lack of audit trail for forensic analysis, inadequate metadata functionality, and misguided users. Some examples of user interfaces are shown in figure 2. A Simple Example of the Problem Identified in a commonly used G&G package were incorrect transformations of coordinate reference systems (CRS) that created 25 to 35 meter errors in well locations.
Using Geostatistical Inversion of Seismic And Borehole Data to Generate Reservoir Models For Flow Simulations of Magnolia Field, Deepwater Gulf of Mexico
McCarthy, Peter (Devon Energy Corp.) | Brand, John (Devon Energy Corp.) | Paradiso, Bob (Devon Energy Corp.) | Ezekwe, John (Devon Energy Corp.) | Wiltgen, Nick (Devon Energy Corp.) | Bridge, Alex (Devon Energy Corp.) | Willingham, Richard (CR Willingham & Assoc.) | Bogaards, Mark (Fugro-Jason)
ABSTRACT The Magnolia field is located in GOM blocks GB 783 and 784 and produces from Plio-Pleistocene turbiditic sands that form a complex channel/levee sequence penetrated by 16 boreholes. The primary pays consist of two sands, each about 200 feet thick, separated by a 15 foot shale layer. The pays are divided into an eastern gas prone province and a western oil prone province. A reservoir flow simulation model is planned to optimize production from existing wells and to facilitate future field development. Construction of an accurate model is complicated by MDT pressure measurements which indicated compartmentalization below the resolution of conventional seismic analysis, and by overlap of the seismic attributes derived from producing reservoirs, wet sands, and shales. To mitigate these factors, geostatistical inversion was chosen to produce the rock property inputs for the flow simulation models. This approach allowed development of a rock properties model consistent with core data, log data, and geologic constraints as well as seismic information. It also allowed assessment of uncertainty through the generation of a statistically significant number of internally consistent alternate solutions (realizations). A Markov Chain Monte Carlo method was employed to integrate borehole and geologic information to produce acoustic impedance and lithology volumes which were then used to co-simulate porosity, permeability, p-wave velocity, and water saturation volumes. Multiple realizations of these products were reviewed, uncertainty was assessed, and a rock properties model was selected for conversion to a flow simulation modeling format. The entire process can be rerun relatively quickly to accommodate additional wells and improved seismic data or to match production history.
- North America > United States > West Virginia > Mingo County (0.65)
- North America > United States > West Virginia > Logan County (0.65)
- North America > United States > Mississippi > Pike County (0.65)
- North America > United States > Gulf of Mexico > Central GOM (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.69)
- Geophysics > Seismic Surveying > Seismic Processing (0.68)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.65)
New API Practices for Isolating Potential Flow Zones During Drilling and Cementing Operations
Bannerman, M. (Chevron) | Calvert, J. (Consultant) | Griffin, T. (Griffin Cement Consulting LLC) | Levine, J. (MMS) | McCarroll, J. (MMS) | Postler, D. (Devon Energy Corp.) | Radford, A. (API) | Sweatman, R. (Halliburton)
Abstract This paper summarizes the progress by government and industryrepresentatives of the API Work Group on Annular Flow Prevention andRemediation in studying the causes and prevention of deepwater shallow waterflows (SWF) and annular flow incidents in other wells resulting in loss of wellcontrol linked to the well-cementing process. An overview is provided on twonew API recommended practice publications (RP-65 Parts 1 and 2) that describepreventive and controlling measures for SWF in deepwater wells and for any flowzone in almost any type of well. This includes key well planning, drilling, andcementing practices designed to help ensure isolation of potential flow zones.The paper also mentions plans to prepare Part 3 of RP-65 on prevention andremediation of sustained annular casing pressure during production. This paper introduces and promotes the use of best practices associated withprevention of annular flow incidents. It will also help inform the industry onpending regulations that may require the use of RP-65 in preparing Applicationsfor Permits to Drill (APD) and in drilling and cementing operations in areasregulated by the MMS (Minerals Management Service) of the U.S. Department ofthe Interior. The Work Group On August 16, 2000, the MMS (Minerals Management Service) presented safetyconcerns on uncontrolled annular flows to a new API work group includingmembers from or links to API Washington staff, the API Executive Committee onDrilling and Production Operations, API Subcommittee 10, ISO, IADC, DEA, DeepStar, the MMS, and other interested parties. Issues related to sustainedcasinghead pressure (SCP) in over 8,000 wells in the Gulf of Mexico wells werealso discussed. The MMS challenged the participants to prepare "best cementing practices" toimprove zonal isolation, reduce the occurrence of SCP, and help prevent annularflows during and after cementing. The MMS would then "consider" theincorporation of these documents into federal regulations as standardpractices. In later Work Group meetings, annular flow statistics were presentedincluding MMS records on the occurrence of SCP in Fig. 1 and on 34 LWC (loss ofwell control) incidents that occurred during drilling operations and reportedin the years 1992 through 2002. Of the 34 LWC incidents, 19 (56%) were causedby annular flows associated with the cementing process. Fig. 2 illustrates thehigh cost of losing well control, especially in offshore operations. The first charge to the Work Group was to prepare an API RecommendedPractice (RP) on a zone-isolation engineering process for prevention ofannular-flow events from deepwater shallow formations during and after primarycementing. In September 2002, this document was published as API RP-65 FirstEdition, titled "Cementing Shallow Water Flow Zones in Deep Water Wells."This is now called "Part 1" of a three-part series of RP-65 publications. The second charge was to prepare a second RP titled "Isolating PotentialFlow Zones in Well Drilling and Cementing Operations." This will be APIRP-65 "Part 2" on a zone-isolation engineering process that helps prevent well-control events during and after primary cementing caused by annular flows ofwater and hydrocarbons (primarily gas) from flow zones of any depth in offshoreshelf wells and from deeper formations in deepwater wells. The first draft ofthis RP is complete and in review as of this writing. The third charge was to prepare a third RP on a zone-isolation engineeringprocess to help prevent SCP from formations at any depth in all types of wells.A section on remediation of SCP will be included in this publication designatedas API RP-65 "Part 3."Work on this RP will begin mid-2005.
- Geology > Mineral (0.54)
- Geology > Geological Subdiscipline (0.47)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract A new phenolic resin system has been developed for proppant consolidation when fracturing low temperature wells. Before the development of this new resin system, which was in response to a global industry need, external chemical activators were necessary to achieve sufficient bond strength of the resin coated sand pack (when treating wells with bottom-hole temperatures less than 140°F). This new low-temperature cure system develops superior proppant pack bond strength and requires no external activation at temperatures as low as 100°F.Eliminating the need for external activators not only decreases the complexity of the fracturing treatment, but also contributes to the saving of time, money, and decreases the need for chemical transportation and the associated potential hazards.However, the lower operating temperature limit of this resin chemistry can be extended even further with the addition of an external chemical activator. The paper will discuss product performance data that was generated to document the effectiveness of this technology at simulated downhole conditions. Results from the initial field trials utilizing the new Low Temperature Resin Coated Curable Proppant (LTRCCP) in various shallow wells in the Permian Basin will also be presented. Field trial data resulted from thirty-nine treatments that were performed on a total of twenty-two wells, in nine different producing horizons, spread over four different fields in Southeast New Mexico and West Texas. The Information presented describes formation properties, treatment designs, post fracturing production response and lessons learned. Introduction Curable, phenolic resin coated proppants (RCPs) have been successfully used in the prevention of proppant flowback and prop pack rearrangement for more thantwenty-five years [1,2,3,4].Loss of fracture connectivity to the wellbore and the resultant loss of productivity is important in lower temperature applications as well as the more notable higher temperature applications [2,3,5].At lower temperatures (<140°F), various external chemical activators have been used for the last twenty years to help the resin coating develop higher grain-to-grain bond strength[1,2,6].However, in many field applications it is common practice to flow wells back immediately following the completion of the hydraulic fracturing operation.In this situation, external chemical activators can be run with curable RCPs even at temperatures up to 160ºF.Without the use of an external chemical activator, and depending on the proppant mesh size and thus the number of contact points, the useful and measurable proppant pack consolidation strength development of the conventional curable phenolic resin proppants in water at lower temperatures(<140°F) can take ½ to 5 days as the temperature approaches 100°F [1,6]. Alberta Province in Canada, the Permian Basin in West Texas/New Mexico, Alaska, and the Northeast U.S.A., along with Western Siberia in Russia are areas where large amounts of RCPs can be used at lower temperatures.The combination of shallow depths, and waterflooding or CO2 flooding of mature oil producing reservoirs, can provide challenges to develop the necessary RCP pack strength without the aid of an external chemical activator.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
Abstract Conventional oil and gas price forecasts typically include pessimistic, most-likely, and optimistic cases in an attempt to quantify economic uncertainty. An analysis of forecasts presented by industry and governmental organizations illustrates that conventional forecasting methods typically underestimate significantly the full range of uncertainty in oil and gas price forecasts. Economic indicators calculated using such forecasts will not reliably quantify investment risk. In this investigation we compared and contrasted several recently developed methods for quantifying upstream petroleum investment risk due to uncertainty in future prices. We analyzed five forecasting techniques - conventional, bootstrap, Inverted Hockey Stick (IHS), historical, and Sequential Gaussian Simulation (SGS). These techniques were applied to three synthetic projects and 23 industry projects to examine the uncertainty associated with economic indicators such as net present value, investment efficiency, and internal rate of return. Across all 26 projects, the conventional forecasts predicted a narrower range of economic indicator values than the four alternative methods, indicating that conventional methods routinely underestimate uncertainty. All four alternative forecasting techniques can provide operators with more reliable quantification of the uncertainty inherent in their investment decisions than provided by conventional methods currently in widespread use. The four alternative methods have unique strengths and weaknesses that may affect their applicability in particular situations. The SGS methods is the most rigorous and accurate method; however, it is also the most difficult to apply. The IHS method serves as a reasonable approximation, and can be easily incorporated into existing procedures and software. Introduction Investments in the petroleum industry are made under significant uncertainty. According to Capen[1], uncertainty is underestimated on an almost routine basis. Stermole and Stermole[2] note that uncertainty will be a factor "no matter how comprehensive or sophisticated an investment evaluation may be." Experts have stated that oil and gas producing assets are subject to three classes of uncertainty: technical, political, and economic.[3] Economic uncertainty affects investments within the petroleum industry at least as much as its technical counterpart.[4] Unlike technical uncertainty, which should decrease with production of a reservoir, economic uncertainty does not decrease over the life of a petroleum reservoir. Future oil and gas prices represent a substantial source of economic uncertainty for operators considering exploration and development opportunities. Wiggins[5] claims that price projections are as important as reserves determinations and production forecasts when evaluating hydrocarbon-producing properties. Campbell et al. [6] affirmed that errors in project valuations are more attributable to price forecasts than any other component. Although we cannot eliminate uncertainty from investment evaluations, we can better quantify the uncertainty by accurately predicting the volatility in future oil and gas prices. Reliably quantifying economic uncertainty will enable operators to make better decisions and allocate their capital with increased efficiency. Price projections within the petroleum industry are often comprised of pessimistic, most-likely, and high cases in an attempt to quantify uncertainty. Typically, these forecasts initially decline or remain flat for a period of time before increasing monotonically. Such price projections are referred to as "hockey stick" forecasts.[4] The California Energy Commission (CEC) published a natural gas price forecast beginning in 1997 that clearly illustrates the characteristic "hockey stick" shape commonly exhibited by conventional price forecasts (Fig. 1).[7] A segment of the CEC natural gas price forecast beginning in 2002[8] is shown in Fig. 2 along with actual gas price data realized by the market. The CEC forecast clearly underestimates the true range of product price uncertainty. A considerable portion of the actual gas price data falls outside of the high and low extremes presented in the forecast.
Abstract Conventional oil price forecasting methods in the petroleum industry typically consider uncertainty by incorporating optimistic, pessimistic, and most-likely cases. Commonly, these price projections are "hockey stick" forecasts, i.e., forecasts that are initially flat or decline for some period of time and then increase monotonically. Review of historical forecasts by industry and governmental organizations show that conventional forecasting methods often fail to capture the true uncertainty associated with oil and gas prices. Performing discounted cash flow calculations using conventional oil and gas price forecasts will therefore underestimate the uncertainty associated with project economic performance indicators. Akilu et al. developed the Inverted Hockey Stick (IHS) Method to address these shortcomings. This new method for quantifying the uncertainty of price forecasts honors the historical extremes of oil and gas prices (on a constant dollar basis) along with the maximum positive and negative historical rates of change. To investigate the uncertainty associated with economic indicators (e.g., net present value, investment efficiency, and internal rate of return), we applied the IHS method to 23 completed or proposed projects from 12 operators. We found the P50 IHS value for these economic indicators is comparable to the most-likely value from conventional price forecasts. Across all 23 cases, however, the IHS method predicted a wider range of economic indicator values than conventional forecasts. The IHS method may be preferable over conventional methods due to its ability to quantify more realistic upside and/or downside risk associated with projects in the upstream petroleum industry. Introduction Investments throughout the oil and gas industry are subject to considerable uncertainty. Capen[1] reports that uncertainty is difficult to quantify and that there is an almost universal tendency to underestimate it. Garb[2] identified three classes of uncertainty for hydrocarbon-producing properties: technical, political, and economic. Many experts believe that economic uncertainty affects oil and gas investments at least as much as uncertainties in reservoir and technical data.[3] Unlike technical uncertainty, however, economic uncertainty does not decrease over the life of a petroleum investment. While we may not be able to reduce economic uncertainty, we can make better investment decisions if we are able to quantify it. Conventional oil price forecasting methods traditionally attempt to address uncertainty by including optimistic, pessimistic, and most-likely cases. Commonly, these price projections are "hockey stick" forecasts. Hockey stick price forecasts are initially flat or decline for some period of time and then increase monotonically.[3] Fig. 1 shows a natural gas price forecast published by the California Energy Commission (CEC) in 1998 that illustrates clearly the characteristic "hockey stick" shape of conventional price forecasts.[4] Fig. 2 shows a later CEC natural gas price forecast, published in 2003, upon which subsequent actual gas price data are plotted.[5] The figure shows that a significant portion of the actual gas price data fell well outside the price range represented by the pessimistic and optimistic cases during the first two years of the forecast. Another example further indicates the industry's tendency to underestimate the uncertainty in price forecasts. In the widely used textbook, Project Economics & Decision Analysis, Mian[6] predicts "oil prices [will] remain in the range of $18 to $30 per barrel for another decade." Only two years after the publication of this text, during 2004, crude oil spot prices exceeded $56/bbl and closed the year at over $43/bbl. Caldwell and Heather[7] noted, tongue in cheek, that nearly all conventional price forecasts are "wrong 100% of the time" and "nobody believe[s] the forecast anyway." Despite these observations and perceptions, conventional price forecasts are still widely used throughout the industry. According to Brashear et al.,[8] return on net assets averaged less than 7% for both majors and independents during the 1980's and 1990's. The apparent failure to recognize the true uncertainty in economic forecasting may have been a cause for these relatively low returns on investments in the petroleum industry.
First Horizontal Well Opens New Gas Opportunities in the Sierra Chata Field, Neuquén Basin-Argentina
Sanz, C.A. (Devon Energy Corp.) | Nilson, G.J. (Devon Energy Corp.) | Acree, J.F. (Devon Energy Corp.) | del Pino, M. (Devon Energy Corp.) | Anaya, L. (B.J.Services)
Abstract The first horizontal re-entry gas well was successfully drilled and put online in the Sierra Chata field in the Neuquén basin in Argentina. This articlecompares the model forecast with the results obtained. The objectives were:to add gas reserves and to incorporate horizontal technology that willallow access thin or low permeability sands, in remote areas that would beeconomically marginal with vertical wells. Recent interpretation of 3-D seismic and geologic data indicated that the"D" Sands were better developed to the northwest of the vertical well SCh-17.In order to access gas reserves postulated to exist there, it was planned todrill a horizontal re-entry well utilizing the existing vertical well, SCh-17as a re-entry conduit. From the well SCh-17 a re-entry was made at 244 m fromthe deviation point (KOP) in 1600 m MD, drilling slightly up-dip to 2975 m MD, using with a downhole motor and a MWD logging system. Shale-silt lithologies within the sand members affect the verticaltransmissibility (TZ) between the "D" Sand members. Sensitivity runs were madeusing a reservoir simulator built to test the effect of such variables on thehorizontal well productivity. For the most probable case, an initial flowrateof 17.7 MMscfd (502 Mm3/d) was predicted. A final cumulative production of 7.3BSCF (206.7 MMm3) of gas was predicted by the numerical simulation model. Three years of production history confirmed the forecast and assumptionsmade in the well proposal and also encourage new horizontal prospects. Introduction The success obtained with horizontal wells in reservoirs with somesimilarities to the Mulichinco Sands, suggested the possibilityof applying horizontal well technology to the development of the Sierra Chatagas field. The Sierra Chata gas field occupies the southeast corner of theCNQ10 (Chihuidos) exploration block located in the Neuquén Basin, (see Figure1). The field is located on the flank of the Chihuidos anticline which isapproximately 100 km long by 50 km wide and is oriented in a NW-SE directionacross the exploration block bearing its name. It is estimated that the originof the structure dates back to the Jurassic with the last flexure havingoccurred in the Tertiary. Within the geographic column present in thesubsurface, the Mulichinco and Quintuco horizons have confirmed hydrocarbons, with only the former exhibiting commercial quantities to date. The Figure 2represents the stratigraphic column of the Neuquén Basin, including theMulichinco formation. Several companies have drilled numerous exploratory wellsin the area during the last twenty years. The interpretation of 2-D seismicidentified a characteristic response of reservoirs having good porosity, whichled to the drilling of the exploratory well SCh x-1 in 1993, and subsequentdiscovery of commercial quantities of natural gas at Sierra Chata .The SCh x-1 well produced with an initial flow rate of 22,605 MSCFD (640 Mm3/d)of dry gas with a 1,000 psig wellhead pressure (WHP). To date thirty verticaland one horizontal well have been drilled in Sierra Chata, including sixexploratory wells (two of which were unproductive).
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Rock Type (0.54)
- Geology > Geological Subdiscipline > Stratigraphy (0.54)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Sierra Chata Field (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Mulichinco Formation (0.99)
SPE Member Abstract Each month, governmental and industry publications discuss proposed and newly enacted environmental legislation. At first glance, the most difficult aspects of new environmental regulations are to understand and implement the requirements. In reality, these are secondary, compared to assuring that our field employees "buy in" to the requirements. Experience has proven to me that our responsibility as environmental managers includes, not only understanding the requirements, but "selling" them to our field employees. That means explaining the rationale for the law and ultimately asking our field employees for the best way to implement performance related requirements. Our field employees have the "hands on" experience to solve problems using the wisdom gained from years of field work. Once they are involved in the process, accountability for the results demanded by government is more easily achieved. Here is an example of what I mean. Texas Railroad Commission Rule 91 requires cleanup to 1 % TPH within one year of an oil spill. Prior to Rule 91 becoming law, we explained the proposed requirements and their rationale to our Texas field employees. They assisted us with our comments on the proposal. When Rule 91 was enacted in November 1993, our field employees were already aware of the requirements and enthusiastic about trying various amendments to remediate oil spills. In other words, we had involved the people most closely affected by the law, in the legislative process. Not all field employees have bought into this process, but more and more are coming on board every day. At times, we may become frustrated with the process, but the results are well worth the effort. Introduction Each month I get approximately two dozen environmentally related publications, all generally saying that there are newly proposed or enacted regulations which are difficult to understand and, more important, expensive to implement. P. 163
- Law (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.35)