Industry Papers

 
Publication: Denver International Petroleum Society Talk, May 9, 2014
Publisher: Denver International Petroleum Society
Published: 2014

Abstract:
Mongolia contains several large under-explored sedimentary basins. These basins are geologically similar to highly productive basins in China. Current production is from Lower Cretaceous sediments located in lacustrine rift basins in eastern Mongolia. These basins are filled with continental sediments and volcanics which can reach 3- 4 km in thickness. Rifting and subsequent basin inversion has resulted in complex basin geometry. Sub basins within the larger basin areas are actively being defined by land based gravity and magnetic surveys, and are confirmed by 2D seismic. Depositional environments for petroleum reservoirs encountered in the lacustrine sub basins vary from alluvial fans, fluvial, delta and deep lake fans and turbidites. Published literature of the reservoir stratigraphy and surface exposures of the Cretaceous are limited. Numerous unconformities within the prospective section have been inferred based on seismic interpretation, with both structural and stratigraphic traps. Sub basins are self-sourced by lacustrine shales within the sub basins, and migration of the petroleum appears to have been limited to within the sub basin. There is a general lack of data in these sub basins and as a result the petroleum system is not well understood. This talk addresses the current status of exploration in Mongolia.
Publication: Denver International Petroleum Society, September, 2013.
Publisher: Denver International Petroleum Society, September, 2013.
Published: 2013

Abstract:
Abstract not available.
Publication: Unconventional Resources Technology Conference, 12-14 August 2013, Denver, Colorado, USA
Publisher: Society of Petroleum Engineers
Paper Number: SPE 168809-MS
Published: 2013

Abstract:
Greenpark Energy, now Dart Energy International, acquired the 74,130 acre (300 km2) Petroleum Exploration and Development License (PEDL) 159 on the border of England and Scotland in 2006 to test for potential coal bed methane prospectivity. While there were no coal mines in the PEDL area, there were 32 borehole penetrations of the Carboniferous Middle Coal Measures, with 14 of the boreholes being cored by the British Coal Board for testing. Based on original subsurface borehole and 2D seismic mapping, 6 seams of coal were mapped over an 18,530 acre (75 km2) area. The Six Foot, Nine Foot, Three Foot, Five Foot, Black Top and Seven Foot Seams are regionally correlatable and lay between 660 feet and 4590 feet beneath the surface. Each seam ranges from just under 3 feet to over 6 feet in gross thickness. Net coal ranges from zero at the unconformity truncation to over 66 feet. Using original gas content data, (265,106 m3) 935BCF of OGIIP was calculated as a potential resource target. Greenpark Energy drilled three test coring wells at structurally shallow, moderate and deeper depths within the PEDL and analyzed the cores for gas content and saturation. Additional permeability testing was done, using various techniques, at each of these wells. A further exploration well was drilled to define the limits of the basin and a site was selected for pilot production test wells. Two horizontal wells were drilled in-seam and put on extended production tests. As a result of the coring and testing appraisal program, Contingent Resources were certified within PEDL 159. With production tests, supported by numerical simulation models, a portion of the Contingent Resources were high-graded to Reserves. By using a managed testing program and the PRMS, costs were contained and sufficient Resources were able to be upgraded to Reserves to advance the field toward a commercial decision point.
Publication: Unconventional Resources Technology Conference, 12-14 August, Denver, Colorado, USA
Publisher: Society of Petroleum Engineers
Paper Number: SPE 168676-MS
Published: 2013

Abstract:
This paper presents an evaluation of producing Bakken horizontal wells in Williams County, North Dakota. In recent years, Williams County has experienced greater horizontal well drilling activity. That fact, coupled with the continuing advancement in drilling and completion techniques, made this area the focus of many operators. As of mid-2012, there were 730 wells producing out of the Bakken Formation in Williams County, with the majority of wells drilled on 1280-acre drilling and spacing units ("DSU??). This study provides a comprehensive analysis of the projected ultimate recovery per well using decline curve analysis for horizontal wells in the Bakken formation. Only wells with sufficient historical production data to confidently determine an initial decline trend were forecast. These wells show strong hyperbolic behavior, with a steep initial decline in oil production rate. The projections of ultimate recovery generated using decline curve analysis were supported by numerical simulation models. The results of the evaluation demonstrate that the initial oil production rates and the ultimate recovery of horizontal Bakken wells in Williams County are a function of both production strategy and completion technique. In addition, it is shown that certain operators consistently achieve superior results as compared to other operators in the same area. Lastly, using numerical simulation models, the impact of well density within the DSUs on the projected well performance is presented.
Publication: SPE Unconventional Resources Conference and Exhibition-Asia Pacific, 11-13 November 2013, Brisbane, Australia
Publisher: Society of Petroleum Engineers
Paper Number: SPE 167011-MS
Published: 2013

Abstract:
Horizontal well development targeting the Niobrara formation in the Denver-Julesburg (DJ) Basin in Colorado and Wyoming is gaining development momentum as the price of gas in the US has fallen and liquid rich plays have come into high demand. The low permeability Cretaceous age Niobrara formation is commonly encountered as three benches of naturally fractured limestones, marls and calcareous shale. The advent of horizontal drilling has allowed exploitation of this previously overlooked target in the DJ Basin. Thermal maturity varies across the DJ basin, resulting in a variety of reservoir fluids in the Niobrara including dry gas (biogenic and thermogenic), wet gas, condensate, and oil. Two of the main oil fields in the DJ Basin are the Silo field, in Laramie County Wyoming, and the Wattenburg field, which is predominantly in Weld County, Colorado. Oil has been produced out of the DJ Basin since 1901, however successful horizontal well development is still relatively recent in both fields. With the increased interest in Niobrara development, rate-decline analysis is used extensively by operators to estimate reserves and to evaluate potential locations for future drilling. Various published models are available for rate-decline analysis. Arps rate-decline relationship has been the most widely used model, however subsequent authors have developed models modifying Arps, or in the case of unconventional and naturally fractured formations, developed completely new models, like Duong, for rate-decline analysis. This paper will utilize production data for wells in Wattenburg and Silo fields to assess how appropriate different models are for rate-decline analysis in the naturally fractured Niobrara Formation.
Publication: presented at the Unconventional Resources Technology Conference held in Denver, Colorado USA, 12-14 August 2013.
Publisher: Society of Petroleum Engineers
Paper Number: URTeC 1575791; SPE-168704-MS
Published: 2013

Abstract:
The USGS has estimated the known Coalbed Methane (CBM) gas resource base in the US to be over 700 TCF. In 2007, nine percent of the U.S. gas production was from CBM and nine percent of the U.S. Proved dry gas reserves were CBM. Typically, CBM is a low-risk, yet economically low-margin resource play. Much is known regarding the location and amount of coal present, thus making dry holes virtually non-existent. In many basins, CBM can be found unexploited at very shallow depths and because methane is stored in coal by a different means than conventional gas, more gas per unit volume can be recovered at these shallow depths. The two greatest economic factors in CBM production are time to dewater (time to get peak gas production) and gas peak rate. The time to dewater the reservoir, which is defined as depleting reservoir pressure below gas desorption pressure, is a function of cumulative water produced. Many CBM pilots fail due to lack of understanding of water influx which, from a material balance prospective, offsets water withdrawn (produced), resulting in the inability to reach peak gas rates. The purpose of this paper is to develop a model to evaluate water encroachment, which in turn works against dewatering efforts. Modeling would then assess the cumulative water produced to reduce reservoir pressure to achieve gas desorption, resulting in gas production. The means to achieve this objective is to utilize the classic reservoir engineering method derived by Havlena and Odeh. This paper derives the afore mentioned method for CBM reservoirs and then test the method against field data gathered in a CBM pilot project located in the Illinois Basin.
Publication: AAPG International Meeting – Singapore, 2012
Publisher: American Association of Petroleum Geologists
Published: 2012

Abstract:
Oral Abstract
Publication: The Journal of the Society of Petroleum Evaluation Engineers, Vol. VI, Issue 1, Spring 2012. pp 7-14.
Publisher: Society of Petroleum Evaluation Engineers
Published: 2012

Abstract:
Abstract not available.
Publication: AAPG GTW – Singapore, March 16, 2011
Publisher: American Association of Petroleum Geologists
Published: 2011

Abstract:
Abstract not available.
Publication: Book
Publisher: PennWell Books
Published: 2011

Abstract:
Author John Seidle has written this much-needed introduction to a unique unconventional gas resource for students and practicing engineers as well as a basic handbook for those who are involved in coalbed methane on a daily basis and require straightforward, practical answers in the fast-paced business world.
Publication: SPE London Section Presentation, 2010
Publisher: Society of Petroleum Engineers
Published: 2010

Abstract:
Abstract not available.
Publication: Canadian Unconventional Resources and International Petroleum Conference, 19-21 October, Calgary, Alberta, Canada
Publisher: Society of Petroleum Engineers
Paper Number: SPE 137651-MS
Published: 2010

Abstract:
Arrow Energy intends to develop its certified coal seam gas reserves in the Surat Basin to supply gas to a proposed liquefied natural gas (LNG) plant located in Gladstone, Queensland. The large scale development of the Surat Basin for the LNG Project required basin-wide geological modeling. The Surat Basin coal structure and properties were reviewed in detail and modeled to estimate Gas Initially in Place. Dynamic simulation was subsequently performed to estimate total recoverable volume and generate a robust development plan for the LNG Project. Key subsurface risks consist of access to sufficient gas volumes within the area of interest and gas deliverability to meet and maintain gas supply to the LNG Project. To minimise the likelihood, and to reduce the consequences of these risks, subsurface uncertainties were identified and low and high values for each uncertainty were assessed with the aim to understand impacts on the LNG Project. Gas content, permeability and Net to Gross resulted in the biggest impact on the LNG Project, followed by relative permeability curves, coal heterogeneity, isotherms, permeability variation with pressure, coal compressibility and potential aquifer connection. Other uncertainties, including coal depth cut-off, sorption time and initial reservoir pressure had a lower impact on the number of wells required for the LNG Project. Subsurface sensitivity analysis combined with probabilistics was used to generate 90%, 50% and 10% probability subsurface models. These were carried forward for development planning to generate a range of development outcomes and production forecasts for economic evaluation to ensure a robust LNG field development plan. This paper describes the integrated reservoir data analysis and dynamic modeling methodology for the purpose of the large-scale development of this Surat Basin opportunity and outlines how key uncertainties were identified and addressed.
Publication: Presentation to the Geological Society of South Africa Western Cape Branch, November 11, 2009
Publisher: Geological Society of South Africa
Published: 2009

Abstract:
Abstract not available.
Publication: 11th SAGA Biennial Technical Meeting 2009, pp 576-581.; 2008 AAPG International Convention in Cape Town South Africa Presentations, October 2008
Publisher: American Association of Petroleum Geologists
Published: 2009

Abstract:
We have analysed several hundreds of km of 2D seismic reflection profiles and ten wells, in an area of about 18750 km2 corresponding to the exploration Block 2 of the Orange Basin, located offshore the South African continental margin. Our main goals are: (1) to characterize the different natural gas leakage features present on the basin, (2) to understand their relationship with structural and stratigraphic elements, and (3) to quantify the liquid/gas hydrocarbon generation, migration and seepage dynamics through the post-rift history of the basin. The seismic data reveals the existence of seven major seismic units separated by conspicuous stratigraphic unconformities. The Cretaceous mega-sequence is composed of five major seismic units: C1- Barremian to Aptian, C2-Early Aptian to Cenomanian, C3-Turonian to Coniacian, C4-Santpnian, C5-Campanian to Maastrichtian and the Tertiary is subdivided into two sequences: T1- Lower Tertiary, and Unit T2-Upper Tertiary. An extensional domain, characterized by basinward dipping listric faults rooted at an Aptian decollement level, have been identified between 500 to 1500 m of present-day bathymetry. A compressional domain, which accommodates the up-dip extension, is observed on the lower slope and is characterised by landward dipping faults and thrusting. Based on their origin, the observed gas chimneys have been classified into two main categories: stratigraphically controlled and structurally controlled. The structural chimneys are mainly located upwards the normal faults on the extensional domain, whereas the stratigraphically-controlled ones are linked to the presence of onlaps and pinch-out within the Aptian sequence. No gas leakage features were identified on the contractional domain. In addition, some "giant" chimneys, with diameter of more than 7 km, were also identified although their origin is still a matter of study as the seismic record is not deep enough to identify the feeder system. Future numerical modeling of two major transects across these features should provide insights on the timing and amount of gas generation, migration and sequestration dynamics, as well as the nature of their feeding source.
Publication: Lecture given at SPE Southern Africa Chapter Meeting, January 25th, 2008
Publisher: Society of Petroleum Engineers
Published: 2008

Abstract:
abstract not available.
Publication: 2008 AAPG International Convention in Cape Town South Africa Presentations, October 2008
Publisher: American Association of Petroleum Geologists
Published: 2008

Abstract:
Today, as the world intensifies its search for hydrocarbons at a time that the industry is experience severe staff shortages there is an increasing need for companies to educate both management and staff on proper reserve auditing methods. While guidelines become every more detailed due to advances in technology, companies often find the fundamental skills needed lacking. At the same time different methodologies compete to become the industry standard for certifying reserves and resources. By examining a few basic issues and real life cases we contrast the two dominant standards and draw lessons for executives and staff alike.
Publication: 2008 AAPG International Convention in Cape Town South Africa Presentations, October 2008
Publisher: American Association of Petroleum Geologists
Published: 2008

Abstract:
The Middle Albian 14A siliclastic sequence in the Bredasdorp Basin of South Africa has been penetrated by over 150 wells and has been recognized as a commercial target since oil was discovered in the E-AA1 borehole in 1986. During 1988, a detailed sequence stratigraphic study of the Bredasdorp Basin was carried out under the auspices of the University of Texas at Austin. This has, since then, resulted directly in a number of geological models being proposed. The 14A 3rd Order depositional sequence has been variously characterized as a) base of slope slumps; b) Low angle lowstand progradational incised channels; c) massflow deep marine sheet sandstones; and d) retrogradational confined flow deposits. Using extensive core, log and 2D and 3D seismic data we document the variable nature of the 14At1 sequence boundary and the nature of the deposition on the unconformity from the eastern shelf, across the slope and into the abyssal plain of the Bredasdorp Basin. Across the transect we document extensive erosive channels and bypass zones, base of slope deposits, intermediate and distal fan deposits and the changing nature of both the well log and seismic character of the sequence boundary.
Publication: 2008 AAPG International Convention in Cape Town South Africa Presentations, October 2008
Publisher: American Association of Petroleum Geologists
Published: 2008

Abstract:
The offshore passive margin Orange Basin, extends from the Luderitz Arch in Namibia, to the Agulhas Fracture Zone. It covers an area of about 250 000km2 with the focus of this study being the Albian Orange River depocentre about 200km south of the Namibian border, offshore South Africa. During the Albian, marine and deltaic conditions were dominant, depositing reservoir quality incised fluvial channel sandstones between second-order unconformities, 14At1 (103Ma) and 15At1 (93Ma)*. At the beginning of this 3rd order super sequence cycle, the principal drainage system suddenly shifted about 300km towards the north. This caused the Orange deltaic system to prograde generally westwards under increasing sediment supply and accommodation rates, developing a depocentre near the mouth of the Albian Orange River. The Albian distributary meandering channels were deposited on the lower to middle shoreface of a delta front, and form the reservoir of the Albian stratigraphic-structural play. This is currently the most significant play in the South African part of the Orange Basin and includes the Ibhubesi gas field. Sandstones in this gas field show good porosity-permeability qualities and extremely good flow rates (30+ MMcfgpd) for relatively thin (10 - 20m) sandstone reservoirs. The objective of the poster is to show the individual channel complexes mapped from 2D and 3D seismic data, making use of the characteristic trough over peak amplitude anomalies that correspond to porous sandstones. Incorporating this data with borehole and regional data an analogue is made to present-day river systems. Building a geological model of the channel fairways, and incorporating all seismic, regional and well data gives a good overview of the most prospective areas for continued gas exploration in this play.
Publication: 28th Oil Shale Symposium, October, 2008.
Publisher: Colorado School of Mines
Published: 2008

Abstract:
The Uinta and Piceance Basins of Utah and Colorado contain, within the Tertiary age Green River Formation, an estimated 1.5 trillion barrels of kerogen oil in the form of oil shale. The surface retorting of oil shale produces a significant amount of carbon dioxide (CO2). SI International conducted preliminary investigations that characterize and assess the viability of geologic sequestration of the CO2, in the Uinta and Piceance Basins, with emphasis on the White River Mine area of Uinta Basin. SI International has compiled a large database from existing well data covering approximately 23,000 wells in the Uinta and Piceance Basins. From these data, SI had prepared a suite of maps that identify basin-wide geologic formations most suitable for CO2 sequestration. A particular are of interest in proximity to an anticipated oil shale mining and retort site on public lands has been chosen here to demonstrate the mapping and reservoir characterization needed to develop a working geologic model. This work is offered as a guide for application to other geologic formations for future geosequestration projects relating to oil shale development and other CO2 emitting industries such as thermoelectric power plants, refineries, etc. in the Uinta and Piceance Basins.
Publication: Presented at the 2008 annual SPEE meeting and at the 2008 COGA-RMAG meeting.
Publisher: Society of Petroleum Evaluation Engineers; Colorado Association of Oil and Gas; Rocky Mountain Association of Geologists
Published: 2008

Abstract:
Abstract not available.
Publication: U.S. Geological Survey Open-File Report 2007-1297.
Publisher: United States Geological Survey
Published: 2007

Abstract:
This report describes an accompanying database of geoscientific references for the country of Afghanistan. Included is an accompanying Microsoft® Access 2003 database of geoscientific references for the country of Afghanistan. The reference compilation is part of a larger joint study of Afghanistan's energy, mineral, and water resources, and geologic hazards, currently underway by the U.S. Geological Survey, the British Geological Survey, and the Afghanistan Geological Survey. The database includes both published (n = 2,462) and unpublished (n = 174) references compiled through September, 2007. The references comprise two separate tables in the Access database. The reference database includes a user-friendly, keyword-searchable, interface and only minimum knowledge of the use of Microsoft® Access is required.
Publication: presented at the 2007 International Petroleum Technology Conference, Dubai, U.A.E., 4-6 December 2007.
Publisher: Society of Petroleum Engineers
Paper Number: IPTC 11333-MS
Published: 2007

Abstract:
The San Juan basin Fruitland coalbed methane (CBM) resource is the most significant CBM play discovered in the world to date and comprises areas within both Colorado and New Mexico of the United States. It contains three distinctly different performance areas within the 6,800 mile2 (17,600 km2) enclosed by the Fruitland outcrop. Two of these areas are considered in this topic: "Fairway?? and "Colorado Type II??. Explaining well performance in these areas has required the examination of a mechanism whereby coal permeability increases over time. Field data and pressure transient analysis (PTA) for Fairway wells have revealed that coal permeability does increase over time and is an exponential function of reservoir pressure depletion. While evidence for pressure dependent permeability in CBM reservoirs has been presented in the literature before, this work seeks to compare the magnitude and functional form in two different reservoir units. In the high productivity Fairway, well data monitored and gathered by a Supervisory Control & Data Acquisition (SCADA) system, including data from two non-producing pressure observation wells, reveal a representative area of the Fairway to exhibit an exponential increase in permeability with respect to reservoir pressure depletion. Time-lapse PTA confirm this phenomenon exists in the lower productivity Type II area as well. Significantly, the Type II area is one of continued, active development via infill drilling. A regulatory requirement of this infill program is that operators measure reservoir pressure in the infill wells drilled after July, 2000 at a prescribed frequency. While the SCADA system also monitors wells in the Type II area, there are no suitable pressure observation wells there. Further, the permeability in the Type II region tends to be significantly lower than in the Fairway. As a consequence, an offset pressure monitor well would tend not to be representative of average reservoir pressure in the drainage area of a Type II producing well. This precludes the Fairway approach and requires a time-lapse PTA approach. While the rate of change of permeability with respect to reservoir pressure appears to be of exponential functional form in the Fairway, until recently it could be demonstrated only that the permeability increased with respect to reservoir pressure in the Type II area of the field. Insufficient testing precluded any claims as to the functional form. In the Type II area, second quarter 2007 pressure transient testing on each of ten wells drilled circa 2000-02 have provided a third data point of permeability vs. reservoir pressure. For these ten wells, one can begin to claim the rate of increase is exponential - as in the high capacity Fairway region of the basin. Over time, many other Type II infill wells will be tested to confirm more conclusively the functional form of permeability with respect to reservoir pressure. This will be of interest with respect to greater data density as well as with respect to obtaining data at ever lower reservoir pressures.
Publication: Presented at the 2007 SPE Rocky Mountain Oil & Gas Technology Symposium, Denver, Colorado, U. S. A. 16-18 April 2007.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 107731-MS
Published: 2007

Abstract:
Many coal deposits throughout the world are undersaturated to some degree. With actual gas contents less than expected from reservoir pressure and the sorption isotherm, these coals require dewatering before gas desorbs. An operator must bear water production and disposal costs, frequently for an extended period of time, prior to realizing any revenue from gas sales. Gas and water profiles for wells completed in Powder River and Greater Green River coals were simulated assuming saturated coals and selected degrees of undersaturation. Base case economics were constructed by combining the simulated gas and water profiles from saturated coals with typical capital costs and well operating expenses for each basin. Gas and water profiles from simulation of ever deeper undersaturation were used to drive additional economic analyses. From this suite of economic analyses, the impact of undersaturation on economic parameters such as net present value, time to payout, and breakeven gas price was assessed.
Publication: presented at the 2007 SPE Rocky Mountain Oil & Gas Technology Symposium, Denver, Colorado, U. S. A. 16-18 April 2007.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 107705-MS
Published: 2007

Abstract:
Recent advances in production data analysis (PDA) techniques have greatly assisted engineers in extracting meaningful reservoir and stimulation information from well production and flowing pressure data. Application of these techniques to coalbed methane (CBM) reservoirs requires that the unique coal storage and transport properties be accounted for. In recent work, the authors and others have demonstrated how new techniques such as the flowing material balance (FMB) and production type-curves may be adapted to account for CBM storage mechanisms (i.e. adsorption), but to date the focus has been on relatively simple CBM reservoir behavior. Although adaptations of PDA to include more complex CBM reservoir characteristics were introduced, the focus of the current work is advancement of modern PDA techniques to incorporate reservoir behavior such as single-phase flow of water in undersaturated reservoirs, two-phase (gas+water) flow in saturated reservoirs, effective permeability changes during depletion, and changing gas composition due to relative adsorption. Specifically, the FMB technique is modified in this work to include several complex CBM reservoir characteristics. FMB can be a powerful diagnostic technique when relative and absolute permeability changes are apparent during depletion. Several synthetic and field examples are given to demonstrate how FMB, type-curve analysis and analytical simulation can be used in parallel to provide a particularly useful data analysis tool. The adapted PDA techniques used in this work make use of the pseudotime and pseudopressure concepts, modified to account for CBM reservoir behavior, to linearize the (constant-rate) diffusivity equation for CBM. Material balance pseudotime was used to account for variable operating conditions. These techniques were used successfully to extract quantitative reservoir information from single- and two-phase CBM simulated and field production and pressure data. The techniques for two-phase CBM require further evaluation, however. Several key assumptions were used in deriving the PDA techniques including (but not limited to) instantaneous desorption (small sorption times) and single-layer behavior. Although the former is not considered a serious limitation, as most commercial reservoirs analyzed to date by the authors have exhibited single-porosity behavior during production, the latter may be quite important for some producing fields. PDA of multi-layered CBM reservoirs will be discussed at length in a future paper.
Publication: U.S. Geological Survey Open-File Report 2006-1370.
Publisher: United States Geological Survey
Published: 2006

Abstract:
This report describes an accompanying database of geoscientific references for the country of Afghanistan. The reference compilation is part of a larger joint study of Afghanistan’s energy, mineral, and water resources, and geologic hazards, currently underway by the U.S. Geological Survey, the British Geological Survey, and the Afghanistan Geological Survey. The compilation of geoscientific references was initially planned to contain only mineral-resource-related references. However, the effort soon grew to encompass references related to water resources, energy resources, and geologic hazards. It is emphasized that this is an on-going work in progress and that the present database is incomplete. A second version of the reference database is planned for future release, and will include all geology-oriented references of Afghanistan.
Publication: Presented at the Gas Technology Symposium, Calgary, Alberta, 15-17 May, 2006.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 100313-MS
Published: 2006

Abstract:
Coalbed methane (CBM) reservoirs commonly exhibit two-phase flow (gas+water) characteristics, however commercial CBM production is also possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan Basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed using traditional techniques commonly used for conventional reservoirs.  Complicating application, however, is the complex nature of coal reservoirs; coal gas storage and transport mechanisms differ substantially from conventional reservoirs. In addition, single-phase coal reservoirs may display multi-layer characteristics, dual porosity behavior, permeability anisotropy etc. The current work illustrates how traditional single-well analysis techniques, such as type-curve and pressure transient analysis, may be altered to analyze single-phase (un-stimulated and hydraulically-fractured) CBM wells. Examples of how reservoir inputs to the type-curves and subsequent calculations are modified to account for CBM reservoir behavior are given. This paper demonstrates, using simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from production data analysis of coal reservoirs only if appropriate reservoir inputs (i.e. desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve and pressure-transient analysis methods for production data analysis are not used in isolation for reservoir property estimation, but rather as a starting point for single- and multi-well reservoir simulation, which is then used to history-match and forecast coal well production (ex. reserves assignment). Coal reservoirs have the potential for permeability anisotropy because of their naturally-fractured nature, which may complicate production data analysis. To study the effects of permeability anisotropy upon production, a 2-D, single-phase, numerical CBM reservoir simulator was constructed to simulate single-well production assuming various permeability anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics. Multi-layer reservoir characteristics may also be observed with coal reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve and pressure transient analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multi-layer CBM (+sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multi-layer) production in the simple 2-layer case.
Publication: AAPG Bulletin, Vol. 88 (2004), No.13. (Supplement), AAPG International Conference, Cancun, Mexico, Abstract. October 24-27, 2004.
Publisher: American Association of Petroleum Geologists
Published: 2004

Abstract:
2001, Discovery of Gas on the West Coast--2001, Discovery of Gas on the West Coast. The Partnership led by Forest Oil as operators in the area of the Orange River Basin finished a drilling campaign in 2001 having drilled 4 exploration wells resulting in the discovery of what has been designated as the Ibhubesi Field, located in 220 m. water depth 70 kms, from shore and 300 kms. from any market. By various estimates the field reserves are just less than 1 Tcf of gas in 3 stratigraphic traps. 2003, PetroSA Involvement. In 2003 PetroSA joined the partnership with at 24% interest in the Ibhubesi project, paying 31 M$ for this interest. These funds are to be used entirely and only to find additional reserves to prove field commerciality. In the 2003 drilling campaign based on a new AK03 3D survey, 4 to 6 wells will be drilled expected to add 2 Tcfg to total field reserves. 2006 and Beyond - The full project development will require 380M$ and generate positive cash flow in 2010. Production begins in 2006 and peaks in 2008 at 77 Bcfg/y generating 200M$/y gross revenue. Development components include Subsea completions, pipelines and compression
Publication: AAPG Annual Convention, Oral Abstract. 2003.
Publisher: American Association of Petroleum Geologists
Published: 2003

Abstract:
New geochemical data from four shelf wells indicate the presence of Cenomanian and Turonian, marine, oil-prone source rocks in the Orange River Basin, R. S. A. The petroleum system related to these source rocks is distinct and separate from the previously recognized Aptian petroleum system that sourced the gas produced from fluvial reservoirs on the shelf. Paleo-climate models for Cenomanian-Turonian time suggest the onset of upwelling near the shelf/slope in this region, and the presence of organically enriched marine strata may be related to these upwelling systems. Preliminary 1-D hydrocarbon generation models suggest that in waters depths greater than about 1000 m, Cenomanian- Turonian sediments may still be in the oil window. Oil generated from the Cenomanian-Turonian would therefore have been available for migration up dip along carrier beds into deep-water, basin-floor fan reservoirs. Possible reservoir facies in this newly identified petroleum system include amalgamated fan channel systems with marine shales as the seals. Traps for the hydrocarbons were formed when reservoir intervals were involved in shelf-edge collapse during the Coniacian through Santonian. Rotational structures related to this collapse are large: one structure imaged on new 3-D data has over 145 km2 of areal closure with over 750 m of vertical relief. Additionally, there are other structures of similar magnitude as the play extends along strike to the north with a series of trapping structures and overlapping fan lobes.
Publication: SPE Annual Technical Conference and Exhibition, 5-8 October, Denver, Colorado, 2003
Publisher: Society of Petroleum Engineers
Paper Number: SPE 84424-MS
Published: 2003

Abstract:
It wasn't always this complicated! In 1990, Seidle and Arri1 demonstrated how to easily adapt a conventional black oil simulation model for use in coalbed methane simulation. These days, when setting up a coalbed methane simulation model, one needs to worry about a single or multi-component gas description; depletion or enhanced coal bed methane recovery; single, dual or triple porosity; vertical, horizontal, or multi-lateral wells; coals only or a mix of coals and sands; and coalbed methane or coalmine methane? Correctly determining what to model is almost as daunting a task as the simulation work itself. All of these variations add complexity to the task and, in some cases, require specialized simulation models to adequately characterize the problem. This paper discusses how the exploitation and development of coalbed resources throughout the world is changing, and with it how our approach to reservoir simulation of the process is changing as well. The paper will provide a valuable resource to engineers and geoscientists faced with developing predictive tools to assist them in evaluating the optimum strategy to exploit these valuable resources.
Publication: SPE Annual Technical Conference and Exhibition, 5-8 October, Denver, Colorado, 2003
Publisher: Society of Petroleum Engineers
Paper Number: SPE 84428-MS
Published: 2003

Abstract:
Just over ten years ago, coal bed methane production from Wyoming's Powder River Basin was virtually non-existent. Today, total gas production from Powder River Basin coals is almost 1 Bcf per day from nearly 10,000 wells. This tremendous resource is unique compared to other commercial coalbed methane plays with gas content an order of magnitude lower, and reservoir permeability values several orders of magnitude higher than other producing coal bed plays. This paper documents the results of an ongoing evaluation of the reservoir and production characteristics of the Wyodak coals located in the fairway of the Powder River Basin activity. Most of the drilling and production to date has focused on the Wyodak and equivalent coal horizons. A reservoir simulation model has been constructed covering 136 sections and including over 1300 wells. A detailed geological description and a large data base of core data and test results were used in the construction of the model. Historical gas production, water production, and reservoir pressure data were successfully matched from 1993 to the present during the calibration of the simulation model. The calibrated model was then used to evaluate optimum development strategies for this shallow, high permeability coal resource. This paper discusses the production characteristics of the Wyodak coal, the impact of well spacing and well timing on the recovery factor, and the influence of outside factors such as recharge from the regional aquifer. Our results contradict conclusions reported in prior studies concerning the influx of water from adjacent sand horizons. In addition, the effects of multiple well interference and depletion of undrilled portions of the coal by existing wells are documented and discussed.
Publication: Presented at the SPE Hydrocarbon Economics and Evaluation Symposium, Dallas Texas, 5-8 April, 2003.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 82024-MS
Published: 2003

Abstract:
Unconventional gas plays are often risky. To help understand the uncertainty inherent in these plays, probabilistic estimated ultimate recoveries (EUR's) can be employed. Once sufficient production data are available for a given play, production based probabilistic EUR's can be constructed. Meaningful economics require introduction of a time component to such probabilistic EUR's. This study does so in two ways. First, detailed production data are used to construct probabilistic distributions for annual gas volumes. Secondly, probabilistic gas price distributions are constructed from pertinent histories. Distributions of gas volumes and prices are then coupled in Monte Carlo simulations to generate probabilistic economics. Examples are presented using production data from Raton coal gas and the Whiskey Buttes (Frontier Formation, low permeability gas field) in conjunction with Henry Hub and CIG price distributions.
Publication: Presented at the SPE Gas Technology Sypmosium, Calgary, Alberta, Canada, 30 April-2 May 2002.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 75519-MS
Published: 2002

Abstract:
Although early gas and water production rates from a coal well are often erratic, at late time these wells typically exhibit gentle declines in both gas and water. A literature review indicated time transfoms for conventional gas well decline analysis may or may not be applicable as coal wells often show exponential declines when plotted in real time. A theoretical gas decline coefficient was derived from the pressure-squared form of Darcy's Law and the Z* formulation of the mass balance equation. Conditions necessary for exponential decline are discussed. A theoretical water decline coefficient was developed by coupling a water mass balance equation with an expression for Estimated Ultimate Recovery. Calculated decline coefficients are compared with reported and simulated declines in the Warrior, Powder River, and San Juan basins. Reasons for differences, as well as agreements, between theoretical and actual decline coefficients and drainage areas are discussed. Practical applications of these results include prediction of the gas decline coefficient from coalbed parameters, calculation of drainage area from water decline behavior, and estimation of total water volumes to be disposed.
Publication: In Coalbed Methane of North America II, Schwochow and Nuncio, eds.
Publisher: Rocky Mountain Association of Geologists
Published: 2002

Abstract:
Coal gas plays usually progress from rank wildcat wells, through multi-well pilot stage, then sometimes on to commercial production. Coalbed methane plays differ from conventional gas plays in that the time consuming and costly middle step of pilot testing is crucial to determination of commercial viability. Consequently, pilot tests have been conducted in several U.S. coal basins over the past 30 years. To increase pilot interpretability and reduce time and cost of future pilots, a review of past pilot tests in selected coal basins is presented. Pilot parameters such as the number of wells, well spacing, completions, and production life as well as characteristics of the target coal deposits are considered. The definition of dimensionless time from conventional gas reservoir engineering led to an equation for the minimum production time required for a given pilot to experience interference.
Publication: SAGA 6th Biennial Conference and Exhibition, 28th September – 1st October 1999, paper 15.3
Publisher: South African Geophysical Association
Published: 2000

Abstract:
Africa has three aerially extensive, thick, deltaic systems on it’s West coast. Of these the Congo and Niger Deltas have major commercial hydrocarbon resources. The Orange River delta is less-explored but has already had gas and oil discoveries that indicate it’s potential. These discoveries indicate that at least 3 hydrocarbon systems exist in the area; in graben deposits of the early rift succession. e.g. AJ-1 well (oil), Kudu-type late rift (gas) and in the Albian-Aptian drift succession (gas). The deepwater portion of the delta has yet to be drilled so its potential is yet to be assessed. 
Publication: AAPG International Convention and Exhibition, Oral Abstract. 2000.
Publisher: American Association of Petroleum Geologists
Published: 2000

Abstract:
Marginal Fields, whether oil or gas, have often been a low priority item for both producers and owners (STATE). Efforts to commercialize a Marginal Field have often focused on corollary issues such as reservoir size, flow rates, Capex or Opex costs. A Marginal Field has much more to do with economics than reserves or production characteristics - from a legislative point of view. A review of several types of Marginal Field legislations and incentives reveals a wide spectrum of styles and methods from tax holidays, reinvestment incentives, sliding scale royalties and the use of an 'R' factor. Each of these programs tried to address specific issues and produces results that can be used by other States to encourage production. A carefully crafted Marginal Field Legislation can create a win-win situation where both the royalty or tax to the Owner and the cash flow to the producer can both rise. When properly used, marginal field legislation provides increased revenue and opportunities to both the owner and the producer. Analysis of global efforts to commercialize sub-commercial fields are presented with specific examples to illustrate positive and negative aspects of such legislation. Additionally a review of countries with substantial non-producing discoveries shows areas where an increased effort can bring large dividends to the State and producers alike
Publication: in International Oil and Gas Ventures: A Business Perspective; eds G. Kronman, D. Felio, T.O’Connor,
Publisher: American Association of Petroleum Geologists
Published: 2000

Abstract:
 
Publication: SPE International Petroleum Conference and Exhibition in Mexico, 1-3 February 2000, Villahermosa, Mexico
Publisher: Society of Petroleum Engineers
Paper Number: SPE 59060-MS
Published: 2000

Abstract:
The successful design and implementation of any improved oil recovery project in a fractured reservoir depends on an accurate characterization of the fracture system. This is especially true in a steam pilot project currently underway in the Yates Field of West Texas. This pilot will assess the economic viability of accelerating gravity drainage in the gas cap of the fractured San Andres reservoir. From the conceptual phase of the project through implementation and monitoring, fracture characterization in the pilot area has been critical to pilot design and success. Key decisions have depended on an accurate assessment of fracture density, orientation, flow capacity and connectivity to other portions of the reservoir. Many geologic and engineering methods have been employed to understand the fracture system. Flexure mapping, tracer testing, pressure interference testing and reservoir simulation were employed in the design phase of the project. Fluid sampling and passive microseismic monitoring have been employed to monitor the project. This paper will discuss each of these methods, field results, and key decisions that were based on the analyses.
Publication: Presented at the 2000 SPE/CERI Gas Technology Symposium, Calgary, Alberta, Canada, 3-5 April 2000.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 59788-MS
Published: 2000

Abstract:
With increasing worldwide CO2 emissions, interest has risen in injecting CO2 into coals to mitigate their possible role in global warming.Concepts from natural gas storage are readily adapted to CO2 sequestration in coals.The classic p/Z plot for describing stored gas inventories is modified for CO2 sequestration using the p/Z* concept developed for understanding conventional coal gas recovery.Coal often exhibits stress dependent permeability and this relationship is used to identify the optimal depth for CO2 injection.CO2 fillup of a coal seam is described by coupling a gas injectivity equation with a mass balance equation.Example calculations are presented for two selected basins
Publication: Presented at the 1999 SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, 15-18 May 1999.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 55605-MS
Published: 1999

Abstract:
Abstract not available.
Publication: Papers presented at the Workshop on Coalbed Methane Recovery and Prospects for a Hydrogen Economy, China Council for International Cooperation on Environment and Development, Beijing, China, 18-19 January 1999.
Publisher: China Council for International Cooperation on Environment and Development
Published: 1999

Abstract:
Abstract not available.
Publication: Journal of Petroleum Technology 50 (10)
Publisher: Society of Petroleum Engineers
Paper Number: SPE 57916-PA
Published: 1998

Abstract:
This paper presents new production decline curves for analyzing well production data from radial and vertically fractured oil and gas wells. These curves have been developed by combining decline-curve and type-curve analysis concepts to result in a practical tool which we feel can more easily estimate the gas (or oil) in place as well as to estimate reservoir permeability, skin effect, fracture length, conductivity, etc. Accuracy of this new method has been verified with numerical simulations and the methods have been used to perform analyses using production data from several different kinds of gas wells. Field and simulated examples are included to demonstrate the applicability and versatility of this technology. These new production decline-type curves represent an advancement over previous work because a clearer distinction can be made between transient- and boundary-dominated flow periods. They also provide a more direct and less ambiguous means of determining reserves. The new curves also contain derivative functions, similar to those used in the pressure transient literature to aid in the matching process. These production decline curves are, to our knowledge, the first to be published in this format specifically for hydraulically fractured wells of both infinite and finite conductivity. Finally, these new curves have been extended to utilize cumulative production data in addition to commonly used rate decline data.
Publication: SPE Advanced Technology Workshop, Chiba, Japan; April 6-8, 1998
Publisher: Society of Petroleum Engineers
Published: 1998

Abstract:
Abstract not available.
Publication: SPE Rocky Mountain Regional Meeting, 18-21 May, Casper, Wyoming
Publisher: Society of Petroleum Engineers
Paper Number: SPE 38379-MS
Published: 1997

Abstract:
A petrophysical study of the Frontier Formation in the Whiskey Buttes Field was performed as part of the GRI project "Emerging Resources in the Greater Green River Basin". Tight gas sands in general, and the Frontier Formation in particular, are difficult to evaluate and predicting long term well behavior is a problem. This study provided a detailed petrophysical characterization of the Frontier Formation which allowed us to compare reservoir characteristics to well performance. Thirty-five representative wells were selected for analysis. The wells were chosen to provide full geographic coverage of the field, to cover the entire range of porosity and permeability and to span the range of production from dry holes to 7 BCF wells. Seven of the wells had routine core analysis available and these were used to calibrate the petrophysical model. A complete shaly sand analysis was performed. Two different pay cases were calculated, generating average effective porosity, permeability, and water saturations for each stratigraphic zone. Also the net feet of hydrocarbon pay volume [h* *(1-Sw)] was calculated for each zone in each well. These pay parameters were then compared with estimated ultimate recovery from decline curves to evaluate which factors could be used to predict well performance. While several trends could be discerned, no one or two factors alone can be used to predict well performance. Log calculated permeabilities were the best predictor, although not a highly reliable one. The fluvial section of the Frontier appears to contribute more to production than the marine zones. Most of the wells drain less than 160 acres. The major problem is that many of the factors affecting production cannot be quantified, including the effectiveness of the hydraulic fracture treatments, presence of natural fractures, and the effective drainage area for each well.
Publication: Proceedings of the 1997 International Coalbed Methane Symposium, 1997.
Publisher: University of Alabama
Published: 1997

Abstract:
Abstract not available.
Publication: Presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October, 1997.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 38861-MS
Published: 1997

Abstract:
An integral part of enhanced coalbed methane recovery (ECBM) is injection of flood gas into a coal deposit via injection wells. Understanding of these wells is critical to maximizing coal gas recovery. Although ECBM is a relatively new and rapidly evolving technology, existing gas injection well technology can be readily adapted to ECBM injectors. This paper discusses characterization of two nitrogen injectors using spinner surveys, Hall plots, reservoir simulation, and pressure transient analysis. Using actual field data, this paper addresses nitrogen injectivity, conformance of injected gas, reservoir sweep, and implications for coal gas recovery.
Publication: International Symposium on Sequence Stratigraphy in S.E. Asia, 1996
Publisher: American Association of Petroleum Geologists
Published: 1996

Abstract:
Twenty-five years of drilling in the oil prolific Sunda and Asri Basins of offshore Sumatra and Java have established the existence of non-marine strata dating from the early Miocene to at least as far back as the late Paleogene. These clastic formations were deposited during the widespread extensional tectonics of the early to late Paleogene and have to a large degree escaped Pliocene basin inversions that characterize many of the onshore Sumatra and Java basins. Recent investigations of early basin history have defined different geologic histories than previously proposed for the Sunda and Asri Basins. The Sunda basin data-set contains adequate well control and good to poor quality seismic data. The Asri basin, on the other hand, has very limited well control but good to excellent seismic data quality. Integration of exploration efforts between the two basins has revealed a nearly symmetric, fault bounded extension in both basins for their early history followed by a shift to a more classic asymmetric rift. The early basin fill of the Sunda Basin consists of the Banuwati Formation and the earliest section of the Zelda Member of the Talang Akar Formation. The Banuwati Formation of the Sunda Basin records an overall transgressive event and culminates in the widespread deposition of the Banuwati Shale member which is the recognized source rock in the Sunda Basin. A thorough study of the well log sequence stratigraphy and available whole core of the Banuwati Formation in the Sunda Basin has identified alluvial fan, fluvial, and shallow lacustrine facies within the non-marine Banuwati Formation. The application of the Sunda Basin's Banuwati sequence stratigraphic model to the Asri Basin gives a predictive model which has proved successful and the resulting exploration has found many similarities in the facies of the early fill of each basin. The sequence stratigraphy of the lower Zelda Member was also examined as the lower Zelda sandstones represent the earliest non-Banuwati carrier beds for the migration of hydrocarbons out of the basins. This paper describes part of on ongoing investigation into the early basin history of the Sunda, Asri and Hera basins.
Publication: Presented at the International Meeting on Petroleum Engineering, Beijing, PR China, 14-17 November, 1995.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 30010-MS
Published: 1995

Abstract:
Coal is not an inert reservoir rock and reacts to gas desorbed from its surface. Coal matrix shrinks as gas is desorbed, increasing cleat width and, therefore, permeability. Very few coal matrix shrinkage data have been reported in the literature so a series of experiments was undertaken to measure such data at reservoir pressures, temperatures, and 100% relative humidity. Strain gages were affixed to the coal sample in the face and butt cleat directions as well as the vertical direction. This work reports measured deformations of a sample of high volatile C bituminous coal from the San Jan Basin during sorption and desorption of first methane then CO2. A pressure cycle was also run with helium, a nonsorbing gas, to determine mechanical compliance of the sample. Observed strain gage behaviors are discussed and shrinkage coefficients for both gases reported. Matrix shrinkage was found to correlate with gas content rather than pressure, confirming the work of a previous investigator. Shrinkage coefficients varied more among replicate gages aligned in the same direction than between gages in different directions. Anisotropic shrinkage effects are discussed. Using a matchstick geometry model, equations are derived for permeability change due to matrix shrinkage. Coefficients reported here are used in example calculations of absolute permeability and porosity increases during coalbed depletion.
Publication: Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October, 1995.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 30731-MS
Published: 1995

Abstract:
As part of the effort to interpret Amoco's enhanced coalbed methane recovery pilot, each of the four nitrogen injectors was tested with a pressure falloff test (PFOT) after approximately five months of injection. An additional test was done on the final injector at the termination of the pilot. The tests were analyzed to obtain flow capacity, wellbore condition, and average reservoir pressure for use in subsequent simulation studies. Stress effects on reservoir permeability and wellbore skin were investigated. Results from the PFOTs yielded an injectivity index which can be used to estimate compression requirements for enhanced coalbed methane recovery projects.
Publication: SPE Gas Technology Symposium, 28-30 June 1993, Calgary, Alberta, Canada
Publisher: Society of Petroleum Engineers
Paper Number: SPE 26172-MS
Published: 1993

Abstract:
Active water influx into a gas reservoir reduces ultimate recovery from that which would be expected under volumetric conditions due to reduced sweep efficiency and residual gas which is trapped at high pressure. Previous investigations on Gulf Coast gas fields presented in the literatures have demonstrated reservoir management techniques which can increase the expected ultimate recovery over 10% of the original gas in place. This paper presents new work in the form of a detailed case history which extends this emerging technology into aquifer gas storage reservoirs. By their nature, aquifer gas storage fields are water-drive reservoirs. Thus, prudent reservoir management is required to reduce the detrimental effects of trapped gas and poor volumetric sweep. A detailed reservoir characterization and numerical simulation study are presented for a midcontinent aquifer gas storage field. It is demonstrated that rate optimization during both injection and withdrawal cycles can significantly improve the performance of the storage reservoir. Performance improvements are realized in the form of a larger working volume of gas, a reduced cushion volume of gas, and a decrease in field water production. This research has significant implications for the business facet of the natural gas industry. By utilizing these reservoir management techniques, gas storage operators will be able to minimize their base gas requirements, improve their economics, and determine whether the best use for a particular storage field is base loading or for meeting peak day requirements.
Publication: GRI Atlas of Major Rocky Mountain Gas Reservoirs
Publisher: Gas Research Institute, U.S. Department of Energy
Published: 1993

Abstract:
(From book description) Application of stratigraphic concepts to selected gas-producing intervals in the Rocky Mountian region and the Permian Basin, including the Mississippian and Creatceous of the Rockies and the Permian of the Permian Basin
Publication: GRI Atlas of Major Rocky Mountain Gas Reservoirs
Publisher: Gas Research Institute, U.S. Department of Energy
Published: 1993

Abstract:
(From book description) Application of stratigraphic concepts to selected gas-producing intervals in the Rocky Mountian region and the Permian Basin, including the Mississippian and Creatceous of the Rockies and the Permian of the Permian Basin
Publication: Journal of Petroleum Technology 45(6)
Publisher: Society of Petroleum Engineers
Paper Number: SPE 21488-PA
Published: 1993

Abstract:
Gas and water production from a coal deposit can be divided into three distinct stages. In the first, gas and water production rates are almost constant. The second stage, beginning production rates are almost constant. The second stage, beginning once pseudosteady state is reached, is characterized by a "negative decline" in gas production rate and a declining water rate. The third stage begins when the peak gas rate is reached. This final stage spans most of the economic life of a coal well and is characterized by a gentle decline in gas rate and negligible water production. Gas production in this stage is described by two production. Gas production in this stage is described by two equations. The first is a gas-deliverability equation using the real-gas pseudopressure developed by Al-Hussainy et al. This equation is applied to published data from a well in the Deerlick Creek field in the Warrior basin of Alabama. The second is a mass-balance equation combining elements from conventional and shale gas reservoirs. The two equations can be coupled to predict gas rates and recoveries of dewatered coal wells. Published simulation results from the Warrior basin Brookwood field and a San Juan basin coal well are compared. The deliverability equation also is used to construct gas-deliverability curves for a typical Brookwood coal well. The method presented here is applicable to coal wells completed in dry coalbeds.
Publication: Presented at the SPE Gas Technology Symposium, Calgary, Alberta, 28-30 June, 1993.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 26201-MS
Published: 1993

Abstract:
Deliverability of coal wells, like conventional gas wells, depends on bottomhole flowing pressure. Because coal wells often produce both gas and water, lowering bottomhole flowing pressure to increase gas rate also increases water rate. Thus, optimization of coal well profitability entails balancing gas revenues and water disposal costs. The present study was undertaken to determine if the relation between coal well bottomhole flowing pressure and gas and water production rates could be described by Vogel's Inflow Performance Relation (IPR). First, simulation studies were clone to test the applicability of Vogel's IPR to coal wells. Secondly, productivity of actual coal wells was compared with Vogel's IPR curves.
Publication: AAPG Bulletin, v. 77, no. 9 (September), p. 1574 and Paper presented at AAPG Midcontinent Section Meeting, Amarillo, Texas, October 10-12, 1993.
Publisher: American Association of Petroleum Geologists
Published: 1993

Abstract:
Hartshorne coals have long been known to be extremely gassy because early underground mines in the Arkoma basin were plagued by methane. Mine data, combined with recent advances in coal-bed methane technology, allow us to better quantify this gas resource. The gas content of Hartshorne coals is controlled by a number of factors, including thickness, thermal maturity, as content, and reservoir pressure. Hartshorne coal can be generally characterized as being thin
Publication: Chapter 9 in Hydrocarbons from Coal, AAPG Studies in Geology #38, edited by B.E. Law and D.D. Rice
Publisher: American Association of Petroleum Geologists
Published: 1993

Abstract:
Abstract not available.
Publication: SPE Western Regional Meeting, 30 March-1 April, Bakersfield, California
Publisher: Society of Petroleum Engineers
Paper Number: SPE 24036-MS
Published: 1992

Abstract:
A light oil steamflood pilot project was conducted from 1987 to 1991 in the Shallow Oil Zone of the Elk Hills field. A thermal simulator, employing a distillable component and a nondistillable component, was used to construct a steam-flood model and duplicate over three years of pilot performance. In addition, a conventional black oil model was used to duplicate pre-pilot primary production performance and quantify the distribution of oil, water and gas saturations prior to the start of steam injection. Uneven thermal energy distribution and limited steam zone temperatures minimized the effectiveness of the steam distillation recovery mechanism.
Publication: SPE Annual Technical Conference and Exhibition, 4-7 October 1992, Washington, D.C.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 24865-MS
Published: 1992

Abstract:
A detailed engineering and geologic evaluation of an offshore Gulf Coast gas reservoir with water influx is presented. The study was undertaken to analyze various production management strategies in order to optimize the ultimate recovery of the reservoir given the detrimental effects of the water influx. Without implementing any reservoir management techniques, the recovery factor of the reservoir is estimated at 66%, much lower than would be expected under volumetric depletion performance. It is demonstrated that producing high volumes of water from downdip wells and adding an additional well high on the structure can significantly increase the ultimate gas recovery from the reservoir. This is achieved by lowering the reservoir pressure which liberates trapped residual gas and by recovering mobile attic gas. However, accelerated gas production does not appear to be beneficial in this particular case due to a reduced volumetric sweep efficiency associated with the accelerated rate case. Economic analyses show that recompletion of an additional well at a higher structural position is the optimum strategy for this particular reservoir. Due to the limited extent of the aquifer, this single well will effectively lower reservoir pressure, liberate gas trapped at residual saturation and recover mobile gas remaining at the top of the structure.
Publication: Technical Presentation presented at the 1992 International Gas Research Conference, 16-19 November, Orlando, Florida
Publisher: Gas Research Institute, U.S. Department of Energy
Published: 1992

Abstract:
Abstract not available.
Publication: SPE Mid-Continent Gas Symposium, 13-14 April 1992, Amarillo, Texas
Publisher: Society of Petroleum Engineers
Paper Number: SPE 24307-MS
Published: 1992

Abstract:
A performance analysis technique is presented which can be used to identify recompletion candidates in producing gas fields. Through geological description and a field case history, it is demonstrated that p/z versus cumulative production curves can be diagnostic tools in identifying inefficient completions or wellbore damage in a stratified reservoir system. It is also shown that these wells can be recompleted or redrilled to add significant incremental reserves which would have otherwise been abandoned. Previous theoretical work presented in the literature demonstrated that layered gas reservoirs producing without crossflow display non-linear p/z versus cumulative production curves. This paper presents field data which support that observation and concludes that the absence of this behavior in a stratified reservoir environment may be indicative of a recompletion candidate due to wellbore damage in one or more of the layers. A field case history is presented involving wells producing from the Mesaverde Group in the San Juan Basin of New Mexico. Wells which were originally completed with nitroglycerin were selectively recompleted to yield significant incremental reserves. These wells were identified by their linear p/z behavior in an area where theory and historical performance indicate a non-linear p/z curve should be present. The results of the recompletion program are presented.
Publication: Presented at the Society of Petroleum Engineers 67th Annual Technical Conference and Exhibition, Washington, D.C, October 4-7, 1992.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 24906-PA
Published: 1992

Abstract:
Coalbed methane wells in the San Juan basin can be highly profitable, with gas production up to about 10 MMcf/D at depths of about 3,000 ft, if the wells are successfully completed with the openhole cavity technique. We report the first measurement of cavity size (radius of about 5 ft) and shape. A cavity can resemble a cylindrical bookcase with shale ledges like shelves. We also report correlations between successful cavity completions and such reservoir/rock parameters as compressive strength, coal rank, permeability, and reservoir pressure (for example, there is no correlation with the minimum coal compressive strength). In this area, wells completed with the openhole cavity technique often produce roughly 10 times more gas than wells completed with hydraulic fracture stimulations. Wellbore mechanics associated with the cavity - e.g., the enlarged wellbore plus enhanced permeability beyond the cavity - does not seem to explain the cavity/fracture production discrepancy. A number of other possibilities are explored, including permeability anisotropy and completion damage to the reservoir or fracture. Severe damage apparently is associated with hydraulic fracture stimulations in the fairway zone, which would explain their poor performance compared with cavity wells.
Publication: Presented at the SPE Rocky Mountain Regional Meeting, Casper, Wyoming, May 18-21, 1992
Publisher: Society of Petroleum Engineers
Paper Number: SPE 24361-MS
Published: 1992

Abstract:
Several investigators have reported coal permeability decreases with increasing stress, but no conceptual model has been advanced to explain this effect. To better understand the permeability of stressed coal, a theoretical and experimental program was undertaken. A common naturally fractured reservoir geometry, a collection of matchsticks, was extended to stressed coalbeds and tested against laboratory measurements using samples from the San Juan and Warrior Basins. Good agreement was obtained between theoretical behavior and laboratory data, Equations are presented for converting laboratory measured stress-permeability data to (a) in-situ permeability as a function of depth of burial in a basin, and (b) to reservoir permeability during coalbed depletion. Evidence in the literature indicates that coal matrix shrinks when gas is desorbed, increasing cleat permeability. Assuming a matchstick geometry and using a coal matrix shrinkage coefficient reported in the literature, the increase in cleat permeability due to matrix shrinkage was calculated. The increase in permeability due to matrix shrinkage during depletion is compared with the decrease in permeability due to increased stress.
Publication: Presented at the SPE Rocky Mountain Regional Meeting, Casper, Wyoming, May 18-21, 1992.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 24358-MS
Published: 1992

Abstract:
Unlike conventional reservoirs, the productive capacity of a coalbed is not immediately apparent. New coal wells typically produce at low rates and often exhibit low gas-water ratios. Only after a coalbed has been dewatered does gas rate begin to rise and water rate begin to fall. A numerical study was undertaken to investigate saturation and pressure behavior during the initial dewatering period and to develop methods to predict its duration. These simulations used typical coalbed and well properties encountered in Warrior and San Juan Basin coal wells. Behavior of gas saturation and pressure profiles during dewatering is discussed. It was found that, for engineering purposes, coalbed dewatering can be considered a constant pressure process. Two methods were developed to determine time and cumulative water production required to dewater a new coal well. The first method is based on the classical definition of pseudo-steady state flow, while the second method is based upon the gas-water ratio. Accuracy of both methods is discussed and a recommendations made for application to actual coal wells. Effective coalbed porosity is difficult to measure, but is necessary for reservoir engineering calculations and numerical simulations of coal well performance. Once a coal well has been dewatered, the gas-water ratio method developed here can be used to determine effective porosity. An example calculation is presented.
Publication: SPE Annual Technical Conference and Exhibition, 6-9 October 1991, Dallas, Texas
Publisher: Society of Petroleum Engineers
Paper Number: SPE 22937-MS
Published: 1991

Abstract:
An analytical model is presented which predicts the performance of gas reservoirs producing under water-drive conditions. The model incorporates a modified water influx technique which accounts for pressure gradients and relative permeability effects pressure gradients and relative permeability effects across the water invaded region of the reservoir. Under certain conditions in gas reservoirs, these effects can cause significant deviations in predicted performance from that behavior projected using conventional water influx theory. The conditions necessary for this to occur and the improvements realized by using the modified approach are discussed in detail. In addition, the results of the analytical model are compared to solutions generated using a radial, numerical simulator. Previous work has shown that for water-drive gas reservoirs, ultimate recovery increases with decreasing permeability, trapped gas saturation and aquifer size, and increasing fluid withdrawal rates. However, these parameters are all interrelated. Gas recovery cannot be determined based on one factor without considering the influence of the others. Thus, this paper details the development of new parameters which incorporate the key factors that influence gas recovery. These parameters describe the shape of the p/z performance curves for the reservoir and allow the p/z performance curves for the reservoir and allow the engineer to estimate the ultimate gas recovery for a particular reservoir/aquifer configuration. particular reservoir/aquifer configuration
Publication: Presented at the SPE Asia-Pacific Conference, Perth, Australia, 4-7 November, 1991.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 23025-MS
Published: 1991

Abstract:
The production of coalbed methane in the United States dates back to the early 1930's. Yet it was not until the early 1980's that research and development projects began to show the enormous potential of this projects began to show the enormous potential of this energy resource. These efforts have resulted in the rapid commercialization of coalbed methane production in the United States, including the drilling of almost 800 wells by Amoco. Efforts to evaluate and implement coalbed methane recovery projects are continuing, with current emphasis being placed on worldwide resources. In recent months, we (and our colleagues) have published almost a dozen papers on coalbed methane published almost a dozen papers on coalbed methane production encompassing a wide variety of topics. This production encompassing a wide variety of topics. This paper summarizes the significant findings of those papers paper summarizes the significant findings of those papers and stresses their importance to field operations. Subjects covered include reservoir modeling, pressure transient analysis, rock property measurements, well stimulation, and enhanced coalbed methane recovery. Although most of the work discussed here was done on coals from the San Juan (Colorado and New Mexico) and Warrior (Alabama) Basins, the results are general and applicable to coals in other parts of the world.
Publication: In Situ, 16(3), 183-202 (1992). Originally presented as paper 9142 at the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama, May 13-16, 1991.
Publisher: University of Alabama;
Published: 1991

Abstract:
It is known that coal permeability measured in the laboratory is highly sensitive to the net confining pressure applied on the sample. Since many coalbed methane modeling studies assume that the permeability of a coal seam does not change with reservoir pressure depletion, skepticism about the accuracy of future predictions is understandable. This paper presents laboratory-measured permeability reduction during reservoir pressure depletion using a whole-core sample of coal in uniaxial strain at reservoir conditions. These laboratory results have been used in a numerical simulation study to determine the influence of pressure-dependent permeability on coalbed methane production. The productivity of a coalbed methane well is substantially reduced because of the decline in coal permeability during reservoir pressure depletion. More significantly, most of the reduction in gas and water production rates because of pressure-dependent permeability occurs during well start-up. Thereafter, the well productivity loss due to stress dependent permeability is fairly gradual over a very long period of time. The characteristic gas and water production-rate profiles obtained from a numerical simulator are almost the same regardless of whether the coal seam permeability is assumed to be constant or stress-dependent.
Publication: Presented at the SPE Rocky Mountain Regional Meeting and Low- Permeability Reservoirs Symposium, Denver, Colorado, April 15-17, 1991.
Publisher: Society of Petroleum Engineers
Paper Number: SPE 21809-MS
Published: 1991

Abstract:
This paper demonstrates field application of pressure falloff testing and analysis methods to new coal pressure falloff testing and analysis methods to new coal degas wells in the San Juan Basin. These tests have provided absolute coalbed permeability, wellbore skin, provided absolute coalbed permeability, wellbore skin, and initial reservoir pressure. Effects due to free gas and gas desorption on pressure falloff tests are considered. The effects of sorption compressibility are shown to have a significant impact on skin but not on permeability. Influence of the duration of the injection and shutin periods on the design and analysis of coal well PFOTs periods on the design and analysis of coal well PFOTs is also discussed. Field examples of both pre- and post-stimulation falloff tests are presented. post-stimulation falloff tests are presented
Publication: SPE Annual Technical Conference and Exhibition, 23-26 September 1990, New Orleans, Louisiana
Publisher: Society of Petroleum Engineers
Paper Number: SPE 20758-MS
Published: 1990

Abstract:
A reservoir characterization technique is presented which can significantly lower the risk involved in developing naturally fractured gas reservoirs. It is shown that depletion ratios can be used to delineate the limits of a field, highlight the prolific trends often associated with naturally fractured reservoirs, and provide a simple, yet accurate, means of assigning reserves to undrilled locations. A field case history is described and the results of a successful twenty well drilling program are presented. Pre-drill reserve estimates for the entire program were within seven percent of the actual post-drill reserve estimates from production decline analysis.
Publication: Journal of Petroleum Technology 42(5)
Publisher: Society of Petroleum Engineers
Paper Number: SPE 18067-PA
Published: 1990

Abstract:
This paper reviews the design, implementation, and performance of one of thefirst field-scale miscible CO2 floods to be conducted in the Rocky Mountainregion of the western U.S. During the first 34 months of CO2 injection, morethan 4 million bbl [636 x 10 M] of incremental oil has been recovered, clearlydemonstrating that the process is displacing significant volumes of tertiaryproduction. Several aspects of the flood's implementation and performance arediscussed, including reservoir pressurization, facilities construction, impactof additional drilling pressurization, facilities construction, impact ofadditional drilling on production response, fluid injectivity, and operationalproblems.
Publication: CIM/SPE International Technical Meeting, 10-13 June 1990, Calgary, Alberta, Canada
Publisher: Society of Petroleum Engineers
Paper Number: SPE 21599-MS
Published: 1990

Abstract:
The recovery of gas from coalbeds is a two-step process. First, the gas diffuses through the matrix process. First, the gas diffuses through the matrix then, secondly, it flows through the cleats to the wellbore. If the release of gas fro. the matrix to the cleats is very rapid compared to the flow of gas. and water in the cleats, the desorption kinetics are relatively unimportant in modeling coalbed methane production. If the coal is well cleated, it can be production. If the coal is well cleated, it can be assumed for engineering purposes that the gas desorbs instantaneously fro. the matrix to the cleat when the pressure in the cleat decreases. This assumption alloys the adsorption of gas on the surface of she coal to be modeled as gas dissolved in an immobile oil. Conventional reservoir simulators can then be used for coalbed-methane modeling purposes. The solution gas-oil ratio of this immobile purposes. The solution gas-oil ratio of this immobile "pseudo" oil is calculated from the Langmuir adsorption isotherm constants and coalbed properties. Additional modest modifications are required in the data describing the porosity and gas-water relative permeability curves to account for the presence of permeability curves to account for the presence of the "pseudo" oil. No code modification is required. This concept has been used with several different simulators to successfully model both single well and 3-D, multiwell coalbed methane problems. A coal well simulation using this method and COMETPC, a simulator developed by ICF-Lewin, are compared.
Publication: Presented at the International Technical Meeting hosted by the Petroleum Society of CIM and the Society of Petroleum Engineers, Calgary, Alberta, 10-13 June, 1990.
Publisher: Petroleum Society of Canada
Paper Number: CIM/SPE 90-118
Published: 1990

Abstract:
The recovery of gas from coal beds is a two-step process. First, the gas diffuses through the matrix then, secondly, it flows through the cleats to the wellbore. If the release of gas from the matrix to the cleats is very rapid compared to the flow of gas and water in the cleats, the desorption kinetics are relatively unimportant in modeling coal bed methane production. If the coal is well cleated, it can be assumed for engineering purposes that the gas desorbs instantaneously from the matrix to the cleat when the pressure in the cleat decreases. This assumption allows the adsorption of gas on the surface of the coal to be modeled as gas dissolved in an immobile oil. Conventional reservoir simulators can then be used for coal bed methane modeling purposes. The solution gas-oil ratio of this immobile “pseudo ” oil is calculated from the Langmuir adsorption isotherm constants and coal bed properties. Additional modest modifications are required in the data describing the porosity and gas-water relative permeability curves to account for the presence of the “pseudo ” oil. No code modification is required. This concept has been used with several different simulators to successfully model both single well and 3-D, multiwell coal bed methane problems. A coal well simulation using this method and COMETPC, a simulator developed by ICF-Lewin, are compared. 
Publication: SPE Annual Technical Conference and Exhibition, 8-11 October, San Antonio, Texas, 1989
Publisher: Society of Petroleum Engineers
Paper Number: SPE 19790-MS
Published: 1989

Abstract:
Diagnostic techniques are presented for detecting and quantifying poorly drained compartments in volumetric gas reservoirs. It is shown that p/z versus G data can be used to assess unrecovered gas reserves and assist in targeting infield development.
Publication: SPE Annual Technical Conference and Exhibition, 2-5 October 1988, Houston, Texas
Publisher: Society of Petroleum Engineers; SPE 18307-MS
Published: 1988

Abstract:
A reservoir study of the Margham field in Dubai, United Arab Emirates was performed. The main objectives of the study were to combine and evaluate all current production and geologic data to better understand historic reservoir performance and develop reservoir management plans for future field depletion and development. To realize this objective a number of simulation tools were developed to help better understand the condensate recovery mechanisms occurring at Margham. This paper concentrates on the development and application of a full-field computer model of the Margham reservoir. Due to the complexity of the Margham reservoir special procedures were required to describe the reservoir geology, represent the field's structure, and model gas condensate phase behavior. A successful match of two and one half years of pressure and production data was achieved using a single porosity simulator. Preliminary results from a strip model indicated the dual porosity mechanism to be inappropriate. However specific areas with extensive, sometimes unmapped faults appear to behave in a manner similar to a dual porosity system. These small areas were adequately modeled with porosity system. These small areas were adequately modeled with the single porosity model by implementing pore volume reductions to represent areas of low sweep efficiency. An aquifer was included in the reservoir description in order to match the field pressure history. Predictions of future field performance emphasized increasing condensate recovery by optimizing current field operations, understanding the benefits of continued gas cycling versus immediate full or partial release of produced gas, and the need for additional infill wells. This paper includes a comparison of actual performance versus the model predicted response during the year following the completion of the study.
Publication: Thesis
Publisher: Texas A&M University
Published: 1983

Abstract:
Abstract not available.
Publication: SPE California Regional Meeting, 23-25 March, Ventura, California
Publisher: Society of Petroleum Engineers
Paper Number: SPE 11685-MS
Published: 1983

Abstract:
The Yowlumne field, located at the southern end of the San Joaquin Valley of California, is one of the largest new onshore oilfields discovered in California in the past twenty years. The field, at an average depth of 12,200', has produced over 42 million barrels of oil since its discovery in 1974. In May, 1982, a portion of the Yowlumne field was unitized and called Yowlumne Unit "B". Nine operators and about 160 royalty owners cooperated to form this unit. A two phase unitization formula based on 1) remaining primary and 2) initial hydrocarbon pore volume was used to form Unit "B". A secondary waterflood project is being implemented which is project is being implemented which is estimated will increase oil recovery by some 25 million barrels.
Publication: Technical presentation presented at the Fourteenth ACS Akron Polymer Conference, 19-20 May, 1983, Akron, Ohio.
Publisher: University of Akron
Published: 1983

Abstract:
Abstract not available.
Publication: SPE Annual Technical Conference and Exhibition, 5-8 October 1983, San Francisco, California
Publisher: Society of Petroleum Engineers
Paper Number: SPE 12042-MS
Published: 1983

Abstract:
The Anschutz Ranch East field is the largest hydrocarbon accumulation discovered to date in the Western Overthrust Belt. Analyses of reservoir fluid samples from the discovery well indicated that the fluid is a rich gas condensate with liquid dropout under reservoir conditions as high as 40 percent of the hydrocarbon pore volume. The proximity of the fluid dew point pressure to the original reservoir pressure dictated that a plan-of-depletion be established very early in the life of the field to avoid reservoir damage and the potential loss of significant liquid reserves. This requirement was further amplified by the fact that some of the depletion alternatives involved major front-end monetary commitments and long lead times for implementation. Using preliminary reservoir data together with compositional simulators, various depletion alternatives ranging from primary depletion to full pressure maintenance were evaluated. Variables examined in the study included such factors as type of injection fluid and injection-production well configuration. Full pressure maintenance using nitrogen preceded by a hydrocarbon-nitrogen gas buffer in an inverted nine-spot pattern was selected as the most attractive depletion method. This plan was approved by the working interest owners and state regulatory agencies and is currently being implemented.