Tight Gas Sands Research Articles

Technology Focus: Tight Reservoirs (November 2008)

Technology Focus Attention to tight reservoirs has moved beyond the boundaries of North America as the importance of these hydrocarbon systems as global energy assets continues to grow. In addition to the complex geology, petrophysics, and reservoir heterogeneities dealt with in our industry today, tight reservoirs (<0.1-md permeability) provide unique challenges related to hydrocarbon storage and flow. Over the coming years, drilling wells with an ever-reducing surface spacing will strain available resources. New technologies and processes (e.g., improvements to drilling and completion of horizontal wells) will be developed to increase reservoir contact and drainage, which in turn will improve operations efficiency, production, and recovery significantly. Effective exploitation of tight reservoirs will depend on new technologies and on improving the fundamental understanding of tight reservoirs over the life cycle of the field. The evolution in fundamental understanding will rely on obtaining critical reservoir data including saturations, wettability, capillary pressure, structural features, deposition and diagenetic effects, volumes, mineralogy, lithology, in-situ stress effects, and rock strength. It will also rely on the ability to incorporate the structural, mechanical, and petrophysical properties of the reservoir into simulators so one may simulate and assess different reservoir-drainage strategies. Achieving continuous subsurface monitoring and measurement during drilling, completion, stimulation, and production will be critical to evaluate the drainage behavior and to validate the optimization of the field-development strategy. In this way, we will not only lower capital expenditures, investment-recovery times, and operating costs but also ensure maximizing the recovery of the hydrocarbon from the reservoir over the life of the field. Papers selected for this month's feature focus on the industry's progress in building the tight-reservoir knowledge base and how we are crafting methodologies to improve our decision making in reservoir development, characterization, and production. Tight Reservoirs additional reading available at the SPE eLibrary: www.spe.org SPE 110050 • "A Comparative Study of Capillary-Pressure-Based Empirical Models for Estimating Absolute Permeability in Tight Gas Sands" by J.T. Comisky, SPE, Apache Corporation, et al. IPTC 11545 • "A Case Study: Using Wireline Pressure Measurements To Improve Reservoir Characterization in Tight Gas Formation—Wamsutter Field, Wyoming" by R.A. Schrooten, BP plc, et al. SPE 110809 • "Barnett Shale Completions: A Method for Assessing New Completion Strategies" by R. Leonard, ProTechnics, et al.

Horizontal Wells in Tight Gas Sands: Risk Management To Maximize Success

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110067, "Horizontal Wells in Tight Gas Sands - A Methodology For Risk Management To Maximize Success," by Jason Baihly, SPE, Dee Grant, SPE, Li Fan, SPE, and Suhas Bodwadkar, SPE, Schlumberger, originally prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 October. The paper has not been peer reviewed. Successful applications of horizontal wells have been limited to high-permeability reservoirs and unconventional formations such as coal, chalk, and shale. Horizontal wells are commonly two to four times more expensive to drill and complete than offset vertical wells, yet theoretically are capable of as much as three to five times the production. However, research shows that in practice, many of these wells produce only 10 to 30% more than offset vertical wells. The full-length paper presents a detailed methodology to identify, understand, and manage risk associated with horizontal wells drilled in tight gas sandstone reservoirs. Introduction Horizontal wells have had great success in high-permeability oil sands, unconventional gas shales, and carbonates. With advances in drilling and completion technologies, there has been a recent trend in North America to drill and complete horizontal wells in tight gas sandstones. In the full-length paper, tight rock is defined as sandstone with permeability less than 0.1 md. Whenever the gas price has been strong in North America, operators tend to attempt more-innovative and inherently riskier investments in natural-gas plays that include new-formation plays, varied drilling techniques, and experimental completion methods. With the current active climate and favorable gas price, increasing emphasis is being placed by exploration-and-production companies on getting as much gas out of the reservoir as quickly as possible, while minimizing cost. Horizontal wells allow operators to increase gas production of a well by exposing more of the reservoir to fracture stimulation. This increases the likelihood that a horizontal well can produce more than its offset vertical counterparts. The key is that the production increase must more than make up for the cost increase associated with the horizontal well. The challenge is identifying and mitigating risks in tight gas sandstone horizontal wells. Methodology The full-length paper discusses each phase of the methodology that can be used to minimize the risk and maximize the success of horizontal completions in tight gas sandstones. The sections include the reservoir model, planning, drilling, completion, and production. In the full-length paper, throughout the various phases there are some discussions about how one or more aspects of a certain phase will affect the design and success of the overall horizontal well or affect other phase aspects that occur subsequently. This methodology is by no means a linear progression; it is circular, so that all aspects of each phase have the greatest amount of input to design and risk mitigation of horizontal completions in tight gas sandstones.

Enhanced Aqueous Fracturing Fluid Recovery from Tight Gas Formations: Foamed CO2 Pre-pad Fracturing Fluid and More Effective Surfactant Systems

Abstract Under pressured, tight, deep formations represent a challenge in terms of recovery of fracturing fluids. CO2, N2 and binary high quality foams are widely used in this type of reservoir due to their capacity to energize the fluid and improve total flowback volume and rate. Surfactants designed to reduce surface and interfacial tension are also a key element in the design of fluid systems to enhance recovery and reduce entrapment of fluid barriers within the formation. Enhanced fluid recovery improves overall completions economics due to less total treatment cost and less time required for flowing back fluids. The most important benefit is achieving a less damaged proppant pack, resulting in higher fracture conductivity. This document will discuss the application of CO2 foamed fluids and surfactants to enhance fracturing fluid recovery and other techniques adopted by one operator in the Wild River Field to improve completion practices. Introduction Unconventional gas-in-place in Canada (not including gas hydrates) has been estimated at approximately 2,589 Tcf; 1,500 Tcf of these reserves correspond to tight gas(1). Achieving optimum development of these reserves is challenging due to the low permeability (< 0.1 mD) and abnormal pressures that characterize tight gas sands. The challenges are both technical and economic. Unconventional reservoirs, in general, require higher capital expenditure compared to conventional reservoirs(2). Commercial rates are, in most cases, achieved by hydraulically fracturing pay zones. The perfect fracturing job in these cases would consist of an inexpensive, long fracture with infinite conductivity, 100% propped, 100% effective length, and contained in the pay zone with 100% fluid recovery. However, realistically we know that a tight gas-bearing zone faces abnormal pressure, low permeability, clay swelling and migration, capillarity effects, near-wellbore restrictions and formation complexity and heterogeneities. These characteristics usually result in damage from drilling and cementing operations, water phase trapping, screenouts, proppant not carried to the far field, dehydrated polymer, etc. This paper will review different practices that are proving to mitigate some of these problems, focusing on enhanced fracturing fluid recovery with the aid of high-quality CO2 foamed fluid as a pre-pad and the addition of solvents/surfactants. The experience gained after performing 192 fracturing jobs in the Cadomin Formation, Wild River Field in central Alberta will help illustrate the benefits of the practices recommended in this document. Description: Cadomin Formation, Wild River Field The practices described in this document are based on the experience acquired fracturing in the Cadomin Formation of the Wild River Field in Alberta, Canada (Figure 1). The Cadomin Formation is a deep basin, tight gas formation with NW-SE trending, usually the lowest reservoir in sequence, and consequently, highly stressed. The Cadomin Formation is a braided channel deposit, sourced by conglomeratic and sandstone alluvial fans to the west. This zone is present in every Wild River well(3). The common reservoir parameters of the Cadomin Formation are presented in Table 1. FIGURE 1: Wild River Field location(3). Table 1: Reservoir properties.

Application of multi-component seismic exploration in the exploration and production of lithologic gas reservoirs

The multi-component seismic exploration technique has drawn great attention in the petroleum industry because it enlarges the S-wave information, reduces the ambiguity in reservoir prediction, and improves the prediction and identification possibility of reservoir fluids. To push forward the application and development of the technique, the 2D and 3D multi-component technical tests have been carried out since 2002 in the Sulige Gasfield, Ordos Basin; the Guang'an Gasfield, Sichuan Basin; the Xushen Gasfield, Songliao Basin; and the Sanhu area, Basin, Qaidam Basin. The imaging of the converted wave is better than that of the P-wave for the gas-bearing structures in the deep igneous body of the Songliao Basin and the Sanhu area, and can define the reservoir boundaries more accurately. In the description of the tight sand gas reservoirs of the Sulige and Guang'an Gasfields, the converted wave imaging improves the accuracy of reservoir prediction and fluid identification, paving the way for the arrangement of wells.

Analysis of Production Data From Hydraulically Fractured Horizontal Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110848, "Analysis of Production Data From Hydraulically Fractured Horizontal Wells in Tight, Heterogeneous Formations," by F. Medeiros, SPE, Petrobras, and B. Kurtoglu, SPE, E. Ozkan, SPE, and H. Kazemi, SPE, Colorado School of Mines, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed. The full-length paper discusses the analysis of production data from hydraulically fractured horizontal wells in tight, heterogeneous formations. Horizontal wells with longitudinal and transverse hydraulic fractures that might be surrounded by a region with natural fractures are considered. These well/reservoir configurations are of interest in many unconventional reservoirs, including tight gas sands and shale-oil or -gas formations. A semi-analytical model that incorporates the key features of reservoir heterogeneity and the details of hydraulic-fracture and wellbore flow was used to compute production decline. Introduction In the last decade, interest in developing unconventional oil and gas reservoirs has grown. Most of these unconventional reservoirs have very low permeability, as in the case of tight gas sands and fractured shale formations. Production economics for these reservoirs normally requires large reservoir contact per well. An efficient means of increasing reservoir contact to achieve higher well productivity is to drill horizontal wells and stimulate with hydraulic fractures. Productivity might be improved further if the horizontal well and hydraulic fractures are connected to an active natural-fracture network. This fracture network may be pre-existing in a naturally fractured reservoir (dual-porosity system) or may be generated or reactivated locally by hydraulic fracturing around the well. Production characteristics of wells in globally and locally fractured reservoirs may differ significantly, depending on the contrast between the matrix and natural-fracture properties. The full-length paper discusses the analysis of production data from hydraulically fractured horizontal wells in reservoirs with a global- or localized-natural-fracture network. It explains the characteristics of production decline associated with various transient-flow regimes, describes the procedure to generate production-decline curves, and demonstrates matching field data with the model. The general idea of this work follows from a production-decline-analysis concept. A transient productivity index (PI), J, is used in the analysis of production data for horizontal wells. Material-balance time is incorporated into the analysis to generalize the analysis procedure for all phases and modes of production. There are two important aspects of the approach presented in the full-length paper. The first aspect is the use of a semianalytical model that incorporates the important features of reservoir heterogeneity and hydraulic fractures without elaborate numerical computations. The model was built on the basis of a semianalytical simulation approach. Having a computationally efficient model is important in that the production-decline model needs to be used in an iterative manner in the analysis of the field production data. Moreover, especially in the early development stage, there are not enough data to sufficiently characterize heterogeneous, unconventional reservoirs. Therefore, more-detailed numerical modeling may not be a viable option until more data become available later in the development of the field.

Imaging tight gas sandstones in the East Texas Basin

Low porosity (tight) gas sands contain important commercial reserves but, unfortunately, are difficult to image seismically with the quality needed to drive an effective drilling programme. These reservoirs typically have a small contrast in acoustic impedance relative to the encasing shales which results in a subtle seismic signature. This signature becomes even more difficult to identify in the presence of intra-bed multiples and other undesired seismic energy. Since this resource is predominantly exploited in the onshore arena, seismic imaging is also subject to the many cultural and near surface factors that affect land seismic data quality.

Capillary Wicking in Gas Wells

Summary Gas expansion near the wellbore during production causes the evaporation of connate water. When the reservoir permeability is low, capillarity is controlling, causing liquid movement to the near-wellbore region, where drying rates are higher. In tight-gas sands or in shale gas formations, where capillarity is high, the gas production itself can cause depletion of the water saturation below residual values because of such evaporation. In this work, we present a study of the fundamental processes involved during the flow of a gas in a liquid-saturated porous medium. We have modeled evaporation by accounting for the capillary driven film flow, or "wicking," of saline liquid to the wellbore or the near-fracture region and the effect of gas expansion. It is shown that, for gas reservoirs with connate water saturation, large pressure drawdowns lead to a drying front that develops at the formation face and propagates into the reservoir. When pressure drops are lower, water rapidly redistributes because of capillarity-induced movement of liquid from high- to low-saturation regions. This phase redistribution causes higher drying rates near the wellbore. The results show, for the first time, the effect of both capillarity-induced film flow and gas compressibility on the rate of drying in gas wells. The model can be used to help maximize gas production under conditions such as water blocking by optimizing the operating conditions. Additionally, it can be used to obtain a better understanding of the impact of capillarity on evaporation and consequent processes, such as salt precipitation.

Analysis of Chalk Petrophysical Properties by Means of Submicron-Scale Pore Imaging and Modeling

Summary For many rocks of high economic interest such as chalk, diatomite, shale, tight gas sands, or coal, a submicron-scale resolution is needed to resolve the 3D pore structure, which controls the flow and trapping of fluids in the rocks. Such a resolution cannot be achieved with existing tomographic technologies. A new 3D imaging method based on serial sectioning, which uses the focused-ion-beam (FIB) technology, has been developed. FIB technology allows for the milling of layers as thin as 10 nm by using accelerated gallium (Ga+) ions to sputter atoms from the sample surface. After each milling step, as a new surface is exposed, a 2D image of this surface is generated, and the 2D images are stacked to reconstruct the 3D pore structure. Next, the maximum-inscribed-spheres (MIS) image-processing method computes the petrophysical properties by direct morphological analysis of the pore space. The computed capillary pressure curves agree well with laboratory data. Applied to the FIB data, this method generates the fluid distribution in the chalk pore space at various saturations.

Let's get cracking

The Reservoir Characterization Project at the Colorado School of Mines acquired three time-lapse multicomponent seismic surveys at Rulison Field, Piceance Basin, Colorado, to identify fracture zones in the tight gas sand reservoir (Figure 1). The purpose of the time-lapse study is to delineate fractures and to use this knowledge to aid in the exploration and development of this tight gas sand field. Tight gas is an important resource, and natural fractures play a significant part in enhancing permeability and controlling production.

Multicomponent VSP imaging of tight-gas sands

Low-porosity Bossier and Cotton Valley sands of the East Texas Basin, U. S., have only a small acoustic impedance contrast with the encasing shales but a greater relative contrast in shear-wave impedance. Vertical seismic profile (VSP) data acquired with both a near-offset and far-offset P-wave source clearly demonstrate the P-P reflectivity and P-S mode conversions within the Bossier section. We designate conventional P-wave reflectivity as P-P, shear-wave reflectivity as S-S, and P-wave/shear-wave mode conversion data as P-S. While Bossier P-P reflectivity is low, it appears to be adequate for mapping thick sandbodies such as the York Sandstone, the main exploration target in this area. However, P-P reflectivity is even lower and is inadequate for imaging the overlying Cotton Valley Sands. In contrast, the far-offset VSP data acquired with a P-wave source demonstrate a high level of P-S-mode conversion, which is used to image this interval with definition that is not provided by P-P reflectivity. This provides strong support for the use of P-S-mode conversion imaging for seismic characterization of tight sand reservoirs. Near-offset shear-wave VSP data acquired with a shearwave source show low S/N ratio and limited bandwidth for the downgoing waveform because of the depth of the target; shear-wave energy appears to have a more limited range of propagation than P-waves. Such effects may also have a strong negative impact on multicomponent imaging of these sands using surface seismic techniques. Multicomponent 3D VSP imaging provides a superior solution by placing the geophones closer to the subsurface zone of interest.

Overview: Tight Reservoirs (October 2006)

High oil and gas prices provide a major boost to the development of tight and unconventional reservoirs. While most of this activity is in North America, tight and unconventional reservoirs are becoming more popular throughout the world. During the last year, I probably have seen more than a dozen conferences in North America on shale plays and unconventional reservoirs with increasing interest and participation from major operators. Success in unconventional reservoirs sometimes can be achieved only with "unconventional" thinking and approaches. The mix of "empirical" and "high-tech" engineering continues to provide an interesting and challenging work environment for engineers. A significant challenge in tight reservoirs is the proper completion of layered reservoirs. In some areas, operators are completing very thick, highly layered formations. The challenges begin with formation evaluation—What is actual pay? How do we optimize hydraulic-fracture staging and completion strategies to ensure coverage of all pay zones while minimizing cost? How do we evaluate which zones are contributing to production, and are we recovering all the reserves efficiently? In some areas, water-producing formations are interspersed with pay zones. How can these formations be avoided without sacrificing hydrocarbon production? There is one persistent question in tight reservoirs that continues to haunt engineers. How do we distinguish between completion effectiveness and reservoir performance? If a well underperforms, is it the result of a poorly performing hydraulic fracture, or is it just poorer-than-anticipated reservoir quality? This question is of high importance because it has major implications for well-completion optimization and infill-drilling strategies. More focus on the importance of gathering appropriate rock, reservoir, and hydraulic-fracturing data and application of advanced technologies hopefully will give us better answers to those questions. Tight Reservoirs additional reading available at the SPE eLibrary: www.spe.org SPE 100572 "A Study of Fracture-Initiation Pressures in Cemented Cased-Hole Wells Without Perforations" by G. Rytlewski, Schlumberger, et al. SPE 96104 "Optimal Stimulation Treatments in Tight Gas Sands" by S.A. Holditch, Texas A&M U., et al. SPE 100434 "Field Study of Completion Fluids To Enhance Gas Production in the Barnett Shale" by G.S. Penny, CESI Chemical, et al.

Stimulation Effectiveness in Multilayered, Tight Gas Reservoirs: Pinedale Anticline Area

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100574, "Using Reservoir Modeling To Evaluate Stimulation Effectiveness in Multilayered ‘Tight’ Gas Reservoirs: A Case History in The Pinedale Anticline Area," by S.K. Schubarth, SPE, Schubarth Inc.; J.P. Spivey, SPE, Phoenix Reservoir Software LLC; and P.T. Huckabee, SPE, Shell E&P Co., prepared for the 2006 SPE Gas Technology Symposium, Calgary, 15–17 May. Low-permeability, or "tight," gas reservoirs are being developed at an ever-increasing rate in the U.S. Currently, there are several tight gas plays in the U.S. where multiple intervals are commingled for economic viability. The Pinedale anticline completions pose a complex problem in determining the best stimulation method because as many as 22 separate stimulation treatments are placed in as many as 70 discrete sands over a 6,000-ft-thick interval. Evaluation is complicated by permeability variations that exceed two orders of magnitude and pore-pressure gradients that range from 0.22 to 0.83 psi/ft. Introduction Development of the Pinedale anticline in southwestern Wyoming has continued at an aggressive pace over the past several years. Massive hydraulic-fracturing (MHF) treatments are the only way to stimulate production from the tight gas sands present in this area to economically acceptable levels. Generally, each well requires between 14 and 22 MHF treatments to produce effectively from all potential pay intervals. Often, more than 2 million lbm of proppant is used per well, representing a high investment cost to the operator. The ability to evaluate the incremental production associated with the use of one proppant vs. another can have a significant effect on field profitability. Data Analysis Production and completion information from 11 wells with 172 fracture-treated intervals was included in this analysis. Production information was updated, and all 11 wells have at least two production logs, with one early in the well life. A detailed production history also was available for all wells for use in the reservoir-simulation evaluation. Six different proppants were used in the fracture treatments pumped. Reservoir Simulation. For single-layer tight gas reservoirs, fracture and reservoir properties usually are estimated by analyzing production data. Methods for such single-layer analysis include advanced decline-curve analysis with constant-terminal-pressure type curves, type-curve matching with constant-terminal-rate type curves, and automatic history matching with a single-layer analytical reservoir simulator. Single-layer analysis methods may provide estimates of in-situ permeability to gas, fracture half-length, fracture conductivity, and drainage area, which are used in evaluating the success of a fracture treatment, selecting restimulation candidates, optimizing future fracture treatments, forecasting future performance, and estimating reserves.

Overview: Well Stimulation (July 2006)

As I write this, my third and final opportunity to select technical papers for this feature, I find myself in Baku, Azerbaijan, the birthplace of our modern-day petroleum industry. This is an amazing place, where the history of our industry collides with the present. It is still possible to see some of the earliest commercial oil wells that were dug by hand and cased with wood; while just offshore, huge new development projects use some of the most modern technology available to the industry. Even with current prices for oil and gas, our industry struggles to supply the energy to support the dynamic economies of the world today. Achieving the goal of long-term, low-cost sources of hydrocarbons will require significant technology advances in the area of well stimulation. From the papers I have seen this year, it is apparent that these technological advances will affect many different portions of our industry, from old, mature fields, where significant reserves have previously been economically unattractive, to the new, major ultradeepwater projects that are being evaluated today. The challenge will be to increase productivity, and then to maintain that increased productivity throughout the life of the field to provide improved ultimate recovery. New and innovative stimulation technologies are emerging that will shake the foundations of some of our tried and proven methods. Still, in other cases, we see elegant enhancements to improve the performance of existing technologies. It appears that the future challenge will be for us to find more-cost-effective ways to improve well productivity. It appears that well stimulation will remain a dynamic part of our industry. I am hopeful that this industry will continue to be attractive to new, innovative, and challenging minds who will continue to shape the future of the petroleum industry. Well Stimulation additional reading available at the SPE eLibrary: www.spe.org SPE 98329 "Evaluation of Nonlinear Fracture Relative Permeabilities and Their Impact on Waterfrac Performance in Tight Gas Sands" by R.B. Sullivan, SPE, Anadarko Petroleum Corp., et al. SPE 98314 "A Breakthrough Fluid Technology in Stimulation of Sandstone Reservoirs" by F.E. Tuedor, SPE, Schlumberger, et al. SPE 97659 "Controlling Formation Fines at Their Sources To Maintain Well Productivity" by P.D. Nguyen, Halliburton, et al. SPE 97161 "Proppant Flowback Prevention—A New Technology for Low-BHST Applications" by D.E. Johnson, SPE, Hexion Specialty Chemicals Inc., et al.

Tight Gas Sands

Tight Gas Sands

Tight Gas Sands

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Tight gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs developed in the past are sandstone, but significant quantities of gas also are produced from low-permeability carbonates, shales, and coal seams. In this paper, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight-carbonate and gas-shale reservoirs. In general, a vertical well drilled and completed in a tight gas reservoir must be successfully stimulated to produce at commercial gas-flow rates and produce commercial gas volumes. Normally, a large hydraulic-fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells can be drilled, but these wells also need to be stimulated. To optimize development of a tight gas reservoir, a team of geoscientists and engineers must optimize the number and locations of wells to be drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher-permeability conventional reservoirs. On an individual-well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher-permeability conventional reservoir. As such, many more wells (closer well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place compared with a conventional reservoir. Definition of Tight Gas Reservoir In the 1970s, the U.S. government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many physical and economic factors. The physical factors are related by Darcy's law, as shown in the stabilized, radial-flow equation, Eq. 1, (Lee 1982).

Assessment of Permeability from Well Logs Based on Core Calibration and Simulation of Mud-Filtrate Invasion

This paper describes the application of a new methodology to estimate the permeability of clastic rock formations based on numerical simulation of the physics of mud-filtrate invasion. The methodology assumes a key well with a complete suite of well logs and laboratory core measurements of porosity, permeability, capillary pressure, and relative permeability. For additional wells in the same field, absolute permeability is estimated by matching shallow resistivity logs with the electrical resistivity in the flushed zone yielded by the simulation of mud-filtrate invasion. We describe the application of this methodology to the estimation of permeability in three wells penetrating the same over-pressured tight gas sands of the East Texas Bossier Formation. Conventional core porosity and permeability measurements, along with capillary pressure, are used to determine rock types and flow units in the cored key well. Estimates of permeability based on a modified version of Winland's equation agree with the measured permeability of the available core samples. Simulations of mud-filtrate invasion account for the dynamic process of immiscible flow between mud filtrate and in-situ gas as well as for salt mixing between mud filtrate and connate water. Moreover, the simulations properly reproduce the effect of mudcake buildup along the borehole wall. Two-dimensional spatial distributions of water saturation and salt concentration obtained from the simulations are used to calculate spatial distributions of electrical resistivity. The latter are checked against the measured shallow, medium, and deep resistivity logs to calibrate time of invasion and Archie's saturation and cementation exponents. Based on the analysis in the key well (Well 1), petrophysical assessment of flow units is performed in two nearby wells (Wells 2 and 3) within the same gas field. Initial Winland permeability values are progressively adjusted until the calculated spatial distributions of electrical resistivity agree with the shallow array-induction resistivity readings. We find that for Well 2, the estimated permeability is equal to the initial guess, whereas for Well 3 the estimated permeability is approximately 50-80% higher than the initial guess.

Energy Commodity Prices

Energy commodity prices have been rising at an unprecedented pace over the last five years. As oil supplies tighten and prices frequently break new highs, major oil companies have recently unveiled a flurry of multi-billion dollar deals for new projects whose target is not oil but natural gas. This article explores new sources of natural gas as well as whether natural gas and oil prices exhibit mean-reversion. The author notes that the three major unconventional gas resources identified so far are coalbed methane (CBM), tight gas sands, and organic gas shales. She concludes that with prices of oil approaching $70 per barrel at the end of August 2005 and oil futures trading above $70 on the NYMEX, these alternative sources of natural gas appear today to be a partial answer to the world energy needs.

Underpressured and Overpressured Tight Gas Sands: II. Spatially and Temporally Varying Conditions

This paper investigates the behavior of gas in tight sand aquifers when the shape of the aquifer, its cross-section, permeability, and temperature can all vary along the length of the aquifer. The basic response equation is steady state input of gas under pressure at the lower end of the aquifer and uses Darcy's law for fluid motion in association with buoyancy drive on the gas to determine the gas pressure variations along the aquifer as the lower end aquifer conditions are changed. Both overpressured and underpressured situations can arise, and are sensitive to the variation of parameters describing both the geometry and the physical conditions in the aquifer. Several illustrations are given to show how simple changes can cause different pressure conditions along the aquifer, making it difficult ahead of drilling to know which conditions prevail in a given tight gas sand aquifer.

Slick-Water and Hybrid Fracturing Treatments: Lessons Learned

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89876, "Slick-Water and Hybrid Fracture Treatments in the Bossier: Some Lessons Learned," by Mukul M. Sharma, SPE and Phani B. Gadde, U. of Texas at Austin; Richard Sullivan, SPE, Richard Sigal, SPE, Robin Fielder, SPE, and David Copeland, SPE, Anadarko Petroleum Corp.; and Larry Griffin, SPE, and Leen Weijers, SPE, Pinnacle Technologies, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. To better understand the process of fracturing tight gas sands, a comprehensive data set was gathered and analyzed for the Bossier formation in the Dowdy Ranch field. The bottomhole treating pressures were higher than expected on the basis of the measured stress profiles. Effective fracture lengths derived from pressure-buildup analysis and history matching of production data were significantly shorter than designed fracture lengths (or those predicted from uncalibrated fracture models). The data collected and analyzed provided valuable insight into the performance of water and hybrid fracturing treatments in tight gas formations. Introduction Waterfracs and hybrid fracs are the stimulation treatments used in many low-permeability reservoirs. Typically, improving the performance of gas wells in marginal gas plays requires improvement of fracturing technologies. To ensure that these gas wells remain economically attractive, even at modest gas prices, completion and fracturing practices must be optimized. Research was aimed at improving the performance and reducing the cost of fracture treatments by acquiring and analyzing fracture-treatment data from the Bossier play in east Texas. Six gas wells (data wells) were identified in the Dowdy Ranch field for a detailed analysis of the well and fracture-treatment data before, during, and after a fracture treatment. The full-length paper details data acquired in Anadarko Petroleum Co.’s Anderson No. 2 well, summarizes findings, and presents recommendations for better fracture treatments on the basis of lessons learned.

The global gas renaissance: opportunities for innovative exploration plays and new technologies in existing fields and unconventional gas resources in the liberalized gas market place: overview

Of all the fossil fuels, natural gas is environmentally the cleanest, having a lower carbon content with respect to energy output than either coal or oil. Global demand for gas has risen steadily over the last decade and forecast demand growth now outstrips all other major energy sources. These two factors should dictate that gas will remain the energy source of choice until renewable alternative energy sources become readily and economically available. The UK is set to face a shortage of proven indigenous gas reserves. However, the known conventional global resources of natural gas are very significant, with reserves projected to last for 60 years at current production levels, and expected un-discovered resources predicted to exceed this figure. In addition, huge volumes of ‘unconventional’ gas resources are trapped in hydrates on the seafloor, in coal beds, in low-permeability sandstone reservoirs (so-called ‘tight gas sands’) or in shale deposits. Whilst the global resource base is good, the UK is set become a net importer of gas as the scope for significant new conventional resources is small, UK gas production is already very efficient, and opportunities for unconventional resources are limited. Traditionally, natural gas has been viewed as a stranded asset when located far from markets. However, since natural gas can now be efficiently converted to a liquid by cooling to −160°C, and then economically transported in ships, gas is now a mobile commodity like oil. The bottleneck of the European Interconnector, once seen as the key to UK gas supply, has thus been circumvented. Liquified Natural Gas (LNG) is being transformed from a small volume, exotic trade into a sophisticated global spot market, opening global gas exploration and production to deep waters and plays far removed from markets. Additionally, the steady advance of technology has played and will continue to play an active role in developing new gas exploration plays, optimizing recovery factors and rapidly monetizing reserves. Unconventional sources of gas will undoubtedly provide additional significant reserves, but on a timescale of ten years and beyond. The future of natural gas looks assured for some time to come.