Hydraulic fracturing in rock masses involves complex and coupled processes of fractures propagating in discontinuous media and of fluid flow in discrete channels. The Unconventional Gas Program at Lawrence Livermore National Laboratory is actively developing numerical models to gain insight in the physics of these coupled processes. However powerful and versatile these models are, they must be verified against analytical solutions and/or physical experiments. This paper describes the current status of the FEFFLAP code, which models fluid-driven discrete fracture propagation in jointed media. We also discuss the results of a preliminary series of physical tests in which hydrofractures were driven across slanted interfaces between dissimilar materials, in blocks loaded in biaxial compression.
Hydraulic fracturing is employed both for the stimulation of tight hydrocarbon reservoirs, and for estimating in-situ stresses in rock. It involves a complex and coupled process of fracture propagation and fluid flow. In rock masses, the interaction of induced fractures with natural joints and interfaces adds another level of complexity to the problem of predicting the behavior of the hydrofractures, i.e., predicting the behavior of the hydrofractures, i.e., extension, and containment, or lack of it. To gain insight in this problem, the Unconventional Gas Program of the Lawrence Livermore National Laboratory Program of the Lawrence Livermore National Laboratory has an active effort in the development of numerical models [this paper]. Numerical methods are emphasized because of their power and versatility in handling complex physics. Still, numerical models, however powerful they are, must be verified against analytical solutions or physical experiments before they can be fully exercized and trusted.
This paper describes the current status of development and testing of the FEFFLAP code (Finite Element Fracture and Flow Analysis Program). FEFFLAP represents the coupling of the FEFAP discrete fracture propagation code and of the JTFLO program, a propagation code and of the JTFLO program, a LLNL-enhanced version of an earlier code for analysis of fluid flow in rock fractures. We also present the results of a preliminary series of physical tests in which hydrofractures were driven across slanted interfaces between dissimilar materials, in blocks loaded in biaxial compression.
THE FRACTURE AND FLOW MODEL: FEFFLAP
Discrete Fracture Propagation: FEFAP
The foundation for the solid fracture analysis described here is the Finite Element Fracture Analysis Program (FEFAP) developed at Cornell University. FEFAP analyzes planar and axisymmetric structures for crack initiation and growth. The program combines linear and non-linear fracture program combines linear and non-linear fracture mechanics theory, the use of interactive computer graphics, and a unique, automatic remeshing capability to allow the user to initiate and propagate up to ten discrete cracks simultaneously.
FEFAP has been used for a variety of applications involving crack growth in rock, concrete, and metal structures. An example of a large scale problem is that involving the cracking of the problem is that involving the cracking of the Tennessee Valley Authority's Fontana Dam [101. Figures 1 and 2 show meshes before and after crack propagation modeling. A comparison between propagation modeling. A comparison between predicted and observed crack paths is shown in Figure 3. predicted and observed crack paths is shown in Figure 3. The salient capabilities implemented in the present version of FEFAP are:
. Complete interactive-graphical execution of the program. Each analysis step is directed by the user with alphanumerical and graphical feedback of the results of this step. After any complete crack propagation step, the analysis can be terminated and restarted from the previous step. The emphasis in the program design is on providing versatility to the analyst. One is not locked into a batch-produced result via the initial data input.
. Automatic, discrete crack nucleation at arbitrary points and angles on an edge or in the interior of a domain, as specified by the analysis.
Production data from coalbed degasification wells characteristically exhibit a negative decline curve. The dynamics of this methane production are complex and interrelated. As production begins, water and free gas are often first- recovered. Continued production lowers pressure and increases permeability to gas, allocating adsorbed gas to flow. permeability to gas, allocating adsorbed gas to flow. This pressure drop within the formation causes sublimation whereby gas, which is absorbed within the coal, forms on the walls of the micropores. Finally, the desorption through production disturbs the chemical and physical equilibrium of the coal, thus enabling the coal to require generation of methane.
Methane from coalbeds has historically viewed gas an explosive nuisance that must be from underground mines in order to prevent disaster. Over the last two decades, however, increasing attention has been given to the production of coalbed pas from single vertical wells. With the infusion of pas from single vertical wells. With the infusion of research support money provided by the Department of Energy, a rise in natural gas prices, and the deregulation of gas produced from coal, this same methane is no longer viewed as a liability, but rather as an asset.
As a result, several energy companies have acquired acreage and drilled wells expressly for coalbed methane production. As production figures from coalbeds grow, an unexpected phenomenon has emerged that is apparently characteristic of all coalbed gas wells: a negative decline production curve.
Producing, coalbed degasification wells in the Black Warrior Basin,, Alabama and the San Juan Basin, New Mexico all exhibit negative decline production curves. Figure 1 shows gas and water production of the U.S. Steel project in Oak Grove, Alabama. This is 1000 days of production from 17 wells with 4 feet (1.3m) coal at 1000 feet (300m.). Note the inclining gas production curve.
Figure 2 is the production curve for the Amoco Production Gahn Gas Commission Number 1 producing from Production Gahn Gas Commission Number 1 producing from 20 feet (20 m.) of coal st 2800 feet (F sq.m.). Again, note the striking incline gas production curve. Another San Juan Basin well (Figure 3) shows five years of inclining gas production. The well is currently averaging 200 MCF per day from 6 feet (2 m.) of coal at 1500 feet (450 m.). Figure 4 is a San Juan Basin well showing a 20-year history of inclining gas production. The gas is produced from 23 feet (7 m.) production. The gas is produced from 23 feet (7 m.) of coal in 160 feet (48 m.) meter open hole completion at 3200 feet (970 m.).
These wells are located in different basins and are completed Jr. coals of widely varyings thickness, rank, depth, and geologic age. The spacing of the wells varies from a single degasification well to wells on 22 acre spacing. The characteristic common to all of these coalbed degasification wells is the negative decline production curve.
The dynamics of methane production from coal is complex and interrelated. Four distinct processes occur throughout the life of a degasification well. First, gas is held in coals as both free gas in the fractures and as gas that is adsorbed or held to the wells of the coal micropores in many coalbeds the production of the free gas is Inhibited by water production of the free gas is Inhibited by water saturation. once dewatering has occurred the permeability to gas increases, causing the initial incline permeability to gas increases, causing the initial incline curve of Figures 1 and 2. In the water-free wells of Figures 3 and 4 dewatering does not take place and free gas flows immediately.
Secondly, this initial production lowers the pressure within the fractures causing gas molecules, pressure within the fractures causing gas molecules, which are adsorbed to the walls of the micropores, to break free and move to the fractures. Movement of the gas through the coal erodes the coal matrix which improves the communication between the fractures and the micropores. This erosion is evidenced by increased coal fines recovery during periods of peek production. production. P. 403
Use of F-overlays to evaluate air-drilled Devonian shale wells simplifies recognition of subtle variations in log response between productive and nonproductive intervals. Combinations of F-curve overlays, called F-pairs, are plotted on a logarithmic grid and normalized in an interval thought to be unfractured. Anomalous response behavior becomes useful in choosing fracturing intervals.
Most Devonian shale production in the eastern United States consists of gas, but in Wirt, Ritchie, and Pleasants counties of northwestern West Virginia, considerable quantities of oil also are being produced from this unit. Potentially oil-productive produced from this unit. Potentially oil-productive Devonian shale covers approximately 300 square miles (777 sq. km.) in these counties. The prospective pay interval is generally from 2500 to 3500 feet pay interval is generally from 2500 to 3500 feet thick (762-1067 m), and consists of interbedded shales and siltstones.
Within the study area, shales and siltstones are characterized by low primary porosity and permeability, and most production is believed to come permeability, and most production is believed to come from naturally occurring fractures associated with the Burning Springs anticline. The reservoir quality of these naturally occurring fractures can be enhances by hydraulic fracturing to increase production rates.
Most wells are air-drilled to minimize formation damage, and a typical logging suite consists of gamma ray, induction, density, sidewall neutron, and temperature logs.
Log interpretation of fractured reservoirs is difficult. Fracture porosities tend to be very low, normally in the .5 to 1.5 percent range, and only subtle differences, if any, in log responses may distinguish a productive from a nonproductive interval. Some operators simply "shoot in the dark". They pick a shallow zone where oil is likely, or they try to "frac" all the zones at once. This procedure is subject to error and can be needlessly expensive.
Eliminating those intervals where production is unlikely would reduce the number of perforations needed, as well as the number and size of the fracture treatments. This can result in considerable savings without raising fears of having missed commercial intervals.
This paper presents a qualitative, quick-look evaluation technique using gamma ray, induction, density, and sidewall neutron logs. It points to a means of identifying intervals in any given well which are most likely to support commercial hydrocarbon production. It also attempts to identify those intervals from which only oil production is probable. probable. "F-overly techniques are devised for use in conventional log analysis to quickly eliminate from further detailed evaluation all nonproductive intervals. Applied to fractured shale reservoirs, the method uses all F's available to take advantage of different tool responses to lithology and fluid changes.
The induction log measures conductivity which then is converted to resistivity for log presentation. Measurements are made in horizontal loops, presentation. Measurements are made in horizontal loops, and the tool is thought of as being relatively unresponsive to vertical fractures and to hydrocarbon filled horizontal fractures will provide an easy current path and should register as intervals of reduced resistivity.
Devonian shales in the area under consideration produce hydrocarbons without any water, so if newly produce hydrocarbons without any water, so if newly logged wells show any fractures at all, it can be assumed that the section will contain hydrocarbons.
Tight oil and gas reservoirs often require stimulation in order to make economic exploitation possible. Tailored pulse loading, usually by possible. Tailored pulse loading, usually by downhole use of propellants or explosives, has been studied as a means of improving production in these reservoirs. This paper presents an overview of the first year's effort on a three-year combined theoretical-experimental research program to develop a systematic understanding of the tailored pulse loading/fracturing phenomena. The project pulse loading/fracturing phenomena. The project is designed to address the sensitivity of multiple fracture initiation and propagation to rock and fluid properties and pressurization history. The results will ultimately contribute to the design procedures for field applications. procedures for field applications
Many hydrocarbon-bearing reservoirs are insufficiently permeable to allow economic production by conventional well completion techniques. production by conventional well completion techniques. Examples are the tight sands of the western U.S. and the Devonian shales of the eastern U.S. Aside from formation characteristics, the deliverability of hydrofractured wells tend to be proportional to fracture conductivity and fracture area within the pay zone. A method to optimize these parameters pay zone. A method to optimize these parameters which has been seriously studied for well workovers, overcoming wellbore damage, and stimulation of naturally fractured formations is tailored pulse loading. Using a sufficiently fast pulse loading. Using a sufficiently fast pressurization rate, typically with a propellant, pressurization rate, typically with a propellant, multiple radial fractures from the wellbore can be achieved. One can easily envision that the possibility of linking a natural fracture set to the possibility of linking a natural fracture set to the wellbore is enhanced using tailored pulse loading as compared to a conventional biwing hydraulic fracture. With the exception of some limited empirical models, little is known of the physical phenomena and parameters governing the multiple phenomena and parameters governing the multiple fracturing process as caused by tailored pulse loading. In particular, the process is likely to be sensitive to downhole stress conditions, formation elastic and hydraulic parameters, fluid parameters, and pressurization history. This parameters, and pressurization history. This paper describes a three-year program to address in paper describes a three-year program to address in detail the sensitivity of the multiple fracturing phenomenon to these parameters and the first phenomenon to these parameters and the first year's results of that program.
Multiple fracture from a pressurized wellbore can be considered to occur in three sequential stages. The first stage is the wellbore pressurization prior to rupture. During this stage, pressurization prior to rupture. During this stage, pressure diffusion from the wellbore is occurring pressure diffusion from the wellbore is occurring simultaneously with wellbore deformation. Flaws, which may be either microfractures or preexisting macro-fractures, are undergoing pressurization at the wellbore and energy is being stored in the wellbore either by liquid or gas compression.
The second stage begins at the time of flaw rupture with subsequent extension from the wellbore. In this stage, the fractures are sufficiently short to propagate independently -- that is, each fracture is blind to the existence of the other fractures. The fractures do not begin to effectively "feel" the other fractures until they have extended one or two well radii from the well face. During this second stage, the large amount of energy stored in the compressed wellbore fluid at the time of rupture is released. Since this is a wellbore storage phenomena it is very sensitive to the volume of the packed-off section of the wellbore and to the fluid compressibility.
The last stage of the process is the extension of multiple fractures from the wellbore, during which fracture-fracture interaction is occurring. During this stage, the fracturing process is very sensitive to the fluid pressure process is very sensitive to the fluid pressure distribution within the fractures. Analytic solutions for stress intensity which assume a uniform pressure loading within the fracture indicate that, if any of the fractures become longer than the others, those fractures will continue to propagate and the shorter fractures will halt due to clamping by the longer fractures. Thus, only a single biwing fracture will result.
Detailed analyses of more than 50 core samples of western tight sands have resulted in several unanticipated observations that are set forth in this paper. Core analyses performed under stress paper. Core analyses performed under stress representative of producing conditions provided data on porosity, pore volume compressibility, stress dependence of permeability to gas, and slope of the Klinkenberg plot (permeability at constant net stress vs. the inverse of pore pressure). Scanning electron microscope (SEM) and petrographic microscope analyses were performed on samples cut from the ends of core plugs tested. The microscopic studies were explicitly plugs tested. The microscopic studies were explicitly directed toward observing the <0.1 micron flow path openings deduced from permeability data.
The Computer Operated Rock Analysis Laboratory (C.O.R.A.L.) used for,) these measurements has been previously described. Permeabilities are measured previously described. Permeabilities are measured with a maximum pressure drop of 20 psi, much less than the pore pressure of 100 to 1500 psia. At the one microdarcy level, the standard deviation of a sequence of permeability measurements under constant conditions is typically 2% of the measured value. Resolution is a few nanodarcies. The accuracy of porosity measurement is about +/- 2% of the reported value, but the sensitivity to pore volume change due to an incremental step in confining pressure is better than 0.1% of the pore volume. Thus, pore volume compressibility is measured to an accuracy of a few percent for a 1000 psi step in confining pressure. percent for a 1000 psi step in confining pressure. The selection of tight sandstone samples for analysis involved an intentional bias. Namely, all samples were from depths that were either known to be gas producers or judged likely to be producers on the basis of wireline log analysis.
CLAY CONTENT OF GAS-BEARING TIGHT SANDS
One of the sponsors of the work reported herein requested that studies be performed on western tight sand containing a broad spectrum of types and amounts of clays. To our surprise, the search for such samples a quite narrow range for both types of clays in the gas productive tight sands his is illustrated by the data on five samples shown in Table 1. Although dry Klinkenberg permeabilities, under net stress representative of permeabilities, under net stress representative of producing conditions, varied by two orders of producing conditions, varied by two orders of magnitude, total clay content (<2 micron particles) of the samples was in the relatively narrow range of 3.8 to 9.1 weight percent. The water-sensitive fraction of clays was found to be less than 50% of the total clay present and to lie in the range of I to 4 weight percent of the sample. percent of the sample. Neither the total quantity of clay nor the percentage of water-sensitive clay was found to percentage of water-sensitive clay was found to correlate with the porosity or permeability of the sample under pressures representative of producing conditions. however, the amounts of water-sensitive clay in the rocks were high enough for laboratory drying conditions to have a significant effect on the measured values of porosity and permeability.
Porosities and permeabilities for the samples in Table 1 were first measured after drying to constant weight at 60 deg. C at 45 deg. relative humidity as suggested by Bush and Jenkins). The measurements were then repeated after drying at the same temperature without humidity control. The percentage increases in porosity and permeability are shown in Table 2. The porosity and permeability are shown in Table 2. The increase in measured pore volume was examined in the context of the general rule of thumb by Bush and Jenkins 2 that "100 mg of water per gram of clay. equals one molecular layer of adsorbed water on montmorillonite (smectite)." Assuming a density of 1.00 for relating this water to pore volume suggests that lack of humidity control resulted in driving about one layer of water of hydration off the expandable clay in each sample (see Table 2).
FLOW PATH DIMENSIONS
Klinkenberg permeability data, taken with net pressure on the core plug representative of the pressure on the core plug representative of the midpoint of reservoir drawdown, has been analyzed to deduce the size of flow paths. The analysis starts with the assumption that mass flow through a slot or narrow crack of uniform width can be described by the sum of Poiseuille's equation for laminar flow, with "no slip" at the walls, plus an empirical constant times Knudsen's equation for flow with a mean free path larger than the opening. For a single slot of path larger than the opening. For a single slot of unit height this yields:
Trends of subsurface structure, total sandstone isopachs and thickness variations are used to geologically characterize the depositional subdivisions of the non-marine part of the Mesaverde Group in the Rulison Field area of the southern Piceance Basin. Investigation of a gas production trend indicates that higher productivity may be controlled by structure induced fracturing productivity may be controlled by structure induced fracturing and is independent of thicker sandstone accumulations. In addition, over-pressured gas reservoirs in a non-marine part of the Mesaverde Group have not been fully evaluated and may be an important exploration target.
Objective. The objective of this investigation is to integrate the geological and production characteristics of the Rulison Field area to obtain a more concise understanding of the factors which allow greater production from low-permeability, lenticular reservoirs present in the non-marine part of the Mesaverde Group. In present in the non-marine part of the Mesaverde Group. In addition, characterization of the subsurface geology and production should improve evaluations of the Department of Energy's MultiWell Experiment (MWX). The area investigated is located in Garfield County, Colorado, and includes the Rulison Field and Mamm Creek Field, hereafter referred to as the Rulison Field area. The study area is shown in Figure 1.
Interval Investigated. The sediments characterized in this study are a part of the Mesaverde Group clastic wedge deposited during Late Cretaceous time as a series of delta systems which pregraded into an interior seaway. The base of the interval investigated is the top of the Rollins Sandstone Member of the Mesaverde Group. The top of the interval investigated is the top of the Ohio Creek Conglomerate (the top member of the Mesaverde Group ). A generalized stratigraphic column, shown in Figure 2, illustrates a portion of the geologic section present in the southern Piceance portion of the geologic section present in the southern Piceance Basin.
Methods. Data for this study includes logs from 44 wells with penetrations into the Mesaverde Group. Monthly production penetrations into the Mesaverde Group. Monthly production records for 29 of these wells were also acquired.
A total sandstone isopach map was prepared which utilizes gamma ray logs run through the non-marine Mesaverde section to identify sandstone units. Sandstones were differentiated from siltstones and mudstones so the isopach map represents only the total thickness of relatively cleaner sandstone. Included in the isopach map were sandstone units having a gamma ray deflection less than 25 percent of the difference between the maximum and minimum gamma ray deflections in the non-marine Mesaverde section. The total thickness of cleaner sandstone per well was plotted on a base map and interpretively contoured. plotted on a base map and interpretively contoured. Coal units were identified in this investigation by interpreting responses from a combination of caliper, gamma ray, resistivity, density or neutron logs.
MWX. Much of the regional geological data in the Rulison Field area has been made available through studies performed in association with the Multi-Well Experiment. MWX is a coordinated research effort to investigate means of stimulating production of natural gas from low-permeability, lenticular sandstone reservoirs. The MWX site, consisting of three closely spaced wells (MWX-1, MWX-2 and MWX-3) penetrating the non-marine Mesaverde section, is located in Section 34, T6S, R94W.
STRUCTURE AND TOTAL INTERVAL THICKNESS
The Rulison Field study area borders the Grand Hogback, a steeply dipping outcrop of rocks which forms the eastern structural and geographic boundary of the Piceance Basin. The tilted rocks of the hogback are a result of Laramide orogenic events occuring near the end of Mesaverde deposition in the basin.
Paralleling the strike of the Grand Hogback in the southeast basin area are several major anticlines which influence the subsurface structure of the Mesaverde Group sediments. Most notably, these are the Divide Creek Anticline, Baldy Creek Anticline and Wolf Creek Anticline.
The subsurface structure on the top of the Mesaverde Group in the Rulison Field study area is illustrated in Figure 3. The structure of the eastern one third of the mapped area is dipping approximately 3 (.052 rad) to the northwest. The subsurface structure here is possibly a continuation of the northwesterly plunging Divide Creek Anticline directly to the southeast of the plunging Divide Creek Anticline directly to the southeast of the mapped area.
The DOE Multi-Well Experiment (MWX) is a research oriented field laboratory whose objective is to improve the technology and provide additional insight into the processes required to develop provide additional insight into the processes required to develop low permeability lenticular gas sandstone reservoirs. The site of the MWX is located in the Rulison Field in the Piceance Basin of Colorado, as shown in Figure 1.
The MWX consists of three closely spaced wells drilled through the Marine Mesaverde Formation to depths of about 8,000 ft.
A detailed geological and geophysical assessment is a continuous effort being conducted throughout the Piceance Basin and other areas as a means to characterize the salient features of this site. Very extensive core and logging programs were carried out in all three MWX wells with emphasis on the zones of interest. Seismic surveys and sedimentological investigations were conducted to provide an assessment of morphology, areal extent of lenses and provide an assessment of morphology, areal extent of lenses and others. As a prelude to the intensive reservoir investigations that were scheduled for the lenticular sandstones, several well tests were performed in the blanket Cozzette sandstone. Some of the experiments conducted within the Cozzette included in situ stress testing, several short drawdown and buildup tests as well as a more sustained interference and pulse test that utilized two of the available MWX wells.
The marine blanket Cozzette sandstone characteristically exhibits gas permeabilities on the order of 10 microdarcies or less. However, the production and test data from the MWX site along with subsequent analytic methods require an average reservoir permeability on the order of 100's of microdarcies. Data obtained permeability on the order of 100's of microdarcies. Data obtained from the observation well during the interference test suggests that the pressure distribution from the production well was not radially symmetric and thus the reservoir was modeled as an anisotropic naturally fractured reservoir. Numerical modeling techniques including a dual porosity reservoir model were used to simulate this naturally fractured tight reservoir. Included in our analysis was a parametric sensitivity study for a number of salient well and reservoir parameters, such as wellbore damage a the effects of boundaries.
Several months of sustained winter pipeline production that followed well testing attests to the fact that the natural fracture system within the Cozzette extends over a large area.
This paper details some of the studies carried out in the Cozzette sandstone and includes core analysis, and the results of the MWX well testing.
INTRODUCTION AND BACKGROUND
At the MWX site the Mesaverde Formation is found to lie at a depth of between 4,000 and 8,300 ft. Outcrop studies indicate that most of the Upper Mesaverde Formation was deposited by meandering stream systems and includes a meandering fluvial system, that grades into more carbonaceous but gas-bearing paludal deposits. Three continuous marine blanket sandstones are paludal deposits. Three continuous marine blanket sandstones are at the base of the column, the Rollins which is water-saturated, Cozzette and Corcoran sandstone which are gas-bearing.
lsopachous contours in the Cozzette sandstone show that the interval thickens markedly eastward, and there is an east-northeast zone of thinning that must reflect an underlying anticline or sandstone buildup. The Cozzette lies between two thick deposits of marine Mancos shale and is separated into two zones by about 50 feet of mudstone and siltstone. The two zones were appropriately designated the Upper and Lower Cozzette. The well testing described herein was carried out in the more productive Upper Cozzette. The logs shown in Figure 2 detail the location of the Cozzette within a portion of the marine interval. The surface and sub-surface location of the wells, MWX-1 and MWX-2 are shown in Figure 3 along with the distance between wells at the depth of the Cozzette. (123 ft). During test periods, bottomhole pressure, bottomhole temperature, surface tubing pressure, casing pressure, fluid flow rates and other pertinent information were pressure, fluid flow rates and other pertinent information were acquired, manipulated and stored using a PDP-11/34 computer system. The field computer, interfacing hardware, accompanying calibration instrumentation and repair facility are all housed within the DOE/ Sandia Well Testing Facility located at the MWX site. Most of the subsequent analysis was performed on a Cyber 76 computer, DOE Nevada Operations and a VAX 730, CER Corp.
MWX COZZETTE CORE ANALYSIS
A total of 3,700 feet of 4 in. diameter core, including some oriented and pressurized were obtained from MWX-1 and MWX-2. The MWX cores were sealed at the site and shipped to several different laboratories for analysis. The following procedures were described by Randolph of IGT in performing their analysis.
In 1980, the National Petroleum Council (NPC)/ published the most authoritative and comprehensive estimates to date of the technical and economic potential of tight sands gas.
While the NPC study remains the landmark effort on this subject, its estimates for recoverable natural gas are considered by many to be optimistic. The Gas Research Institute (GRI) and the Department of Energy (DOE) jointly commissioned construction of the Tight Gas Analysis System (TGAS) as a vehicle to perform systematic sensitivity analyses of the NPC study, to serve as a repository for future additions to the data base and analytical understandings of the technology, and to estimate the benefits of specified R and D advances. This paper describes TGAS briefly demonstrates its reconciliation with published NPC results, and reports sensitivity analyses of:
Improved fracture effectiveness with and without closer well spacing;
Producing from gas-bearing lenses encountered by the wellbore versus lenses lying remote from the wellbore; and
Altering the NPC's assumptions about the relationship between reservoir permeability and thickness.
The reconciliation and sensitivity studies confirm the analytical integrity of the NPC study but also point out that the NPC's results contain significant uncertainties.
Background and Purpose
Low permeability ("tight") natural gas sands were recognized as a major potential domestic resource by the middle 1960's. The detailed studies of the late 1970's, and particularly the 1980 National Petroleum Council study particularly the 1980 National Petroleum Council study brought this resource to national attention. This highly credible study concluded that natural gas from tight sands was a massive resource with substantial potential for sustaining domestic gas production in an era of declining conventional gas reserves-to-production ratios and could conceivably contribute to a "gas economy" in the near- and mid-term.
The NPC results, while highly respected, were considerably higher than prior estimates. A number of uncertainties (requiring sensitivity analyses) are inherent in the NPC results. Thus, the Gas Research Institute and the U.S. Department of Energy jointly sponsored the "automation" of the NPC study in order to:
Explore the sensitivity of its geological, technological, and economic assumptions on the overall estimates;
Test the implications of alternative gas research strategies on the resultant economically and technically producible gas; and
Serve as an analytically useful repository for new and emerging findings about the resource and the technology for characterizing and extracting it.
The resulting system, christened the Tight Gas Analysis System (TGAS), has been constructed, validated against the NPC results, and exercised through selected sensitivity analyses.
This paper seeks to quantify some of the uncertainties in the NPC estimates in order to establish which are critical areas for further research and/or analyses. It does not challenge the NPC estimates, findings, or conclusions -- only new data can do that. It does however, explore the implications of key uncertainties in a "what if..." fashion.
An unprecedented core analysis program is under way as part of DOE's Multi-Well Experiment (MWX)- MWX is a research-oriented field laboratory whose objectives are to thoroughly characterize lenticular tight gas sands and to develop technology for their production. Over 4100 ft (1250 m) of core were production. Over 4100 ft (1250 m) of core were taken from three wells separated by only about 115-215 ft (35-66 m) at depth. All major categories of core analysis are reviewed and results through December 1983 are included. Those include routine core analysis, restored state reservoir parameter measurements, electrical measurements, mechanical rock property data, mineralogy, organic maturation, natural fractures, and geochemistry. This paper also describes the laboratory work on core and formation invasion and the development of instruments that were used in the field processing of the core.
An unprecedented core analysis program is under way as part of DOE's Multi-Well Experiment (MWX). MWX is a research-oriented field laboratory whose objectives are to thoroughly characterize lenticular tight gas sands and to develop technology for their production. Results from the core program provide production. Results from the core program provide input to well test and stimulation activities, information on the earth's stresses, and data to correlate with log studies to improve their reliability. These results also provide a thorough characterization of the Mesaverde formations.
Core taken in this program comes from the three wells located in the Rulison field of the Piceance basin of Colorado, which are separated by only about 115-215 ft (35-66 m) at depths of interest. A total of over 4100 ft (1250 m) of 4-inch (0.12 m) diameter core was cut in intervals shown in Fig. 1: 2744, 930 and 454 ft (836 m, 283 m, and 138 m) in MWX-1, MWX-2 and MWX-3, respectively. About 1150 ft (550 m) of this amount was oriented; this was divided nearly equally between the three wells. Core recovery exceeded 99% and the condition of the core was excellent. This was probably due in part to the use of oil-based drilling fluid in mwx-l and -2, a polymer drilling fluid in MWX-3, and to the use of Stratapax coring bits.
Successful completion of the MWX core program has required: (1) laboratory study of invasion of tight sandstone by an oil-based mud which is similar to that used in drilling the first two wells; (2) development of a core gamma assembly for use in the field; (3) use of a specially developed laboratory apparatus for analyses of restored state permeability and porosity measurements in a permeability and porosity measurements in a semiproduction mode; (4) development of special tools to provide more rapid determination of dip, strike, and bearing data on natural fractures and slickensides found in oriented core; (S) use of a special facility to perform field processing of core (e.g., photography and lithologic descriptions, core gamma log, sealing of core, taking of plugs, and handling and shipping); (6) provisions for special core measurements at the well site (e.g., strain relaxation, desorption of coals, and collection of gas samples for chemical and isotope analysis); (7) development of a core library with computerized inventory; and (8) a major part in the development of a paleomagnetism technique for orienting sedimentary core.
Routine core analyses were performed at one-foot intervals over all the sands encountered to help screen the core body for special core analyses. over 1100, 300 and 150 Plugs were taken in the field from the three wells. Plugging was usually extended into the rock abutting each sand.
Specific intervals were selected for detailed special core analyses. Dry Klinkenberg permeabilities at pressure and CEC measurements were permeabilities at pressure and CEC measurements were made and thin sections were taken and analyzed every 1-3 ft (0.3-1.0 m) across the sand lenses and into the abutting "shales" or caprock.
Many operators do not routinely run prestimulation pressure buildup tests in prestimulation pressure buildup tests in low permeability gas reservoirs. Frequently, all that is available is a single-rate flow test. To obtain permeability estimates for FERC filings and to evaluate the reservoir, a new method has been developed for analyzing typical prefracture production data.
Permeability estimates obtained from this method have been used as a major source of data in numerous successful tight gas determinations, including the Cotton Valley, Wilcox Lobo, and Canyon formations in Texas.
The paper shows that this simple method can be quite reliable. This conclusion is based on a comparison of permeabilities estimated with this technique and with more rigorous determinations from pressure buildup tests.
Accurate reservoir description is necessary to develop tight gas reservoirs economically. A critical formation property
is in-situ permeability. An accurate estimate of formation permeability is needed for fracture design calculations and for predicting future production as a function predicting future production as a function of time. Permeability estimates are also needed to determine if a reservoir qualifies for FERC's "tight gas formation" classification.
In many cases, operators do not run pressure buildup tests on low permeability pressure buildup tests on low permeability gas wells prior to hydraulic fracture stimulation. Frequently a well is perforated, broken down and produced for only a perforated, broken down and produced for only a few days prior to performing a massive hydraulic fracture treatment. Chokes are changed frequently in this testing program and there are often shut-in periods of varying lengths between flow periods. This pre-fracture flow data cannot be analyzed pre-fracture flow data cannot be analyzed using conventional pressure transient analysis techniques; therefore, pre-stimulation permeability estimates are not pre-stimulation permeability estimates are not available. To compound the problem, post- fracture pressure buildup tests leading to unambiguous interpretations are often prohibitively time consuming. Thus, an prohibitively time consuming. Thus, an alternate method to estimate formation permeability, even if it is less accurate permeability, even if it is less accurate than the buildup tests, is needed to evaluate tight gas reservoirs using available pre-fracture flow data. pre-fracture flow data. This paper presents an approximate method (ONEPT) for determining formation permeability from single-point flow data. permeability from single-point flow data. This new method uses conventional transient flow equations in situations where only the initial formation pressure, the final flowing pressure, the cumulative gas production, and the final flow rate are known. production, and the final flow rate are known. The ONEPT method is appealing because, in contrast to pressure buildup data, which are often not available, single-point flow data are nearly always available on gas wells. This paper describes the ONEPT method and documents its validity in two field studies in which it is compared to the results of pressure buildup tests. In addition, the pressure buildup tests. In addition, the paper shows the effect on permeability paper shows the effect on permeability estimates of wellbore storage, variable rate history (including shut-in periods), and uncertainties in skin factor. These effects were determined using finite-difference reservoir simulation.