Introduction The 1984 Natl. Petroleum Council (NPC) evaluation of domestic EOR potential stands as the most extensive analysis of the U.S. potential EOR resource ever completed. potential EOR resource ever completed. Publication of the study culminated a 2-year, Publication of the study culminated a 2-year, 50-person-year effort. EOR experts from industry, universities, and government participated. The findings of this study have been participated. The findings of this study have been widely reported, critiqued, and used throughout the industry. L.F. Elkins previously discussed the series of SPE articles on the NPC results by offering his alternative interpretations of the NPC methods and results. He concluded that the methods used in the study were in error; ". . the permeability variations used in the NPC study are anomalous and exceedingly high." He also states that" . . the analyses made by the NPC task force overstate the amounts of remaining oil in place that are trapped in lower-permeability parts of sandstone reservoirs that are within the active dynamic waterfloods. "He concludes this on the basis of his interpretation that the volumetric estimates used in the analysis overstated initial oil in place." These three objections provide the core of his criticism of the NPC analysis. This reply clarifies the NPC's approach and also attempts to clarify several points raised by Elkins concerning the study procedures, models, and data. procedures, models, and data. NPC Data Sources and Procedures The NPC assembled detailed reservoir data and engineering-based models to project possible EOR production under a variety of possible EOR production under a variety of cases reflecting the oil price and the state of technology development. The data-collection effort started with the information available from existing sources within the U.S. DOE, but was significantly expanded and enhanced during the study. Additional material was obtained from questionnaires completed by 18 different companies on 1,300 reservoirs. Table R-1 lists the data elements collected and used in the models. This information was assembled, to the extent available, for each reservoir in the data base. Once collected, all data were thoroughly screened and evaluated for in ternal consistency and were cross-checked with other reservoir properties, companyprovided data, and average values for other reservoirs in the region. For data elements that could not be readily and consistently determined from available data sources, the committees chose to develop default procedures. Where possible, these values were estimated from other data by use of correlations. After all changes were complete, the entire updated data base was again thoroughly screened by committees assigned to assess the potential for the specific EOR methods evaluated. The three committees were composed of renowned experts on miscible flooding, chemical processes, and thermal recovery. Each processes, and thermal recovery. Each committee, in addition to the coordinating committee, included representatives from the oil industry, universities, and government agencies. This effort resulted in the most complete, usable data base possible while guaranteeing internal consistency. The resulting data base contained rock, fluid, geologic, and production information on more than 2,500 reservoirs originally containing more than 330 billion bbl [52.5 × 10–9) M3] Of oil, more than 70% of the national total estimated by the API in 1980. Because of time constraints, the data base was pared to consider only reservoirs with original oil in place (OOIP) estimated at more than 50 million bbl [7.9 × 106 M3]. As a result, the evaluation considered just over 1,000 reservoirs, accounting for more than two-thirds of the total domestic OOIP, a total of around 309 billion bbl [49.1 × 10–9 M3]. Because results were not extrapolated beyond the reservoirs specifically analyzed in this study, they are conservative estimates of the true national EOR potential. The miscible and chemical flooding prediction models required an estimate of the prediction models required an estimate of the permeability variation for each analyzed permeability variation for each analyzed reservoir. Fewer than 50 reservoirs in the data base had values reported for the coefficient of permeability variation. The supplied values were subjective because how they were obtained from core analysis data was not known-e.g., whether the permeabilities were arranged in sequence or averaged permeabilities were arranged in sequence or averaged by position. Because reservoir heterogeneities are unique to each reservoir and directly affect the waterflood as well as the EOR process performance, it was decided to process performance, it was decided to estimate the permeability variation from the demonstrated waterflood recovery performance. performance. The approach used for estimating the Dykstra-Parsons coefficient, VDP, considered the demonstrated waterflood performance in each reservoir. The ultimate performance in each reservoir. The ultimate recovery was estimated by adding seven times the current annual production to the cumulative production (an assumed reserves-to-production ratio of 7 years), as long as the cumulative production was greater than 80% of the estimated ultimate recovery. The recovery efficiency is the estimated ultimate recovery divided by the OOIP. If the cumulative recovery was less than 80% of the ultimate, then the sum of the recovery factors for primary and secondary recovery reported by the operators was used as the ultimate recovery efficiency, if the information was available. The volumetric sweep efficiency was calculated from the recovery efficiency, FVF'S, initial oil saturation, and waterflood residual oil saturation (ROS). The endpoint mobility ratio was calculated from data-base or default values of viscosities and relative permeabilities. A pseudo-VDp was determined on the basis of pseudo-VDp was determined on the basis of the calculated sweep efficiency and mobility ratio for each reservoir in the data base that had sufficient data to perform these calculations. The pseudo-VDp correlations were based on results from a HigginsLeighton streamtube model of a five-spot pattern with 100 permeability layers, pattern with 100 permeability layers, assuming that the economic limit was reached at a producing WOR of 25. The median of all the calculated values was 0.72. The reservoirs for which insufficient data were available to calculate a value were assigned the median value of 0.72. If the pseudo-VDp value was calculated to he less than 0.5, it was given a default value of 0.5. This pseudo-VDp for each reservoir in the data pseudo-VDp for each reservoir in the data base was used in the predictive models for miscible and chemical EOR processes. The methodology the NPC used to calculate pseudo-VDp scales the EOR production to the waterflood volumetric sweep performance because it assumes that the geological performance because it assumes that the geological features that affect the waterflood will also affect the EOR process. Related papers: SPE 13239, SPE 13240, SPE 13241 Related discussions and replies:SPE 18397, SPE 20007, SPE 20009

Tight gas sands for this analysis have less than 0.1 md (100 microdarcies) in situ gas permeability ranging down to 0.001 md (1 microdarcy). permeability ranging down to 0.001 md (1 microdarcy). Eliminating speculative basins and portions of basins where production is proved, a tight gas resource of 409 Tcf has been identified. Estimated recoverable reserves vary between 149 and 182 Tcf at $1.75 and $3.00/Mcf (1977 dollars) with anticipated technology improvements in 5 years. Annual production rates, affected by technologic advances and price growth, could be around 2 Tcf/year in 1985 increasing to 7 to 7 1/2 year for the last decade of this century. This compares with production in 1977 of 19 1/2 Tcf. Most of these technology advancements anticipated relate to better methods for resource characterization lateral and vertical control of massive hydraulic fractures (MHF) extension by design, and the ability to design fracture programs to expose lenticular pays existing within a thousand or more feet from the wellbore but not penetrated by the well programed to drain the area. Parallel with these major objectives are improvements in fracture fluid design, proppants, and postfracture production performance analysis. Introduction Lewin and Associates, Inc. were commissioned by ERDA (now DOE) in 1977 to study the technology and economics of gas recovery from four identified types of unconventional gas, i.e. tight gas, Devonian shale, geopressured water (gas dissolved), and methane from coal. Two reports on this study have been published recently by DOE and a third report detailing methodology will be issued soon. This paper deals only with the tight gas resource as paper deals only with the tight gas resource as studied by Lewin and Associates. The author of this paper has been involved heavily in this study. While paper has been involved heavily in this study. While this paper incorporates the relevant findings of the DOE study, it enlarges and expands on the evolving MHF technology and how it has brought this type of resource into play. Prior to this study, the Federal Power Commission included in its National Gas Survey a study on natural gas technology. This was initiated in 1971 and was published in 1973. It was during this study that deeply penetrating fractures became recognized as having potential for exploiting tight gas sands in three major western basins particularly the Mesa Verde section. At that time the term "massive hydraulic fracturing" was coined, admittedly for lack of a better alternative. With growing application, the abbreviation MHF has become an accepted term. However, there is no real definition as to when a big fracture treatment enters the MHF category. Most treatments in tight gas formations defined herein are categorized as MHF. It is technology related to MHF that is highlighted in this paper. paper. Exploitation of several tight gas formations also is accelerating with production in 1977, amounting to about 0.9 Tcf. The advanced technologies required are primarily aimed at reducing the risk and the maximizing economic recovery efficiency of the resource. THE TIGHT GAS RESOURCE - A DEFINITION Most tight gas formations in this study are classified as those having in-situ permeability to gas of less than 0.1 md (100 microdarcies) and ranging down to 1 microdarcy (see Figure 1). Some shallow low pressure formations may fall into the near tight category. Most of these formations have 40 to 60% connate water saturation and porosities generally in the 8 to 12% range. Singe-phase bench top permeabilities often must be reduced by a factor of 10 or 20 to approximate in-situ gas permeability. The reduction is necessary to account for relative permeability to gas at 40 to 60% water saturation and compaction due to overburden net confining pressure.

Three major findings emerge from the study of the technology and economics of recovering natural gas from tight gas formations.1. A minimum threshold price, near $3.00/Mcf (in mid-I977 dollars) and equivalent to approximately $4. 50/Mcf (in mid-1981 dollars), is required to make the tight gas resource attractive for investment.2. Beyond the threshold price, improvements in technology have a greater impact in terms of gas recovery than further increases in gas prices.3. The combination of increased gas prices and improved recovery technology provides the most effective means for accelerating production from this vast domestic natural gas resource -calculated at more than 400 Tcf in place.The technology improvements that have the largest impact on ultimate recovery are (1) improved ability to identify the net pay and characterize the reservoir, (2) capacity to stimulate multiple reservoirs from a common well bore, (3) increased effective fracture length, (4) ability for fractures to intersect sand lens beyond the wellbore, and (5) optimization of field development.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines. Abstract Preinjection of high-molecular-weight Preinjection of high-molecular-weight polyacrylamide polymers in advance of a polyacrylamide polymers in advance of a miscible slug is proposed as a means of improving reservoir sweep efficiency by reducing the degree of "permeability" contrast between wells in a moderately heterogeneous system. The use of polymers in a preinjected mode is radically different from their "conventional" use to provide a favorable mobility condition between in-place and injected fluids and so maximize areal sweep even in a flood of a "homogeneous" sand. Theory and model flow tests were employed in an investigation of polymer preinjection in advance of a miscible flood. Flood test s in physical models of heterogeneous porous media physical models of heterogeneous porous media showed that preinjection of polymers could result in better flooding efficiency because of increased volumetric sweep. This was concluded from tracer performance data and oil recovery response. Studies of the interactions between the preinjected polymer and a subsequent micellar flood indicated that prior polymer flow had no adverse effects on oil polymer flow had no adverse effects on oil displacement efficiency by a micellar fluid and appeared to decrease surfactant loss to the rock. Additional mobility control requirement in micellar floods as a result of decreased mobility of fluids was moderate. Because laboratory models cannot be scaled to reproduce the complex heterogeneities encountered in reservoirs, extensive field testing of polymer preinjection in a real environment and under carefully controlled test conditions is suggested. This is highly desirable since the timing of development is an important factor if the full value of having available sweep improvement methods is to be realized. Introduction While considerable attention has been given to the chemistry of miscible flooding, little published work is available which discusses effects of variations in formation rock texture on reservoir flooding efficiency by these improved recovery methods. Reservoir rock heterogeneity can result in an injected fluid bypassing significant portions of a reservoir under flood. Circulation of large volumes of water to achieve higher ultimate sweep in a waterflood is tolerable because of the low cost of injected water.

Low permeability gas reservoirs ("tight gas sands") are abundant in the U.S. Economic recovery of the gas in these formations requires reservoir stimulation, usually massive hydraulic fracturing. Significant investigations of tight gas sands by the National Petroleum Council (NPC)(1), Lewin and Associates(2), and the Gas Research Institute (GRI )(3) have agreed that, although some formations can be profitably produced with existing technology, improved reservoir diagnostic and stimulation techniques are required to realize the full potential of the resource. Most major operators and well-service companies conduct research and development to improve tight gas technology. A survey of tight gas research managers in eight companies was conducted to determine their R&D priorities and the constraints under which they operate. The responses of the R&D managers showed a high degree of consensus on tight gas R&D objectives, company priorities, decisionmaking criteria, current activities, and constraints. The representatives of six operating and two service companies stated that they prefer R&D that produces high "payoffs" in the near term, with low-to-medium risk of R&D failure. This characteristic leads industry to focus current R&D on measurement and prediction of fracture geometry (shape and orientation), particularly in the lower-risk blanket-type (as opposed to lens-type or lenticular) formations. Despite the presence of price incentives for production of tight gas and the potential of high return, the constraints on available personnel and funds for R&D limit industry's willingness to conduct the long-term, high-risk R&D needed to produce the lenticular resource. The industry R&D personnel interviewed were familiar with, and generally endorse, those long-range and high-risk objectives and priorities of the Federal tight gas research program that complement university and industry efforts.