The tertiary recovery of oil by chemical flooding is an admittedly complex process involving both micro and macroemulsions. The work reported here suggests from fundamental considerations of theory, operation and economics that in situ emulsification of the immobile residual oil (and mobile secondary oil) in the petroleum reservoir and its transport as such to the petroleum reservoir and its transport as such to the producing well is feasible and has many advantages over producing well is feasible and has many advantages over miscible processes. These include freedom from mobility control and ultralow interfacial tensions that call for substantial chemical outlays. Arguments are presented in support of this view with tertiary oil recovery data obtained from Berea core floods using cosurfactant-free aqueous solutions of two hydrocarbon sulfonates differing substantially in their solubility in water. A brief discussion of pertinent EOR methods is given, emphasizing the occasionally obscured but significant distinction, from an EOR-perspective, that exists between the mobile (secondary), and immobile (tertiary) components of the reservoir oil targetted by these processes. Introduction The energy crisis has focussed attention on the critical role of crude oil in the economies of all oil consuming countries. What is not generally apparent, however, is that the current crisis is the result of the limitation of petroleum recovery technology, that now leaves in the abandoned oil field, nearly two thirds of the original resource, as economically "unrecoverable." Overcoming this constraint by innovative technology is undoubtedly the single major challenge of the oil industry over its entire history. Success in meeting this challenge, obviously, has worldwide implications. The very circumstance of our current and largely limited knowledge of the forces that control multiphase fluid flow through porous media, in relation to oil production, in itself holds the prospect of possible progress in the critical area of enhanced oil possible progress in the critical area of enhanced oil recovery. Ongoing work on enhanced oil recovery research at this Energy Technology Center, has shown that trace amounts of certain yet to be identified chemicals occurring in selected water soluble (oil-insoluble) alkylate sulfonates and petroleum sulfonates are capable of immiscibly displacing substantial amounts of tertiary oil from water flooded Berea sands. The oil recovery is found to be uninfluenced by oil viscosity ("mobility control"), or by interfacial tension levels or by chemical requirements generally associated with conventional chemical (microemulsion) floods The hypothesis that the mechanism of tertiary oil recovery by these purely aqueous sulfonate solutions, devoid of cosurfactants or other additives, consists e dispersion or emulsification of the residual oil into the injection water with the aid of the EOR-active substance, and the transport of the emulsion as such to the production well, explains the experimental data as well as similar results obtained with an oil soluble, sparingly water soluble synthetic sulfonate ("Texas II") of known structure. Continuing work aims at corroborating this hypothesis by additional fundamental studies and establishing process application feasibility in the field. The key to this goal has been and still remains the separation and isolation of the water soluble EOR-active substance from its chemically complex commercial source to be followed by its identification and manufacture for further investigations including field testing. The Enhanced Oil Recovery Problem From the perspective of petroleum recovery, it is convenient to recognize two regions or "domains" in the void space of a porous medium based on whether or not the fluid (water or oil) associated with it, is mobile or immobile. The connate water and the residual oil representing immobile "cushions" of water and oil, together account for nearly two-thirds of the total pore volume of the average oil reservoir, leaving but pore volume of the average oil reservoir, leaving but a third for simultaneous two-phase flow involved in all immiscible displacement processes. Under this concept, the mobile water and oil associated with the two-phase flow region of the saturation - relative permeability curves of reservoir rock, may be permeability curves of reservoir rock, may be visualized as coexisting, continuous filaments of the conjugate phases. Water flooding would, then amount to the "squeezing out" of the mobile component of the oil filaments by progressively expanding filaments of water until continuity of the far less cohesive (relative to water) and relatively viscous oil phase is disrupted at residual oil saturation. P. 57
Summary This paper describes a method to examine the relative merits of locationsfor horizontal wells in a naturally fractured shale gas basin. The methodologyexamines noncontrollable variables (existing reservoir pressure, pay-zonethickness, and success ratios) as well as controllable pressure, pay-zonethickness, and success ratios) as well as controllable variables (gas price anddrilling costs) to arrive at the profitability for a horizontal well project ina candidate area. An analysis of the expected monetary value (EMV) and a cashflow model are used to obtain a distribution of cash flow levels that yields adetermination of whether a project is likely to succeed. Ranges ofprofitability for an unstimulated project is likely to succeed. Ranges ofprofitability for an unstimulated horizontal well are presented graphically. With this approach, the most likely areas for horizontal drilling to beeconomically and technically successful are identified easily and quickly. Introduction The most promising areas for horizontal-well development in a tight, naturally fractured shale reservoir can be identified quickly with a methodthat ranks proposed horizontal-well projects. This method combines the benefitsof risk analysis, in terms of success ratios and EMV calculations, with thepredictive capabilities of a reservoir simulator. EMV analysis lends itself toa determination of whether a project is likely to succeed. EMV analysis can beused alone to compare similar projects quickly in terms of the drillingtechnique used; however, a more realistic project analysis is possible if EMVanalysis is used in conjunction with rate of return (ROR) and paybackdeterminations. The tight, naturally fractured Devonian shales of the Appalachian basin compose the project area for this horizontal-well rankingproject area for this horizontal-well ranking study. The state of West Virginiapreviously was partitioned into three geologic settings, reflecting the typesof Devonian shales present. Fig. 1 shows the primary partitioned present. Fig.1 shows the primary partitioned areas in Geologic Setting 1, an organicallyrich, black shale region (Huron-Rhinestreet formation), the area that is thefocus of this study. Geologic Setting 1 is partitioned into six areas on thebasis of geologic data that establish the natural stress and natural fracturedistribution of these Devonian shales. These partitions were validated with 40years of cumulative gas production data. Table 1 lists the counties included ineach of the six partitions. Reservoir parameters for each partitioned area wereused in a finite-difference, dual-porosity, single-phase gas reservoirsimulator to predict horizontal-well gas production over 10 years. Predictedproduction production over 10 years. Predicted production was then used in acash flow model to determine economic parameters at different gas-pricescenarios. EMV calculations were performed with Devonian shale success ratiosperformed with Devonian shale success ratios compiled by the West Virginia Geological and Economic Survey for the U.S. DOE (see Table 2). The EMV analysiswas completed at each gas-price level for all the areas. Each horizontal-wellproject was then ranked on the basis of its respective EMV value, with thesites showing the highest EMV's considered the best candidate areas forhorizontal-well development. The simulator used in this study can account fordesorbed gas in naturally fractured Devonian shale reservoirs. An input datatable of reservoir pressure vs. adsorbed-gas content is used when theadsorbed-gas option is turned on. This table represents results from thelaboratory measurement of gas content from more than 2,000 Devonian shale coresamples taken from selected wells in West Virginia. Ranking Method-EMV Theory Reservoir properties play an important role in predicting the future gasproduction and, ultimately, the profitability of a venture in a gas reservoir. Reservoir properties, such as pressure and pay-zone thickness, and previoussuccess rates are fixed at the start previous success rates are fixed at thestart of a project and thus can be considered "noncontrollable"variables during the project's life. This study also considers project's life. This study also considers horizontal-well length, drainage area, azimuth, typeof horizontal well (medium radius), and topography as noncontrollablevariables. However, values assigned to gas price and drilling costs can varyfrom start price and drilling costs can vary from start to completion of aproject. Gas price usually covers a range of values during the project's lifebecause annual gas prices fluctuate with gas supply and demand and inflation. Therefore, these values can be considered "controllable." Thus, cashflow levels can be predicted from ranges of gas production predicted fromranges of gas production values obtained from a reservoir simulator. As projectcash flows become known at different gas-price levels, these values are used in EMV calculations as part of the project-ranking method. project-ranking method. Horizontal-well projects are ranked by following the same principles used torank vertical-well projects. The EMV concept is widely accepted as a logicalmethod for ranking projects, based on the expected value (future cash flow) orprofitability of a project.
This study is a comparative evaluation of predicted gas production from horizontal, high-angle, and vertical wells in the tight, fractured Devonian shales of West Virginia. The optimal drilling method was determined by economic and production comparisons of simulation results from studies of unstimulated and stimulated wells of the following types: a single horizontal well, a single high-angle well, and up to four vertical wells. Infill drilling was compared to new-lease wells, and the effect of faulting on predicted gas production was studied. The study showed that new-lease horizontal drilling is the optimal method in West Virginia, and high-angle drilling results in a slight improvement over vertical drilling. Horizontal drilling showed as much as a 46 percent improvement in production performance over both vertical and high-angle drilling for new-lease wells. Economically, a single 2,000-ft (6.096 × 102 m) horizontal well revealed a ROR of 40 percent and payout of 1.6 years as compared to 11.2 percent, 4.9 years and 4.1 percent, 7.8 years for single new lease vertical and 60° high-angle wells, respectively.
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