The Raageshwari Deep Gas Field is located in the Central Basin High, in the southern part of the Barmer Basin, Rajasthan, India. The major reservoirs are eruptive volcanics and subsequently deposited clastics of Cretaceous - Early Tertiary age. The reservoirs are micro porosity-low permeability gas condensate systems. Exploration wells were conventionally tested with gas production rates of 2–4 MMScf/day at high drawdowns. In the development phase, deviated wells with multi-stage hydraulic fracturing have shown multi-fold improvement in production performance. Volcanic reservoirs are characterized by quick changes of lithofacies both laterally and vertically resulting in strong vertical and horizontal heterogeneity. Unpredictable distributions of pore and fracture networks resulted in variable well performance and productivities. Difficulties in reservoir characterization pose an immense challenge to effective well and reservoir management. Comprehensive reservoir characterization studies were undertaken to unravel the complexity of the volcanic reservoirs and to capture the uncertainties. The workflow integrates data from volcanic outcrop analogues, conventional core (visual description, thin section petrography, geochemistry, RCA, Dean Stark and SCAL), mudlogs (gas shows and chromatography), and wireline logs including dipole sonic, image and NMR logs. Productive reservoir units deliverability was validated with production logs, whereas the effectiveness of hydraulic fracturing was matched with micro-seismic data coupled with seismic attributes (AntTrack volume). Matrix permeability coupled with fracture characterization was used to match well performance. Spatial distributions of reservoir properties were populated by geostatistical techniques incorporating available geometries and flow unit dimensions from analogues and well information. The validity of this approach has been confirmed with most recent wells as blind tests and a successful production test from a deeper unit. The approach also emphasises the importance of integrating different datasets for detailed reservoir characterization leading to increased confidence in effective reservoir management of this complex reservoir.
The efficient design and operation of a geothermal wellbore requires an understanding of the complex interactions of heat transfer, fluid flow, phase change, flow regime change, and steam-water slip. The equations flow and concepts presented here account for those interactions and are used in simulating two-phase steam-water in a wellbore. Introduction The current examination of our country's energy resources has resulted in new and greater interest in geothermal power. There are geothermal installations in New Zealand, Italy, California, Mexico, Japan, U.S.S.R., and elsewhere. Many of these operations have long been producing power from reservoirs that are principally vapor-dominated systems, where essentially dry steam is produced at the wellhead and used directly for power generation. Unfortunately, vapor-dominated systems are relatively rare and current geothermal projects in the U.S. propose to use aquifers that produce hot water or a steam-water mixture. New Zealand is the leader in developing the technology required to operate these two-phase steam-water systems. A typical aquifer, when first discovered, will produce undersaturated water at the wellbore sand-face. produce undersaturated water at the wellbore sand-face. As the fluid flows up the wellbore and pressure is lost, the fluid eventually flashes, producing a steam-water mixture in the well. The two-phase mixture is usually separated at the wellhead, with the steam being used directly to generate power." More advanced designs call for the fluid heat to be transferred to a secondary fluid, such as freon or isobutane, thereby using the potential of both steam and hot-water fractions. potential of both steam and hot-water fractions. The secondary fluid is used to generate power and the condensed water is reinjected into the formation. This approach reduces environmental problems and makes more efficient use of the available thermal energy. The reinjected water maintains aquifer pressure and prolongs the producing life of the field. As production continues over a period of months, the aquifer pressure will usually drop to the saturation point, and fully developed two-phase steam-water flow will be produced by the formation at the sandface. The two-phase mixture then flows towards the surface, experiencing pressure drop and heat transfer. In many applications, minerals are deposited on the wellbore casing where the mixture is flashing. The design, analysis, and operation of geothermal systems requires sophisticated applications of the principles of fluid mechanics, heat transfer, and flow principles of fluid mechanics, heat transfer, and flow through porous media. The mathematical equations that describe a geothermal wellbore will be presented in this paper. The simulation of the combined effects of heat paper. The simulation of the combined effects of heat transfer and two-phase flow in wells has not previously been fully presented. Various portions of the technology have been published, but in a piece-wise fashion. The aim of this work is to develop an integrated approach to the problem, an adequate treatment of which must account for problem, an adequate treatment of which must account for the following effects:Two-phase pressure drop,Flow regime change,Phase change (fluid miscibility),Relative steam-water velocity (slip),Heat transfer from the fluid. All these effects are interrelated. JPT P. 833
A model for predicting pressure distribution in two-phase flow through vertical, inclined, or curved pipes combines the best available correlations for predicting pressure gradients for each flow regime. It has been evaluated statistically against literature data and directly against field data from directionally drilled offshore wells. On the whole, the model performs commendably. Introduction Problems related to two-phase flow are frequently Problems related to two-phase flow are frequently encountered in the design and operation of oil and gas production or storage fields. In addition, two-phase flow technology is of great interest to chemical engineers in dealing with such areas as boilers, condensers, heat exchangers, reactors, and process piping. Many of the concepts and correlations developed piping. Many of the concepts and correlations developed originally for petroleum operations are being extended to other fluids and new applications. The energy shortage, currently so much the focus of public attention, has recently stimulated interest in new areas, many of which closely relate to the current understanding of two-phase flow. Simultaneous long-distance pipelining of crude oil and natural gas, harnessing of pipelining of crude oil and natural gas, harnessing of geothermal energy in the form of steam and hot water, production from offshore locations, pipelining of production from offshore locations, pipelining of LNG, and mining and dredging from the bottom of the oceans are among the new areas where recently developed technology in two-phase flow is being evaluated in the light of economic feasibility. The basic engineering problem in calculating the pressure distributions in conduits subject to pressure distributions in conduits subject to two-phase flow may be spelled out as follows: Knowing the geometry of conduit, physical properties of the two-phase flow system, and conditions prevailing at one end, predict pressure profiles along the pipe. Contributions to solving various aspects of two-phase flow problems have been numerous in the literature. This paper will be limited to an investigation of those pressure-drop models that are currently available for vertical and inclined flow. We shall consider both the quantitative and the qualitative aspects of the models and discuss their extension to inclined and curvilinear flow. Through the years, a number of investigators in vertical two-phase flow chose to correlate both slippage and friction losses by a unique and single energy-loss factor. The results of their efforts fell short of their desired goal because their correlations did not include the effects of all pertinent variables, and, more importantly, they did pertinent variables, and, more importantly, they did not reflect the effect of various flow regimes. Another school of thought is represented by other investigators who chose to define, measure, and predict slip or holdup as an intermediate parameter predict slip or holdup as an intermediate parameter leading to the calculation of pressure drop. This approach, along with considerations of energy balance, led to an interpretation of pressure gradient as a sum of three individual gradients: density, acceleration, and friction. One of the principal reasons for the failure of most vertical two-phase flow correlations was the coexistence of several flow regimes along the same pipe for a given set of operating conditions. JPT P. 915
Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary The purpose of this paper is to summarize what has been learned over thelast several years about infill drilling and to recommend when it should andshould not be considered. In general. the more a reservoir deviates from idealbehavior, the greater the opportunity for incremental recovery by infilldrilling. Introduction Infill drilling of pattern waterfloods has received remarkably littleattention from both the public and professional communities. Given the rightcircumstances. this process can compete favorably with EOR processes on arecovery basis for much less investment and operating cost. And yet, to thebest of our knowledge, there are no research institutes, university projects, government programs, or tax incentives to encourage projects, governmentprograms, or tax incentives to encourage the development and application ofinfill drilling. There is virtually no technical literature on the subject, compared with EOR, and until recently very little field data supported ordenied any claim concerning the benefits of infill drilling. In 1980, vanEverdingen and Kriss provided our industry yet another service by raising acontroversy around infill drilling. Their statement that "infill drilling, ifdone properly, can be used to recover at least as much oil as the U.S. alreadyhas produced" (120 billion bbl [19 X 10(9) m3]) created a controversy thatstill goes on today. Although we believe this statement to be exaggerated forthe U.S. as a whole, it is interesting to note that there are no projects underway to determine just how much could be recovered. As a result of his originalposition papers, van Everdingen was asked by the U.S. DOE to investigate thesubject further. His resulting proof was inconclusive, primarily because of alack of good proof was inconclusive, primarily because of a lack of good fielddata and reservoir description. In 1980, Holm provided a thought-provokingdiscussion of van Everdingen and Kriss' work, but his analysis was limited bythe same lack of field data. At that time, very little technical analysisexisted of infill drilling as an incremental recovery process and themechanisms involved. Holm's estimate of the potential of infill drilling ismuch more conservative: "with our best efforts we could add to U.S. reservesabout 1 to 1.5 billion bbl/yr for about 10 years." In our current times ofreduced reserve additions from exploration. such additions would be mostwelcome. Holm's estimated national average was 34 × 10(3) to 47 × 10(3) bbl[5406 to 7472 m3] per infill well. In 1983. a very significant paper by Barberet al. confirmed Driscoll's 1974 observations of 2 to 8% incremental recoveryfrom infill drilling. Barber et al. analyzed nine sets of field data showingvery positive incremental recovery from infill drilling. Two of the reservoirs, Dorward and Sand Hills, were primary projects and cannot be used for comparisonwith secondary pattern floods. The Howard-Glassock reservoir is a peripheralflood and as such is also not directly comparable. Data from Barber et al., Driscoll, and Ghauri et al. are summarized in Table 1 for a total of 1,323wells with an average incremental recovery of 107.1 × 10(3) bbl [ 17 × 10(3)m3] per infill well. This average is greater than Holm's by a factor of two tothree but is weighted specifically for west Texas carbonates. If Holm's moreconservative estimate is correct, 10 to 15 billion bbl [1.6 × 10(9) to 2.4 x10(9) m3] still a very large number for a virtually unstudied incrementalrecovery process. This represents 2 to 3% of the national original oil in place(OOIP) of 460 billion bbl [73 × 10(9) m3]. Current field data for a limitednumber of projects show estimated infill recoveries of about 5% OOIP. Althoughthe true benefit of infill drilling is unknown, its potential is wellestablished. The Natl. Petroleum Council (NPC) published a study on EORpotential in the U.S. in 1984 that concluded that "as much as 14.5 billion bblof additional oil could ultimately be recovered with the successful applicationof existing EOR current technology, under current economic conditions." JPT P. 229
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