Abstract Conventional wisdom developed throughout many years in the oil industry indicates that a single, closed reservoir can have only one single well-defined water oil contact. Although the contact could appear in some instances to be tilted because of capillary effects, it is still a single water-oil contact. I have observed some instances where a single closed naturally fractured reservoir has two (and even three) different well-defined water oil contacts. This paper gives some ideas to how this can happen. The principles do apply to the case of multiple gas-oil contacts in a closed reservoir, and could be applied in the case of non-fractured reservoirs. I present some guidelines to handle this problem in numerical simulation attempts. The reason is because most numerical simulators will raise an "error flag" if an engineer attempts to input more than one contact within the same simulation in a closed reservoir. Introduction The geological and engineering literature is full of examples showing that single closed reservoirs can have only one well-defined water-oil contact. In fact, the geological/engineering literature has mentioned that having a single water-oil contact is an indication that there is only one oil and/or gas reservoir. Having two or more well-defined water-oil contacts is our indication that there are two or more separate reservoirs. Due to the confidentiality of the data I have examined and the controversial nature of this paper, I have changed the name of the formations where I have observed this phenomena. CONVENTIONAL THEORY Figure 1 shows an example of multiple water-oil contacts (more than 20 WOC's) in separate reservoirs. The example was published on page 239 of Levorsen's book, Geology of Petroleum 1 , from where I quote: "Section through the Santa Fe Springs oil field, California, an example of how many separate traps, holding many separate pools, are formed by one fold. The lack of connection between the different reservoirs is shown in the different water-oil contact level for each productive sand." Figure 1 shows what is conventionally expected. Different water oil contacts in separate pools. But is it possible to have one single, closed reservoir and different water-oil contacts Figure 2A presents a well-accepted case of secondary hydrocarbon migration through the reservoir that does not necessarily end with the first trapping2. In stage one, gas, oil and water are segregated by gravity and all three phases are above the spill point. In stage two, oil reaches the spill point and migrates farther up-dip. In stage three, the anticline is filled with gas. Any oil migrating up at this time will bypass the trap entirely. Continuation of the same sequence of events throughout buoyancy will lead to the four traps in tandem presented in Figure 2B.This is a well-accepted case of multiple gaswater, gas-oil-water, and oil-water contacts in four traps connected with the same aquifer. The cross-section shown on Figure 3 is a corollary from the trapping concept presented in Figure 2 . Originally the trap is full with water. Oil migration occurs up-dip following the white arrow until it reaches level WOC1 close to the sealing fault.

Abstract Nearly twenty years of research and field testing has resulted in the development of Hydratherm ™' s hybrid drilling system, which uses ultra-high pressure (UHP) drilling fluid jets and / or a variable thermal spallation gas jet. The gas jet subjects the host rock to pulsed heat fluxes at temperatures ranging from 20 °C to 1,100 °C, producing thermal expansion and strength reduction of the rockforming minerals. The UHP jets then quench, cut and erode the rock momentarily after heating. The combined mechanisms enable ultra-fast rock penetration (20–50 m/hr in hard rock) by means of spallation, erosion, fracturing, chipping and cutting. This technology has exciting applications in heavy oil recovery. Introduction The Hydratherm system can be employed for drilling oil, gas or geothermal wells. It may also be adapted for mining, boring, tunnelling or the cutting of chambers and will operate at great depth. Together with other Hydratherm technologies, it can be employed in heavy oil recovery. These include faster and cheaper well drilling and the economical thermal treatment of heavy oil reservoirs, especially those at great depths. The latter is achieved by the creation of deep fractures and cavities in hot dry rock (HDR) to produce supercritical (> 380 °C) steam at critical pressure (3,204 psi) for injection into the shallower oilbearing formations above. Employing similar techniques, the drilling system may also be used for the economical production of geothermal steam as a source of energy. Other applications include subterranean incineration or storage of hazardous wastes, subterranean storage of volatile liquids or water, large-scale tunnelling, microtunnelling, conventional mining and quarrying. This paper describes the drilling technology and how it can be used for developing heavy oil reserovirs. BRIEF OVERVIEW OF THE DRILLING SYSTEM The system comprises a hybrid rotary head drilling system in which a supersonic thermal gas jet is superimposed upon multiple pulsed or continuous ultrahigh pressure (UHP) hydrojets. The latter deliver a special surfactant solution to the rock surface which acts as both cutting medium and drilling fluid. The gas jet (the "Hypertherm" system) or the UHP hydrojets (the "Hyperjet" system) may be used independently or simultaneously (the "Hyperdrill" system). In the latter case a combination of thermal gas jet heat flux spallation and UHP hydrojet erosion/cutting are used to penetrate the host rock. Figure 1 shows the drilling assembly. The hot thermopulsing gas jet induces intense thermal stress at the rock face. Spallation occurs and this, together with the action of the superimposed pulsed UHP hydrojets, produces small rock chips which are blown out of the well by exiting combustion gases. The cutting and erosive actions of the hydrojets are assisted by the thermal reduction of rock strength that takes place due to the heat flux delivered to the rock surface by the spallation gas jet. The heat fluxes are delivered intermittently, imposing a variable temperature field, whilst the actions of the spallation gas jet and multiple hydrojets combine in such as way as to produce cyclic heating and quenching. This maximizes the thermal shock effects at the surface of the host rock.

Abstract The tight gas resource potential in the Western Canadian Sedimentary Basin is enormous. To date, however, it remains relatively unexploited and underdeveloped. The use of multiply fractured horizontal wells (MFHW) appears to be the "breakthrough" technology needed to economically exploit reasonably thick tight gas zones with effective in-situ permeabilities between 0.1 mD and 0.005 mD. This exploitation technology is already being applied in Europe and, in a more limited extent, in the U.S. Its application in Canada is currently being tested and/or evaluated by several of the larger majors. (This technology also has the potential for enhancing the deliverability of conventional gas.) An analytical model has been developed to predict the deliverability and production forecast of a multi-fractured horizontal well in a tight gas pool that includes the initial, transient production period. Using the DTC (discounted technical cost) approach to evaluate the economic feasibility of tight gas resources, the majority of the deep, high pressure tight gas evaluated in this study appears to be commercially viable, even at today's gas prices. Advances In Tight Gas Production Technology Historically, the development of tight gas reservoirs has involved drilling vertical wells and hydraulically fracturing them, often with the use of large amounts of proppant. These large fracs are known as massive hydraulic fracs (MHF) and typically involved hundreds of thousands or even millions of pounds of proppant. Quasi government bodies in the United States, such as the Gas Research Institute (GRI) and the Department of Energy (DOE), have been heavily involved in promoting research into the production of tight gas sands (Ref. 1). The GRI and Advanced Resources International (Ref. 2) have highlighted four key new technologies which they believe have the greatest application for the efficient development of tight gas sands: 3D Seismic Integrated Approaches to Natural Fracture Detection Improved Well Completions/Stimulations Selected Use of Horizontal Wells We believe that multiply fractured horizontal wells (MFHW) is one such technology. Spencer (Ref. 5) surmised that natural fractures played a key role in the production of most tight gas reservoirs so that if the extent and direction of the natural fractures can be predicted and is sufficiently intense and laterally extensive, horizontal and/or multi-lateral wells can be used to promote otherwise uneconomic pay zones. The logical corollary to this is to question whether a network of induced fractures from a horizontal well could be used where the natural fissuring has limited development; and, particularly, where the stress regimes allow the resulting induced fractures to intersect the natural fissuring. Multiple Fractured Horizontal Wells (MFHW's) Mobil patented this stimulation concept in 1973 and applied it in deviated wells (Ref. 3). The technique was first applied in a horizontal well in 1987 by ARCO in the Spraberry formation. In October 1988, Mobil also successfully performed five fracs off a horizontal oil well in the Spraberry formation at 2420 m in John Snowden #7 near Midland, Texas (Ref. 5). However, these first two attempts were reportedly technical successes but economic failures.

Abstract For predicting the performance of water injection in naturally fractured reservoirs, scale-up of the recovery data from immersing an oil-saturated core into water is commonly used. Oil recovery from some of the naturally fractured reservoirs of the North Sea has been better than what is predicted using the immersion laboratory experiments. In the field, the matrix blocks do not become surrounded by water at once; they experience an advancing fracture-water level (FWL). In this paper, the results of experiments of water injection in fractured porous media comprised of a number of water-wet matrix blocks are reported for the first time. The blocks experienced an advancing fracture-water level (FWL). Immersion-type experiments were performed for comparison. The experiments revealed that the dominant recovery mechanism changed from co-current to counter-current imbibition when the boundary conditions changed from advancing FWL to immersion-type. We performed single block experiments of co-current and counter-current imbibition and found that co-current imbibition leads to faster oil recovery. This difference may explain the improved recovery observed in the field, when the blocks are experiencing an advancing FWL. Chalk and Berea sandstone were investigated. A column of three blocks of Berea sandstone (Φ =0.22, k=620 md, pore volume (PV)=8800 cm 3 ) and a stack of 12 blocks (4 rows and 3 columns) of an outcrop chalk (Φ =0.30, k=2–5md, PV=13,900 cm 3 ) were used. Breakthrough recoveries were 0.2–0.4 for the Berea and 0.2–0.6 of PV for the chalk experiments. Corresponding ultimate recoveries were around 0.5 and 0.65 of PV. Surprisingly, oil recovery from low permeability chalk was better than that of Berea. Fracture apertures in all the above experiments were in the range of 150–200 μm. Another unique feature of the experiments was utilizing a transparent core-holder, which permitted measurement of FWL and visual identification of the active imbibition mechanisms. An approximate mathematical model was developed for counter-current imbibitions. It was found that the late-time matrix--fracture transfer function simplifies to an exponential function. Hence, the physical significance of the empirical transfer function of Aronofsky et al. (1958) was demonstrated. The transfer function was incorporated in a model, which was used to match the water injection experiments performed on a stack of very low permeability Austin chalk (Φ =0.05, k=0.01-0.05 md, PV=287 cm 3 ). These experiments were dominated by counter-current imbibition Introduction Water injection is known as an important method for oil recovery from fractured reservoirs. In water-wet fractured reservoirs, the capillary pressure contrast between the fracture and the matrix media provides the main driving force for water imbibition, which can be an efficient recovery mechanism 1 . Field application of water injection in fractured reservoirs has been implemented since the early fifties 2 . Many issues, however, remain unresolved in the understanding of this process. Since the early studies, it was understood that recovery behavior from a block totally covered by water is different than the same block in contact with water from some faces and with oil from other faces 2 . However, the majority of studies have centered on immersion type boundary conditions 3 .

Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains 10 layers that are naturally fractured. The 10-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the 2 layers with the largest permeabilities. If this is used in reservoir studies, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized during a drawdown by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shutin. Introduction Outcrop information, imaging logs and production logs, have shown that in some cases naturally fractured reservoirs are composed by many layers 1 . The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1 . A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft perforated in a fractured reservoir only 5 to 10 ft contribute production into the wellbore even if the 100 ft are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures 1 . One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al 2 . There was no communication between layers except at the wellbore. Later Russell and Prats 3 studied the practical aspects of interlayer cross flow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow. Prijambodo et al 4 studied the early time performance of a well in a reservoir with cross flow and concluded that the pressure behavior was remarkably different from that of an equivalent single layer system. They indicated that the early time response could be divided in flow periods.

Abstract Hydraulic fracturing has become increasingly popular in high permeability gas reservoirs in order to reduce apparent skin and thus improve well productivity. The remaining post fracture rate dependent skin effect varies from case to case and it is unclear whether this is a result of non-Darcy flow in the fracture, the reservoir or both. This paper presents a study of the effects of reservoir and fracture turbulence in fractured gas wells. First, a quantification of the fracture length required to eliminate the effects of reservoir turbulence is obtained by means of a numerical study. A similar study with non-Darcy flow in both the reservoir and the fracture results in a correlation of fracture length required to get zero apparent skin at 75% of AOF as a function of reservoir permeability, pressure, fracture conductivity and β factor. Introduction As shown first by Forschheimer (1901) flow through porous media deviates from the linear Darcy's law and can be described by a quadratic equation with a non-Darcy flow coefficient β in the non-linear term. The coefficient β has been correlated to reservoir permeability by numerous authors; in general β decreases with increasing reservoir permeability. Experience has shown that the non-Darcy term becomes more significant in higher permeability gas reservoirs. Generally for reservoir permeabilities below 1 mD there is little effect from non-Darcy flow. In higher permeability reservoirs non-Darcy flow can significantly restrict well production rates and may also affect the pressure transient response. Hydraulic fracturing has become increasingly popular in high permeability gas reservoirs. Normally the goal for hydraulic fracturing high permeability gas wells is to bypass skin damage and thus increase initial flow rates. These ‘skin’ fractures are generally small in nature and may or may not include high-grade proppants. Prior to performing such a treatment there is often evidence to support a high permeability reservoir and a high apparent skin. Unfortunately there is rarely enough data to distinguish if this skin is a true mechanical skin or rate dependent (non- Darcy) skin. Post fracture analysis may show apparent skins ranging from slightly stimulated to neutral to positive. If a multi-rate post fracture test was performed it is sometimes possible to separate mechanical skin from rate dependent skin. The basic problem with applying the rate dependent skin analysis to a fractured well is that the rate dependent skin was developed based on the assumption of radial homogeneous flow into the wellbore. By adding a hydraulic fracture the flow regime has been altered and the theory breaks down. It is unclear whether the rate dependent skin is occurring in the linear fracture flow or in the reservoir or in both. The primary purpose of this study was to quantify when reservoir turbulence is insignificant for a fractured well. The second purpose was to provide a simple method for predicting post fracture rates in high permeability reservoirs taking into account fracture turbulence.

Abstract In order to determine the technical and economic feasibility of carbon dioxide (CO 2 ) flooding the naturally fractured Spraberry Trend Area reservoirs in west Texas, a team with multiple disciplines was formed A thorough geological study has been performed based on analyses of thin sections, core samples, and open- and cased-hole logs. A rock-log model has been developed for identification of pay zones in the reservoirs. The natural fracture system has been characterized based on horizontal coring. Fracture intensities and orientations have been determined. Permeability anisotropy was estimated based on pressure transient data from well testing. The anisotropic permeabilities have been used in numerical simulation of a waterflood pilot in the field. Successful history match has been achieved Laboratory water imbibitions tests have been conducted to understand the waterflooding performance in the reservoirs. An analytical model has been developed for scaling-up the imbibitions data to field scale water flood. Good agreement has been observed between up-scaled imbibitions data and oil production decline in the oil field The result indicates that the weakly-wet Spraberry sands are partially responsible for the low performance of water flooding in the Spraberry Trend Area reservoirs. Possible effects of stress-sensitive fracture conductivity and formation damage on oil productivity of wells have been analyzed using a newly developed analytical model. The result indicated that the stress-sensitive fracture conductivity was partially responsible for the fast productivity decline during the primary production. The efficiency of CO 2 flooding the reservoirs have been investigated in the laboratory using whole cores, reservoir oil, synthetic reservoir brine, and CO 2 under reservoir conditions. Results of oil recovery from low permeability Spraberty cores during CO 2 injection experiments are promising. A mathematical model has been developed for scaling-up the laboratory CO 2 ternary oil recovery to pilot scale to assist pilot design. The result indicates a good potential of CO 2 flooding in the reservoirs. After two years of team work, we have gained significant understanding of the naturally fractured reservoirs. The CO 2 flooding pilot is being carried out. This paper presents our integrated geology-reservoir description and modeling of the naturally fractured Spraberry Trend Area reservoirs for CO 2 flooding. Introduction Carbon dioxide (CO 2 ) injection is a proven technology to enhance oil recovery. Every CO 2 flood reviewed in the literature reported improved oil recovery. 1 Because of the success of CO 2 , reservoirs which were previously believed to be poor candidates for CO 2 injection are now being considered as potential targets. This is especially true in the case of naturally fractured reservoirs. Historically, the perception of rapid channeling of injected CO 2 to production wells precluded the concept as too risky. However, laboratory evidence 2 and a pilot test in the naturally fractured Midale reservoir 3 has opened up the possibility that naturally fractured reservoirs may be better candidates for CO 2 injection than previously believed. Naturally fractured reservoirs are, by nature, characterized by low permeability matrix. Permeabilities in tight gas sands or coal bed methane have been recorded in the microdarcy range. Naturally fractured oil reservoirs are often characterized by matrix perrneabilities in the submilidarcy range.

Abstract High water-cut in the produced fluids is one of the major problems facing the petroleum industry. We have developed the concept of using swelling clays for water shut-off in high permeability channels such as fractures and wormholes. In this process, swelling clays are mixed into aqueous solutions and the clay slurry is injected into high permeability channels. When contacted by formation water, the clay slurry will gel and block the fluid flow. Critical to this concept is a cation exchange process. The water composition used to make the clay slurry is controlled such that the smectite clay will not swell during mixing. This ensures that the clay slurry can flow and be pumped before entering reservoirs. Once in the reservoirs, the formation water will trigger a spontaneous cation exchange process. This will turn the clay slurry into a clay gel and subsequently block fluid flow. Systematic laboratory experiments were conducted to test this process. With a small amount of inorganic additive, a clay slurry with up to 40 wt% clays can be made to flow. Rheological properties of this clay slurry indicated that it could be easily injected into fractures and wormholes. After the cation exchange, the resulting clay gel can resist a pressure drawdown of 100–500 kPa/m in a fracture with an opening of 1 cm, and 60–300 kPa/m in a wormhole with a diameter of 5 cm. This gel strength should be sufficient for most field applications. The feasibility of using clay gel for water shut off was further demonstrated by a series of two-dimensional visualization experiments. The clay gel system is very economical and has good chemical and thermal stability. The limitations of this system are 1.) the salinity of the formation water has to be low (< 5 wt%), and 2.) the system is only applicable for blocking fractures and wormholes. A patent application for this process has been filed in both the USA and Canada. Field evaluation is underway. Introduction High water-cut in produced fluids is a common problem in the petroleum industry around the world. In Alberta alone, 460 million cubic meters of water were produced in 1996 1 . This is about 6 cubic meters of water for every cubic meter of oil produced. In US, water cut is more than 8 times oil cut in produced fluids 2 . In heavy oil production, the problem of watering out is more serious because the mobility ratio (of water to oil) is higher and water breakthrough is easier. Polymer gels have been used for water shut-off and conformance control in the field. For permeability modification and water shut-off in naturally fractured reservoirs, polymer gels have achieved a considerable amount of success 3,4 . However, polymer gels formulated for permeability modification (e.g. MARCIT) may not have sufficient strength to block big fractures and "wormholes" found in heavy oil reservoirs. The polymer gels formulated for total zone isolation (e.g. MARA-SEAL) have sufficient mechanical strength but may invade deeply into the pay zone. The polymer invading the pay zone will not only be wasted but will also plug off the pay zone.

Abstract Optimum fracturing is very important and what reservoir managers expect in order to exploitate reservoirs effectively. It is difficult to both reservoir managers and service operators to assess a treatment whether an optimum one because a underground fracture is invisible and immeasurable. Previously some individual techniques such as shut-in pressure analysis and well test after a treatment were presented in the evaluation of hydraulic fractures. However, using all the techniques in one evaluation and comparing the different results are not reported to our scope. Several evaluating techniques have been integrated and a software platform has been developed to evaluate a hydraulic fracture using recorded information during injecting and the tested data after a treatment. These techniques include treatment simulation, pressure decline analysis, transient well test and the evaluation of production performance. A case is investigated by these techniques and the comparison and comments are presented in this paper. Ability to understanding a hydraulic fracture has been improved a lot and the confidence can be enhanced in further optimum designing and treating having these integrated techniques. Introduction Economic optimum of hydraulic fracturing is what people expect in petroleum industry. To achieve this goal much work was done in past more than ten years. Veatch [1] firstly outlined the concept of optimization of hydraulic fracturing treatments on the basis of NPV(net present value). Following Veatch's study Warembourg [2] gave out the detail and general steps for optimizing hydraulic fracturing treatments. Then many applications in determining and practicing optimum fracturing have been attempted [3]-[7] and now many methods and rules to determine optimum fractures are widely used in the industry. However, although a optimum treatment or fracture can be planned very well and designed very accurately before operating it is still questionable and difficult to answer that whether a proppanted fracture is optimum and a fractured operation is the best one because a underground fracture is invisible and immeasurable directly. In addition, a practical fracture usually differs from a designed one as in-situ parameters are not completely the same as those used in the design. Therefore, the evaluation of a existing fracture or a treatment is very important to both reservoir engineers and service operators. Recent years much effort has been made in order to assess existing fractures and fracturing treatments [8]-[21] and now many evaluation methods are available. The methods include well test, pressure decline analysis, treatment simulation and performance evaluation etc.. In order to evaluate fracturing treatments and fractured fractures comprehensively, a integrated software platform called AFDDE (Acidizing & Fracturing Design, Diagnosis and Evaluation) is developed based on the above analyses, which is financially supported by service companies. This paper presents the main analysis techniques in the platform and a case application. FRACTURE EVALUATION TECHNIQUES The information feeding back from treatments and fractured fractures is treatment records (including treating pressures, rates, and pressure decline after shutting in etc.), production performance after treatments and pressure build-up or pressure down test data after treating. In according to the different information, a suitable interpreting techniques may be selected.

Abstract The using of horizontal wells is an effective exploitation way for naturally fractured reservoirs. In accordance with horizontal wells in a naturally fractured volcanic reservoir, the characteristics of damages from drilling, completion and natural blockages are discussed and the aim of acidizing is outlined in this paper. The method to determine segment length and position and treatment parameters are presented for segment acidizing. The three-dimension unsteady acid flow model, acid flow heat exchange model and acid-rock reaction model are established and a semi-numerical calculating method is utilized in order to simultaneously predict the distribution of acid velocity, temperature and concentration during acidizing treatments. The well completion and the segment acidizing design are presented for a horizontal well in a naturally fractured volcanic reservoir of a oil field in western China. Introduction Horizontal wells have been widely used in petroleum industry [1][2] because they have higher economic efficiency and advantages over vertical wells such as controlling sand, delaying gas or water coning and preventing turbulent flow around the wellbore etc.. They are very attractive to be used to exploitate anisotropic reservoirs [2] like naturally fractured reservoirs, because they have more opportunities to channel through fractures as natural fractures are generally vertical and they have longer wellbores in pay zone. However, the formation damage will be more severe in horizontal wells than in vertical wells because of the longer exposure time and higher mud density to maintain the stability of bore hole. The damage impact on the production index of horizontal wells has been investigated [3][4] . The results shows consequence matrix stimulation treatments are required to increase the flow profile across horizontal section. The use of coiled tubing is the recommended method for the matrix stimulation of horizontal wells as it can provide a necessary mechanical isolation and diversion for uniform coverage along a horizontal well [5] . The optimal rate of coiled tubing withdrawal was given by Economides et. al. [4][5] for matrix acidizing of horizontal wells. As coiled tubing stimulation can not exercise a well effect in naturally fractured reservoirs where diverters would lose their functions another acidizing method such as segment acidizing should be used. This paper presents design method of segment acidizing and treatment consideration for horizontal wells in a naturally fractured volcanic reservoir. The provided method may be applied in other naturally fractured reservoirs as carbonate reservoirs. RESERVOIR CHARACTERISTICS The studied reservoir was produced by paroxysmal eruption and its rock is mainly vitric and sedimentary tuff with frequently natural fractures of middle to high angles. The fractures have width of 0.5-5.0mm according to the core investigation and are seriously filled with calcite, float stone and chlorite etc.. The reservoir is driven by dissolved gas. The other parameters of the reservoir are shown in table 1. Horizontal wells were selected to develop this reservoir after compared the economical efficiency of horizontal wells with that of vertical wells. FORMATION DAMAGE There are two main damage sources for horizontal wells in naturally fractured reservoirs. One source is natural blockages in fractures, which were produced while they were formed and the other is from drilling, completing, workover and producing.

Abstract Approximate equations are presented for evaluation of naturally fractured gas condensate reservoirs represented by dual-porosity models in radial systems. The reader is cautioned that this work is in progress. Additional research will help to corroborate and refine these techniques. The solutions have not been published previously in the petroleum engineering literature. The solutions are presented for drawdown and buildup tests. The model assumes flow of gas condensate from a tight matrix into permeable natural fractures. The fractures conduct the fluids to the wellbore. It is preliminary shown that a conventional cross plot of m(p) vs. time on semi logarithmic coordinates results in approximately two parallel straight lines with a separation that is related to the storativity ratio between fractures and matrix. This plot allows determination of key parameters such as absolute permeability, effective permeability's to oil and gas, skin, storativity ratio (ω), fracture porosity (Φ 2 ), average distance between natural fractures (h m ), radius of investigation, and extrapolated pressure (p 1 or p). In addition the method permits generating a liquid saturation profile and a general composition profile around the wellbore at shutin. Introduction Naturally fractured reservoirs have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov (1) and Warren and Root (2) handled naturally fractured reservoirs by assuming pseudo steady-state (restricted) interporosity flow in a model made out of cubes with spaces in between. Flow toward the wellbore was assumed to be radial via the natural fractures. Their work led to the conclusion that a conventional cross plot of pressure vs. log of time should result in two parallel straight lines with a transition period in between. The separation of the two straight liens allowed calculation of the storativity ratio omega, i.e. the fraction of the total storage within the natural fractures. Kazemi (3) used a numerical model of a finite reservoir with a horizontal fracture under the assumption of unsteady state interporosity flow and substantiated Warren and Root's conclusion with respect to the two parallel straight lines. The transition period, however, was different due to the unsteady rather than pseudo steady-state interporosity flow assumption. de Swaan (4) developed a diffusivity equation and analytical solutions to handle the first and last straight lines. His method, however, could not analyze the transition period. Najurieta (5,6) developed analytical solutions of de Swaan's radial diffusivity equation which could handle the transition period as well as the first and last straight lines. Streltsova (7) used a gradient flow model and indicated that the transition period should yield a straight line with a slope equal to ½ the slope of the early and late straight lines. Her examples showing the ½ slopes gave values of storativity ratios approximately equal to 0.37, 0.26, and 0.48. Serra et al. (8) reached the same conclusion with the use of a stratum model for the cases in which the storativity ratio, omega, was smaller than 0.0099. Various type curves have been developed to analyze naturally fractured reservoirs with transient (9,10) and pseudo steady-state (11) interporosity flow.

Abstract Hydraulic fracturing of low permeability reservoirs with multiple fractures is an effective stimulation treatment in the serial techniques of horizontal well production. The comprehensive mathematical model of predicting the production performance of a hydraulically fractured horizontal well with multiple fractures, combined the reservoir model and type of reservoir derive with the hydraulic fracture model is first established in this paper. The numerical models and the corresponding solution are first derived. Both fracture performance and reservoir performance in the transient producing period or pseudosteady producing period are taken into account. These models are applied to simulate the pressure performance of reservoir and multiple fractures in the horizontal well, to forecast the well production in the transient producing period and pseudosteady producing period. This paper investigates optimization of fracture numbers in the horizontal well, added the fracturing economic evaluation model to the comprehensive mathematical model. A case study is shown which demonstrates the method of forecasting production and optimizing fractures numbers. These models and the methodology can be employed in fracturing design of a horizontal well and evaluation of fracturing effectiveness. Introduction Hydraulic fracturing of horizontal wells, which enhances the oil reserves in the low permeability reservoir and keeps the oil wells high productivity is becoming an effective stimulation treatment in the serial techniques of horizontal well exploitation. Forecasting the production performance of a hydraulically fractured horizontal well plays an important role in the optimization design of hydraulically fracturing the horizontal well, furthermore it is the main basis of evaluating the effectiveness of post-fractured wells. Segment fracturing in the horizontal wells commonly induces multiple fractures which are oriented near the wellbore. Predicting the production performance of a fractured horizontal well with single fracture or several fractures can be used to determine the optimum fracture numbers and to improve the design of hydraulic fracturing treatment. This paper first presents the comprehensive mathematical model of predicting the production performance of a hydraulically fractured horizontal well with multiple fractures. The reservoir model, type of reservoir drive and hydraulic fracture model are included in the comprehensive model. Both pressure behaviors in the fractures or in the reservoir and well production in the transient producing period and pseudosteady producing period can be simulated. The fracturing economic evaluation model is introduced to investigate the optimization of numbers of fractures in fractured horizontal wells. A case study is presented which demonstrates the method of forecasting production and optimizing fracture numbers. These models and methodology can be employed in fracturing design of a horizontal well and evaluation of fracturing effectiveness. ESTABLISHMENT OF PHYSICAL MODEL Assumptions The object of this study is shown in figure 1 in which a fractured horizontal well with multiple fractures is located in the rectangular reservoir. The following assumptions are involved in the derivations of the mathematical model. The fractures are perpendicular to the wellhole and vertically penetrate the partial reservoir thickness. The horizontal well fully penetrates the reservoir or unfully penetrates the reservoir.

Abstract This paper presents an analysis of present day initial stress states in the Upper Cretaceous formations overlying the heavy oil deposits of Northeastern Alberta. Two models based on elastic unloading of Pleistocene glacial ice sheets are presented to predict the dependence of present day initial stress ratios with depth. The results of the both models are consistent with published in situ stress data in the region. These computed stress ratios were used to calculate the maximum slip on an inclined interface where the shear resistance has been eliminated by hydraulic fracturing. The finite element program ABAQUS was used to compute the maximum slip at the interface. The magnitude and the direction of the slip is dependent not only on the interface inclination but also on the stress ratio. The material above the fracture will slide up-dip when the stress ratio is greater than 1 and down-dip when the stress ratio is less than 1. There is no slip when the stress ratio equals to 1. Introduction Fluid or steam injection into bitumen oil sand reservoirs is often used to stimulate or assist viscous heavy oil production. However, fluid injection into the reservoirs is often done above the fracture pressure resulting in the formation of hydraulic fractures. Fluids may also escape into the overlying shale's, causing additional hydraulic fractures above the reservoir. The shear strength along these fractures or interfaces is effectively zero. In the cases where a non-isotropic state of stress exists in the vicinity of inclined interfaces, the removal or reduction of the shear strength will cause stress redistribution in the formation and will likely cause relative sliding along the fracture. The stress redistribution and associated deformations may induce wellbore casing failures. The sliding along injected interfaces or natural fractures depends on the stress states at the plane before the fluid injection. More specifically, it depends on the direction and magnitude of the shear stress on the plane. The principle directions of the present day stress fields are generally aligned with or close to vertical and horizontal directions. Elastic theory dictates that shear stresses are absent on the principle stress planes. Therefore reduction of shear strength on horizontal or vertical planes normally will not cause any significant shear deformations. However, this is not the case for inclined planes. The magnitudes of the present day shear stresses along inclined interfaces depend on the angle of inclination and the difference between the maximum and the minimum principle stresses which can be calculated from the effective horizontal to vertical stress ratio. For normally consolidated conditions, the stress ratio is empirically defined by Jaky's rule 1 and is always less than 1. However, normally consolidated conditions are rare in nature, particularly in temperate, onshore regions. There are many processes that can create over consolidation. With few exceptions in Northeastern Alberta, the Upper Cretaceous sediments are over consolidated. This state of over consolidation can be attributed to several factors. Tectonic activity during the Laramide Orogeny raised horizontal stresses.

Abstract A newly developed mathematical model has been used for formation damage analyses of two hydraulically fractured horizontal wells in the Daqing field, China, and twelve vertical wells in the naturally fractured reservoirs of the Spraberry Trend Area, West Texas. Application of the model to Daqing horizontal wells indicated that these wells should have 4 to 5 times higher oil production rates if the formation was not damaged The use of the model has captured the characteristics of rapid decline in productivity of the Spraberry vertical wells. Comparisons between the effects of matrix skin and fracture permeability indicated that stress sensitive fracture permeability is responsible for the productivity loss of these wells. This paper provides reservoir engineers with a practical tool for analyzing inflow performance of wells intersecting long fractures. Introduction The Spraberry Trend Area of West Texas was discovered in 1949 and was considered the largest field in the world. The Spraberry Trend Area presents unusual problems for both primary production and waterflooding. After more than 40 years of waterflooding, the current oil recovery is still less than 15 per cent. A model study of a waterflood pilot in the Spraberry Trend Area indicated a NE-SW trend of the major Fractures l . A contrast of 144/1 was required for the major/minor fracture trend permeability ratio to match the pilot response. This strong anisotropic effective permeability implies the existence of well inter-connected, long natural fractures in the Spraberry reservoir. A characteristic of flow in the long natural fractures is the pressure variation along the fracture should be significantly higher compared to that in a hydraulic fracture or a short natural fracture. Unfortunately, a method for analyzing flow behavior in reservoirs with long fractures is not readily available from the literature. Several analytical solutions have been presented for transient flow in fractured reservoirs. 2–8 Numerical models have also been developed for simulating fluid flow in fractured reservoirs. 9,10 However, it is still desirable for reservoir engineers to use steady flow equations for identification of formation damage in the fractured reservoirs. This is not only because the analytical transient flow solutions and numerical simulators are not convenient to use, but also because steady or pseudo-steady flow prevails as the dominating flow mechanism in the lifetime of most oil wells. Therefore, steady flow equations are attractive for formation damage analysis. This paper demonstrates applications of a newly developed steady-flow mathematical model for formation damage identification. This model is utilized for analyzing performance of two horizontal wells with hydraulically induced fractures in the Daqing field, China, and twelve vertical wells intersecting natural fractures in the Spraberry Trend Area, West Texas. Use of the model for matching production data aided in understanding of the productivity of the Daqing horizontal wells and the unusual behavior of Spraberry Trend Area reservoirs. The results of analysis for the Daqing horizontal wells indicate that these wells should have higher potential if formation damage could be removed. The use of the model has captured the characteristics of rapid decline in productivity of Spraberry vertical wells.

Abstract An experimental and numerical study was conducted to investigate the effect of the variable aperture system of an oil sand fracture on its two-phase flow response. The oil sand fracture was induced in core samples along the axis of the sample using the Brazilian tensile test. A Computer Assisted Tomography (CAT) scanning analysis was performed to determine the fracture geometry. The fracture was shown to be a variable aperture system- which, when coupled with capillary dominated conditions, governed the occupancy of each phase in a two-phase system. A numerical program was used to investigate the occupancy and two-phase flow response of the derived aperture distribution. Phase interference was found to be significant with the interface between phases showing an unsteady nature. The impact of this unsteadiness may affect the assumption of relative permeability being a function of saturation alone. INTRODUCTION Heavy oil and bitumen are a major energy resource in Canada, and have become a major focus for the oil and gas industry. The fact that the heavy oil deposits of Canada contain 30 % of the world's recoverable oil indicate the potential is certainly present. 4 The challenge in developing this resource is the difficulty in recovering these highly viscous substances. Thermal recovery has become an accepted method with steam-based recovery drawing much attention. Steam-based recovery methods involve the injection of steam into the reservoir to heat up the reservoir, lowering the viscosity of the bitumen, which increases production rates. Cyclic steam-based recovery processes have become common practice in the thermal operations of the Cold Lake heavy oil reservoirs. 1 The steam injection approach used at Cold Lake encourages fracturing of the reservoir each steam cycle, exploiting the permeability of the fracture instead of relying on a layer of bitumen depleted, permeable oil sand. The high hydraulic conductivity of the fracture enables heat transfer to take place further away from the well, thus, accessing more undisturbed reservoir material instead of depositing most of the heat in a previously heated and bitumen depleted area of the reservoir. In order to optimize this steaming approach an understanding of the medium used to carry the heating agent, the fracture, is essential. The geometry of the fracture, characterized by surface roughness and aperture distribution plays a key role in the permeability of the fracture as well as the flow channels available to the injected mass. A detailed picture of an oil sand fracture, its surface characteristics and their relation to the two-phase flow is needed to better understand and possibly exploit the flow phenomena taking place during and after the hydraulic fracturing process of steam stimulation. According to the authors' knowledge, no work is currently available characterizing an oil sand fracture or proving that fractures in this material can be characterized in a similar manner as to what has been previously studied in rock fractures 1,3,5 . The following study presents an experimental, physical characterization of an oil sand fracture using a Computer-Assisted Tomography (CAT or CT) scanning analysis to visualize the fracture geometry.

Abstract The hydraulic impedance method is a method for estimating the dimension of a downhole fracture by using the reflected waves measured at the wellhead. The method is studied in this paper. By considering the wave motions in Q fractured borehole, the fracture impedance and the wave reflection coefficient are derived. It has been demonstrated that the shape of the reflected wave at wellhead can be calculated numerically by carrying out the inverse Fourier transform on the product of the input pressure pulse and the wave reflection coefficient. The calculated waveforms are in good agreement with the laboratory measurements. The results have also demonstrated that the hydraulic impedance method could provide an accurate estimation on the length and other characteristics of a downhole vertical hydraulic fracture if the input pressure pulse could produce a resonant motion of the fluid in the fracture. Introduction An interesting method for assessing the dimension of a downhole hydraulic fracture was introduced by Holzhausen and his co-authors 1,2 . The method was based on the phenomenon that the existence of a hydraulic fracture along the surface of a wellbore would alter the acoustic impedance of the well bore and change the pressure oscillation characteristics at the wellhead. Thus, the dimension and other characteristics of the downhole hydraulic fracture can be assessed by analyzing the pressure oscillations measured at the wellhead. The method requires one to generate a wellhead pressure pulse propagating downward along the wellbore and to measure the reflected pressure pulse at the wellhead. Since both the pressure pulse generation and measurement are made at the wellhead, it is a convenient and economical method for assessing the characteristics of downhole hydraulic fractures. By solving the one-dimensional fluid wave equation in the wellbore, Holzhausen has shown that the hydraulic impedance, which is defined as a ratio of the pressure and the volumetric flow rate, can be written as Equation (1) (Available in full paper) where, i = ν-1, is a complex number, Z ch = v f /gA w is the characteristic hydraulic wave impedance in the borehole (v f is the wave speed in the fluid, A w is the area of borehole section, and g is the gravitational acceleration), k is the wave number, and r is the wave reflection coefficient. By placing a hydraulic fracture at the bottom (x =L) of wellbore and letting the fracture has an impedance Z f , the reflection coefficient,τ s , at the wellhead (x = 0) can be derived from the above equation to give Equation (2) (Available in full paper) where, the coefficient τ fw is the reflection coefficient at the junction of fracture and wellbore. In Holzhausen's model, the characteristics of hydraulic fracture are represented by a fracture capacitance C f and a fluid flow resistance R f in series, i.e., Equation (3) (Available in full paper) where ω is the angular frequency of the wave. By defining the fracture capacitance as a ratio of the fracture volumetric change ΔV and the fluid pressure head change ΔH and using formulas from a static fracture analysis, the fracture capacitance C f and fracture resistance R f are derived by Holzhausen as follows:

Abstract Mini-frac analysis performed prior to a main fracture treatment is a common procedure for many companies involved in well stimulations. The purpose is to determine instantaneous shut-in pressures (lSIP), fracture closures, and leak-off. If the value for leak-off is high (greater than 0.005 ft/vmin), it can cause early sand-off where only 20–80% of a fracture design is placed. This high leak-off can be attributed 10 two factors: high reservoir permeability or. induced shear fracturing near the wellbore. Reservoirs with permeabilities greater than 100 md have been successfully fractured using fluids with good sand carrying capabilities, high viscosities, and/or low wall-building coefficients. Shear fractures, created dry by bending stress off a hydraulically induced tensile fracture and opened wide by hydraulic fracturing fluids, can show apparent permeabilities in the hundreds of millidarcies, and are capable of easily sanding-off any well. It is the authors' opinion that most shear fractures are created in brittle rock, i.e. sandstone reservoir rock high in quartz (greater than 80% concentration). Most oil sands reservoirs (quam rich) in northern Alberta have shown signs of shearing during high-rate cyclic steam injection and have been responed in the literature. Deeper formations in central Alberta, such as the Basal Quam and Gething show results similar to minifrac analyses performed previously in the McMurray oil sands and can be used to identify the presence of shear fractures. Once characteristic shearing has been detected fracture design is modified to increase sand placement and importantly, to increase gas and/or oil production from the stimulated well. Introduction Well testing procedures have been available for years 1–2 and existing methods will be applied here. More specifically, traditional well test analyses are performed in oil and gas reservoir studies to evaluate the potential for improving economics and/or increasing recoverable reserves. A well-planned mini-frac program 7,8 can determine with reasonable certainty, the Initial Shut-in Pressure (ISIP), fracture closure (minimum stress), fracture height, formation permeability, and leak-off coefficient. A propped fracture treatment is designed using this data and for many reservoirs, the odds are still 50/50 whether the well will sand-off (plug with sand in the wellbore), with only part of a planned treatment placed. The capability of technology to guarantee a fracture treatment going to completion has yet to be developed. Lately, mini-fracs are nearly always performed on problem reservoirs as most of the high-quality reservoirs have already been tapped. A well that sands-off and has not had any previous mini-fracs provides little information. Fracturing by trial and error is costly and does not pass today's economic hurdles. Therefore mini-fracs are a stepwise necessity not a research project. There are good sand-offs and bad sand-offs. A well may sand-off because the formation permeability has been under-estimated and leak-off exceeds fracture growth. Such wells tend to sand-off from the fracture tip backwards to the wellbore (tip screen out). While this type of sand-off is usually undesirable, the propped fracture width is maximized, resulting in maximum fracture conductivity. High permeability wells minimize costs with short fractures.

Abstract Recent improvements in the speed of numerical compositional simulators has made it possible to use a large number of gridblocks to model condensate reservoirs, volatile reservoirs, and gas injection projects. This paper discusses techniques for choosing pseudo components so as to use 4 – 5 pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally fractured reservoir are presented and other parameters which affect hydrocarbon recovery are discussed as part of a parametric study. INTRODUCTION In recent years wells have been drilled to greater depths, resulting in the discovery of gas condensate reservoirs and volatile oil reservoirs at relatively high temperatures. Recently a large amount of research has been conducted to investigate productivity from these oil reservoirs. This research has investigated how to tune an equation of state so as to match the actual phase behavior which is occurring within a reservoir. Studies have reported on the effects of interfacial tension and velocity on gas-oil relative permeability curves. These studies indicate that bench type gas-oil and water-oil relative permeabilities are not applicable to predicting the performance of individual wells in gas condensate reservoirs. Well test data and recent advances in well logging procedures using well-bore imaging techniques have provided tools to better characterize the fracture system which exists in naturally fractured reservoirs. These data have been used in conjunction with stochastic models to describe the fracture network inside of these reservoirs. A parametric study using a number of variables was conducted for this paper. The results from this parametric study are useful in history matching to determine those parameters which, when adjusted, will have the greatest effect on the performance of the reservoir. This study will also suggest modifications which need to be made to numerical simulators so as to better simulate the actual mechanism which are occurring in gas condensate reservoirs. MECHANISM OF FLOW IN NATURALLY FRACTURED RESERVOIRS Fluid flow in naturally fractured reservoirs differs significantly from that in a single porosity system. The numerical simulator breaks the reservoir into two different systems, one a system of matrix blocks which mayor may not have capillary contact and a network of fractures. The simulator basically assumes that most of the flow to the wells will occur through the fracture network which contains a relatively small fluid volume, but high permeability, and that the bulk of the hydrocarbon fluids are contained within the matrix blocks. As reservoir pressure is depleted, the fluids are expelled from the blocks into the fracture system which conveys them to the producing wells. Gas condensate reservoirs initially are at pressures at or above the dewpoint. Once the pressure has been depleted below the dewpoint, liquid will condense and two phases will be present. Once these two phases are present the liquid will not flow in either the matrix or the fracture system until a critical condensate saturation is obtained.

Abstract Multilateral drilling and completion technology is a very fast moving area for the petroleum industry. It is currently being applied or considered for applications in most operating areas of the world. This paper covers both the drilling and completions aspects involved in drilling, casing, and completing a well with multiple drainholes. Drilling systems covered include the Sperry Sun LTBS ™ (Lateral Tie-Back System) and the RMLS (Retrievable Multilateral System) which allows a lateral to be drilling and cased back to the primary wellbore. The paper also covers completions of multiple drainhole wellbores including: lateral completions, lateral flow control and isolation and lateral re-entry during production workover operations, Included in the discussion are several case histories and producing configurations where this technology is applied. Multilateral wells cross normal lines between drilling and production and this presentation will illustrate the strong need for detailed preplanning and an interdisciplinary approach in applying this technology. INTRODUCTION Multilateral wells are the direct result of the advances of in directional drilling, MWD, and LWD. These advances have allowed operators to select the best or most appropriate well profile, geometry, and formation entry points. The economies of being able to select these criteria for the best producing benefit of the formation in order to improve drainage, contact natural fractures, or reduce water production have opened many new opportunities to the industry. Horizontal drilling was the first beneficiary of the advances in drilling capabilities. For the first time, massive amounts of permeable formation rock or natural fractures could be contacted with the drilled borehole to dramatically increase the potential drainage face. Unfortunately, horizontal well geometry applications are not as universally applicable as was first hoped. Formation with features such as layered porosity and shale formations with limited vertical permeability are not drained well with a single horizontal well. Also, problems exist with drawdown in a very long horizontal well. There may be a limit to the effective drainage in a long horizontal section. Production logging has shown that often, only 40–60% of a long horizontal well leg contributes production. Therefore, a longer horizontal section does not always drain a reservoir more effectively, nor does it necessarily provide higher producing rates. FROM HORIZONTALS TO MULTILATERALS The next step in the evolution of this technology was to drill multiple horizontal well legs in a formation from a single wellbore. The most common procedure has been to first drill a single horizontal well, then branching off of the initial wells in open hole to produce two or more (often as many as five) horizontal legs. This provides the benefit of drainage from multiple horizontal laterals as well as the ability to move the drawdown to a central point, in the case of multiple opposing horizontal sections. The drilling capabilities for these types of wells have been developed and improved upon for several years now. There exists a very large number of successfully drilled and completed open hole multilateral wells.

Abstract Enhancing oil extraction from oilsand by hydraulic fracturing technique hasbeen widely used in practice. Due to the complexity of the actual process. Modeling of hydraulic fracturing is far behind its application. Effects of highpore pressure and high temperature combined with complex stress changes in theai/sand reservoir requires a comprehensive numerical model which is capable ofsimulating the fracturing phenomenon. To capture all of these aspects in theproblem three partial differential equations. i.e. equilibrium. flow and heattransfer should be solved simultaneously in a fully implicit (coupled) manner. A fully coupled thermo-hydro-mechanical fracture finite element model isdeveloped to incorporate all of the above features. The model is capable ofanalyzing hydraulic fracture problems in axisymmetric or plane strainconditions with any desired boundary conditions, e.g constant rate of fluidinjection, pressure, temperature and fluid flow/thermal flux. Fractures can beinitiated either by excessive tensile stress or shear stress. The fractureprocess is simulated using node splitting technique. Once a fracture is formed, special fracture elements are introduced to provide in-plane transmissivity offluid. Effectiveness of the model is evaluated by solving simple examples andcomparing the numerical results to analytical solutions. The model is also usedto simulate large scale laboratory hydraulic fracturing experiments. Introduction Hydraulic fracturing technique has been a fast growing technology since itsfirst application in 1947. By 1988 more than one million hydraulic fracturingtreatment had been performed[1], and today this technique is one of the mostimportant methods in enhancing oil extraction from wells. Hydraulic fracturingin oilsand reservoirs plays an even more important role. Due to low temperatureand low permeability of oilsand deposits and high viscosity of bitumen, oil isvirtually immobile[2]; hence any attempt for in-situ oil extraction shouldemploy one of the techniques such as cyclic steam stimulation, in-situcombustion or hydraulic fracturing. Despite the fact that hydraulic fracturing technology has advancedsignificantly over the past fifty years, our ability to design the process hasnot change rapidly. As a matter of fact this technique has been so successfulthat in the past designing the treatment with a high degree of precision wasnot of interest. But as the industry moved towards applications of very highvolume/rate and highly engineered and sophisticated hydraulic fracturingtreatments, the demand for more rigorous designs in order to optimize theprocedure have become more important. On the other hand without a thoroughunderstanding of the physical process and the factors that are involved, ourability for an optimal design is limited. Modeling of fluid flow combined withheat transfer in the reservoir has been used by the industry for a long timeand fracturing process often was designed based on two dimensional closed formsolutions such as Geertsma-deKlerk[3] or GdK in brief and Perkins-Kern[4] and Nordgren[5] or PKN. Most of the flow and heat transfer models are based on thefinite difference method and effects of stresses and deformations in theground, if not totally ignored, is solved in a decoupled or partially coupledmanner with other elements.