Abstract Even though it has long been recognized that pressure drop along a horizontal wellbore cannot be neglected, little has been done to estimate the pressure drop with any rigor. The existing models are derived jPom pipeflow equations, neglecting, therefore, the presence of radial fluid movement perpendicular to the direction of bulk fluid flow. Recent experimental studies indicate that such a simplistic approach provides an optimistic behavior in a horizontal wellbore. This paper presents a realistic representation of the pressure drop in a horizontal wellbore. Equations are derived from rigorous experiments conducted earlier and reported in the literature. They include the effect of radial fluid movement, perforation flow, gas-oil ratio, oil viscosity, bulk flow rate, water saturation, and even the presence of asphaltenes in the crude oil. Even though the equations are based on experimental results, predictions apply to Jeld situations. This aspect is verified with certain unpublished field data from USA and Canada. Introduction The use of horizontal wells has significantly increased in recent years. However, mathematical modeling of pressure drop in the horizontal well has been neglected in this research. Pressure drop has been found to be a very important aspect of horizontal well analysis. Aziz and Arbabi' pointed out that performance prediction in horizontal wells is considered to be a very difficult task. Ahmed and Badry 2 recognized the increase in horizontal well usage and noted the effects of pressure changes on well productivity. Dikken 3 concluded that the pressure drop in the wellbore cannot be neglected in order to obtain realistic prediction of field performance with horizontal wells. Also, Doan et al. 4 pointed out the importance of pressure drop along the wellbore of a horizontal well, especially during initial production periods of a steam injection process (when the oil viscosity is high). Lackner and Economides 5 noted the importance of pressure changes in horizontal wells by combining vertical and horizontal pressure gradient curves to predict the pressure loss in horizontal wells. However, this study was conducted over the entire length of the well and did not focus on the horizontal portion. Also, this study resulted in pictorial representations of pressure drop instead of algebraic solutions. Many studies on pressure drop in horizontal wells simplify the system by neglecting perforations and multiphase flow. Collins et al. 6 reported a simplistic model for simulating flow in a horizontal well in a field. They used Darcy's law in a dual porosity representation of a horizontal well. This model unnecessarily introduces simplicity and does not deal with wellbore dynamics with any rigorousness. Jelen 7 used a new technique for solving fluid flow equation in different domains independently. This method was particularly useful for modeling a horizontal well in which several domains exhibit different types of fluid flow. This paper deals with the development of simple polynomial equations that may be used to predict pressure drop in horizontal wells. By using past experimental data by Islam and Chakma 8 , it examines the difference between pressure drop in wells with and without perforations and it shows the important role that perforations play.

Abstract Plugging of horizontal wellbores can lead to significant loss of productivity and can nullify, the benefit of a horizontal wellbore that is expensive to create. Cleaning horizontal wellbores is a formidable challenge. The problem is particularly complex for heavy oil formations that show asphaltene, sand and other difficultto- remediate problems. This papers aim is to develop a new technique that can effectively clean up a horizontal wellbore without requiring expensive workovers. The technique involves the use of ultrasonic treatment coupled with foam treatment. Initial experiments show that ultrasonic treatment can reduce plugging in two waysthe first is the reduction in oil viscosity (especially in the presence of asphaltic crudes) and the second is the ability of ultrasound to keep particles in suspension. The second effect can be due to generation of microbubbles. The process is coupled with in situ generation foam. In order to generate foam, a particular fYPe of surfactant is chosen from a selection of a wide range of surfactants supplied by the service companies. While the design of the device that couples both these effects need to be optimized, initial series of experiments show goodpromises. Introduction Crude oils produced in many parts of the world contain asphaltenes. Asphaltenes are known to deposit in the vicinity of production wells during miscible floods, after acid stimulation, during thermodynamic changes, and in the pipelines during transportation or during pressure changes in a mature field with an asphaltic crude. Asphaltene deposition leads to production loss and involves expensive corrective measures. This study proposes a new technique for cleaning asphaltenes with an ultrasonic device. The same method can be used to clean a horizontal wellbore that usually suffers from solid deposits, leading to significant reduction in productivity. The principle behind this new technique is ultrasonic irradiation, coupled with foam treatment. Even though ultrasonic treatment has been used in other disciplines for cleaning purposes, the petroleum industry has used the technique for remote sensing'" and material characterization 4 . Recently, ultrasonics have been used to reduce cuttings size 5 . This is possibly the first application of ultrasonics in reducing environmental impact due to drilling activities. Several other potential applications of ultrasonics have been investigated, but did not reach commercial level, both in the areas of asphaltene removal 6 and the removal of fines and mud solids from new wellbores 7 . The ultrasonic treatment has been proven to reduce viscosity to facilitate flow in pipelines. The preliminary experiments conducted by the principal author showed that the same ultrasonic technique can be used to clean asphaltene clogged sections of oil wells and reservoirs 8 . Little has been reported, however, on the optimization of amplitude, power generation, time required for cleaning and viscosity reduction. The effect of ultrasonication on adsorption properties of the reservoir rocks and fluids is another area that lacks investigation. Recently, Smordal and Islam 9 demonstrated that the combination of ultrasonic treatment with a jet reactor can be attractive.

Abstract The purpose of this paper is to discuss and forecast the future evolution of technology affecting the petroleum sector in Canada. However it is never sufficient to just forecast technology development. It is important to set the context inwhich the forecast is made. In this case, 8 key issues that can affect petroleum technology are discussed and evaluated- oil prices, global warming, markets, R&D pegormers, government support, the resource base, information technology and deregulation. In the context of these assessments, future technology evolution is predicted for 4 areas - geosciences, production, EOR [enhanced oilrecovery) and upgrading. The forecasts are provided for two time frames - near term (0 to 20 years) and longer term (20 to 50 years). Introduction The purpose of this paper is to discuss and predict the future evolution of technology affecting the petroleum sector in Canada. The time frame assumed is the next 50 years. Two phrases used herein are ""near term", meaning the next 20 years, and "longer term", meaning 20 to 50 years from now. One may think that 50 years is a long time frame, but in the resource business the length of time for new technology to achieve commercial significance is often protracted and underestimated. For example, a multi-lateral horizontal well was drilled in 1953. However, horizontal wells did not achieve commercial significance until the late 1980's. Multilateral horizontals are just now achieving commercial significance - a time lag of over 40 years! This paper is developed in a logical sequence. First it is important to set the context for the forecast - what issues and assumptions are important and can impact the timing or success of any new technologies. Second, sector forecasts are provided with a focus on 4 areas - geosciences, production, EDR and upgrading technologies. Each of these areas can have a major impact on the petroleum sector and is critical for growth and prosperity. Placement of technology in the time frames is based on the authors' view of when the technology will achieve a level of commercial significance. Thirdly, critical factors to achieving the forecast are discussed. Our industry is rife with acronyms and many are used in this report. To help the reader an acronym dictionary is included at the end. Like any forecast on the future there should be disclaimers: This paper does not necessarily reflect the views of our Company, it is a personal view of the future The authors warrant no accuracy or completeness of the forecast. In fact, the only thing known for sure is that, at least in part, the forecast will be wrong and incomplete. Like any forecast, this is a blend of what the authors believe will happen and what they would like to see happen. The reader may choose to view this as a wish list, without seriously changing the intent of the paper.

Introduction Horizontal wells have helped in advancing the oil industry since it was first introduced in 1980 1 . As useful as horizontal wells have become, the need for careful preparation become even more imperative before drilling can begin. As a result. the oil industry wants to be sure that a horizontal well is the right choice and will be economical. This reassurance is obtained through the use of field simulators which simulate a well's operation and production. These computer simulations require careful preparation and accurate input data with the results being within accepted tolerances. Engineers and oil companies also require a quick and easy method (plug and solve) of calculating production rates with "ballpark" results. Thus the question arises. what variables should be used and what models should be used? The answer is to simply use horizontal flow rate equations based on a few reservoir and fluid properties and reservoir and well dimensions. This paper will examine the result of a number of calculations using four horizontal flow rate equations (Borisov 2 , Giger 3 , Renard and Dupuy 4 , and Joshi 5,6 ) and compare the predicted results to actual daily averaged oil flow rates and cumulative oil production figures. HORIZONTAL WELL HISTORY Horizontal drilling and production started in Saskatchewan in the 1950's. These early oil wells consisted of only vertical wells. This conventional method of oil recovery initially met the production needs and oil recovery percentages ofthe time. Under favorable conditions (no formation damage, high initial reservoir pressure, no gas or water coning, etc.) vertical wells would recover no more than 60 percent of the original oil in place (OOIP) 1 . As oil needs increased and existing oil reservoirs were being abandoned before the reservoirs were depleted because no further oil could be recovered using conventional vertical wells or enhanced oil recovery (EOR) methods. another oil recovery methods were required The latest method is the use of horizontal wells. The use of horizontal wells in Saskatchewan began in 1987 and have greatly influenced the province's oil production. As of December 1994, there were 1385 producing horizontal wells and 14138 producing vertical wells in Saskatchewan. 7 Although horizontal wells accounted for only 8.9 percent of the total number of wells, horizontal wells accounts for 33.8 percent of the total oil production. More specifically, the annual production ofheavy oil increased to almost 6 million m 3 ofoil per year. The quarterly provincial oil production for horizontal wells steadily increased to where it is approximately a third ofthe total oil production. Figure 1 shows the provincial monthly oil production from horizontal wells with the total oil production broken down into heavy oil and light/medium oil production with a noticeable substantive increase in well production occurring in the middle of 1992. Figure 2 shows the number of horizontal wells drilled per year in Saskatchewan and the type of oil being produced since 1987. The number of horizontal wells broke the 500 barrier in 1993. Figure 2 also shows the total cumulative number of horizontal wells in Saskatchewan and the number of wells drilled for heavy and light/medium oil.

Abstract The Steam-Assisted Gravity Drainage (SAGD) process, which usually employs horizontal injection and production wells has been applied successfully in producing heavy oil reservoirs. It allows high recoveries to be obtained, at high rates without significant bypass of steam. However, SAGD process. due to, the heat loss to the overburden and adjacent formations can only be used for thick reservoirs with relatively high porosities and oil saturations if there is to be an economic oil/steam ratio. The Vapex process, which uses light hydrocarbon vapours 10 extract heavy oil from the reservoir is studied experimentally in the work described in this paper using a new, longer, scaled, packed model. In the process that evolved from the work. liquid solvent (propane, butane or mixtures) is injected with a small amount of non-condensible gas through a horizontal well at the top of the reservoir to contact and mobilize oil by dilution. The diluted oil is produced by a horizontal well. laterally separated from the injector. and located at the bottom of the reservoir. With this configuration. practical production rates can be achieved without appreciable gas bypass. Solvent is separated easily from the produced liquid by distillation and recycled and this results in relatively low net solvent requirements. Gas fills the vacated pores. The objective of the experiments was to develop process conditions to give high oil production rates with economic solvent requirements. To achieve this major parameters affecting the Vapex performance were investigated: temperature, pressure. solvent injection rates, types of solvent. mixed solvents, well spacing and configurations etc.. The major finding has been that wider lateral well spacings allow higher production rates and make the process more economic. Experimental results indicate that. under suitable conditions. the net solvent injection is about 0.2 B per B of produced oil and that high recoveries and practical rates are achievable. For example. a field prediction based on the experimental data indicates an average oil production rate of450 BID per horizontal well pair. 1000 m long. drilled in a pressure depleted. heavy-oil reservoir that is 10 m thick, to give a recovery of over 50% OOIP for a 70 acre pattern. Introduction The concept of Vapex evolves from the Steam Assisted Gravity Drainage (SAGD) process in which two closely spaced horizontal wells are employed with steam injected from an upper horizontal injector to form a steam chamber in the formation and heated oil drains downwards, driven by gravity, to a horizontal producer located near the base of reservoir. Another form of the process involves the use of multiple vertical injection wells instead of the horizontal injector. In the Vapex process, light hydrocarbon vapours or their mixtures with non-condensible gases are employed instead of steam to extract heavy oil or bitumen from the formation. Compared to thermal processes, the Vapex process can be operated at reservoir temperature with almost no heat loss. Vapex can be used as an alternative to recovery the heavy oil and bitumen from reservoirs which are not suitable for thermal processes such as reservoirs with bottom water and/or high water saturation, vertical fractures, low porosity and low thermal conductivity.

Abstract Use of a horizontal well for steam injection, or for fluid production in thermal recovery, is of practical interest in field operations. Experiments were carried out in a high pressure steam model equipped with an axially placed horizontal well. Steam was either injected into the horizontal well, or into the surrounding porous medium, with fluid production through the well. A variety of experimental conditions were employed. Temperatures and pressures were measured inside the well and at various points in the porous medium. Several effects were clearly evident: gravity segregation of steam led to uneven heating of the porous medium. The distribution of heat along the well axis was quite uneven. Pressure drop inside the well was small, but it influenced fluid flow distribution in the surrounding porous medium. Oil recovery and pressure drop were plotted as functions of volume of steam injected. The production behaviour of the horizontal well could be correlated with temperature in the surrounding porous medium. Effects of well length, diameter, vertical position in the porous pack, oil viscosity, and pressure differential on oil recovery, oil-steam ratio, etc. were examined. Introduction Over 2000 horizontal wells have been drilled for primary production in Alberta and Saskatchewan. A smaller number is used for thermal applications. Such applications utilize horizontal wells for production, injection, or both. Examples are: Tangleflags and Cold Lake, where horizontal wells are used for production, with vertical injectors, several cylic steaming type operations where horizontal wells are used for injection and production, and SAGD (Steam Assisted Gravity Drainage) in UTF and other areas where horizontal wells are used for both injection and production. There are more applications where horizontal wells are used as producers than injectors. Flow of fluids and heat in the vicinity of a horizontal injector or producer is of interest in the above applications. The work described in this paper was concerned with an experimental investigation of fluid and heat transport around a horizontal producing well in a physical model that allowed for gravity effects. The flow of fluids inside the horizontal well was also studied via the measured pressure drop in the well. Several types of wells were tested. Effects of well length, diameter, and vertical location on performance were examined. PREVIOUS STUDIES The advantages of horizontal wells, viz. large contact area with the reservoir, low pressure drawdown, and possible mitigation of coning, are well-known, and discussed in many papers. Likewise, field experience has been also been described in numerous reports. The success rate of horizontal wells as producers is about 60% in Saskatchewan. The experience with horizontal injectors is much more limited. Flow hydraulics and pressure drop inside a horizontal well have been the subject of several recent studies. Plaxton 1 gives a comprehensive survey of treatments of pressure drop in horizontal wells, and reports an improved method. The only previous study pertaining to flow inside a horizontal well and in the porous medium in the proximity of the well, under steam injection, was reported by Doan 2 and Doan, Farouq Ali and George 3 .

Agenda Introduction Horizontal well Intervention Geological Setting Tubing Conveyed Openhole Logging Isolation Candidate Selection 1996 Program Review Summary Recommendations Questions Figure. Williston Basin Setting (Available in full paper) Comments Weyburn Unit is located in the northern portion of the Williston Basin 125 km SE of Regina Figure. Weyburn Unit Sakskatchewan, Canada (Available in full paper) Comments 22 km long X 18 km wide = 396 square kms 130 horizontal wells with 253 legs 520 vertical producing wells 168 injection wells 1.2 billion barrels of oil in place Figure. Weyburn Unit - Production History and Forecast (Available in full paper) Comments field discovered in 1954 waterflood started in 1963 production peaked at about 7500 m 3 /d vertical infill program in 1980's horizontal pilots in 1991 and 1992 horizontal infill program started in 1993 and is still ongoing, the majority of which have been drilled under balanced opportunities identified until the end of 1998 the current production is 3500 m 3 /d horizontal wells account for 19% ofthe producing well count, however, they contribute 65% ofthe total oil production recently announced Canada's largest CO 2 miscible flood at Weyburn, injection of CO 2 by Q3 1999 Figure. Horizontal well Intervention (Available in full paper) Comments horizontal well technology, especially multi-lateral technology, has outpaced developments in cost effective intervention intervention can mean anything such as stimulations, isolations (mechanical or chemical), logging this project is another step in the development ofa horizontal well intervention strategy that will ensure that PanCanadian is aware ofor involved in development of the technology required to optimize recovery using horizontal wells the downhole environment in Weyburn is severe, H 2 S ∼5%, high brine and ofcourse will be faced with CO 2 in the future all interventions must be compatible with the above 130 horizontal wells, 70% ofwhich are multi-lateral, with approximately 250 km of openhole section one small interval in a horizontal well that is in communication with the under lying Vuggy can be the dominant producing feature ofthe well quad wells have 4000 m ofopenhole section; where do we start looking? - only source ofinformation is fluids and pressure while drilling objective ofthis project was to isolate these highly conductive zones so that the well could be pumped down with the existing lift equipment for other projects this type of intervention could be used to reduce operating costs or to reduce voidage requirements when infrastructure constraints become apparent if intervention is impportant under waterflood it is critical under miscible flood

Abstract Heavy oil accumulations in A1ississipian carbonate rocks, immediately subjacentto the sub-A1esozoic unconformity in southwestern Saskatchewan, have been knownfor more than forty years. Until late 1993, sporadic attempts using verticalwells to recover oil trapped at Battle Creek have attained about 17, 000m 3 in 15 years of production. However, recently drilled horizontalwell indicate there is potential for much higher yields over shorter timeperiods. The reservoir rocks were deposited on a ramp that prograded over olderMississippian deeper water and basin slope carbonates. The ramp rocks includecrinoidal grains/ones and packs/ones, interbedded with lime muds/ones andcrinoid-rich wackestones About 15–20 m below the unconformity the grainstones and packstones have beensealed by calcite Cf!JlJeI1B. However subjacent to it, they were extensivelyaltered. Skeletal components of the grainstunes and packstones were micritized, and in places, preexisting particles and interparticle cements have been wholly01' partically dissolved, exhuming original porosity or creating enlarged vugs.Furthermore, the paleotopograplucally positive features on the unconformityhave been dolomized. Lithologies affected include: micritized skeletalcomponents of grains/ones and packstones and micrites of packstones, wackestones and lime mudstones. Diagenesis has created two suites of non-reservoir rocks and three of reservoirgrade. Porosities of 8–41%, permeabilities of 8–5/2 md, and entry pressuresless than 4 kg/m 3 make up the reservoir rock properties found atBattle Creek and several other poorly exploited localities Introduction The Mississippian rocks of southwestern Saskatchewan unlike their counterpartson the eastern flank of the Williston Basin, have been known to exclusivelycontain heavy oil shows, The shows in cores, drill cuttings and drillstem testshave been recognized since the early days of drilling in both southeastern Alberta and southwestern Saskatchewan. However, their producibility wascommonly overlooked because of the extremely low gravity of the oil (in theorder of 11 ° API). In a study for the Saskatchewan Department of Energy andMines, Kent and MacEachern 1 identified twenty-four heavy oil showsin Mississippian core and drillstem tests from the area between range 20 westof the third meridian and the Alberta/Saskatchewan Interprovincial Boundary andtownship 1 to township 15, inclusive. The most impressive of these shows was adrill stem lest from the Coop et al.. Battle Creek 1–27 well (Lsdl27-3-26w3)thaI recovered 1262 m (4140 ft) of 11 ° API oil from an interval inMississippian rocks immediately beneath the sub-Mesozoic unconformity.Subsequent tests in the same well yielded mainly water and it was eventuallyabandoned. However, this discovery identified the Battle Creek area as apotential heavy oil producing area and in 1966. Western Decalta offset the 1-27well with two boreholes at IA-27-3-26W3 and 6-27-3-26W3. The former wasabandoned shortly after completion but the latter produced oil from theMadison at the same stratigraphic level as the discovery well for about one anda half years (1966 to 1968) until a fire at the treated caused the operator toabandon the well.

Abstract The displacement of oil by bottom water to a horizontal well in a verticallyconfined reservoir was studied experimentally in a Hele-Shaw cell. Thestability of the water-oil interface was investigated at different flow ratesand viscosity ratios_ A stable interface with higher recoveries was obtainedfor lower flow rates and for the cases where water and oil had the sameviscosities. The interface became unstable for higher flow rates and/orviscosity ratios. Fingering flow, which results ill bypassing of oil, reducesultimate oil recovery. For a given viscosity ratio, the higher flow ratesusually result in a lower oil recovery at breakthrough. However, in some caseswhere multiple fingers fanned, the oil recovery for higher flow rates was foundto be higher than that for lower rates. Gil recovery at breakthrough wascorrelated with a dimensionless flow rate. A novel numerical method was developed in this study to simulate [he pistontype of displacement found in Hele-Shaw cells. The advancement of the water-oilinterface and the corresponding oil recovery, as well as the pressurebehaviour, were predicted. A single finger was identified for different flowrates when the viscosity ratio was adverse. The simulation results were ingeneral agreement with corresponding experimental data.. Introduction Reservoirs underlain by bottom water zones are very common and constitute asignificant resource. The effective exploitation of these resources wouldprovide an offset to the oil production decline from lop quality reservoirs.Production from such reservoirs usually involves the completion of the wellnear the top of the reservoir so as to reduce the production of freewater. If the interfacial effect is ignored, then there are two kinds of force exertedon the interface during production: the viscous force that results from theflowing of fluids in the reservoir and the net gravitational force thatresults from the difference in density of two phases. For upwards displacementof oil by water, the gravitational force tends to stabl1iu: the water-oilinterface if water has the higher density than oil When the difference betweenvertical pressure gradients across the interface becomes greater than thedifference of gravity pressure gradients, the water-oil interface becomesunstable and viscous fingering occurs. Otherwise, the water-oil interface isstable. Figure 1 shows schematically the shape of a stable water cone for avertical well am.! a corresponding crest for a horizontal well. For verticallyconfined reservoirs, the cumulative oil production for isolated wells at thebreakthrough depends on the volume of water cone or crest underneath theproduction well (Butler, 1992). Cumulative oil production by bottom water drivecan be improved by horizontal wells in place of vertical wells because of theextended length of water crest (see Figure 1). When the viscosity of water is less than that of oil, which is the usual casein actual reservoirs, the upwards displacement of oil by bottom water may causethe interface lo become unstable at high production rate because of the adversemobility ratio between water and oil phases.

Abstract In recent years, horizontal wells have been very successful in increasing productivity adding reserves, and improving the overall cost-effectiveness of field operations. As a result, many operators are including the utilization of horizontal wells as an important element in their reservoir management strategy. Horizontal wells are being used in a variety of conditions: intersecting natural fractures, reducing water and gas coning, exploiting thin oil and gas zones, enhancing heavy oil recovery, tapping unswept oil, improving sweep, producing attic oil, and connecting discontinuous zones. Limited success has also been observed for therl1wl and low-permeability applications. In spite of documented successes in these areas, several challenges still face this technology. They include: sufficient prework including reservoir characterization during the candidate selection process, effectively integrating horizontal wells in overall reservoir management strategies, sufficient post-appraisal a/performance versus a plan in trying to learn more about the successes and failures with horizontal wells, and the perception that horizontal wells are only applicable in selected cases and not desirable if vertical wells are already performing well. The presentation focuses on three items: an evaluation of horizontal drilling and completion potential of various prospects, a discussion of some advances in horizontal well technology, and a review of case studies summarizing key aspects and emphasizing the use and misuse of this technology. Introduction Horizontal well technology is receiving notable attention for increasing productivity, adding reserves, and improving the overall cost-effectiveness of field operations. As a result, many companies' vision involves greater utilization of horizontal wells for enhancing their profitability (see Fig. I). Provided the prework has been performed during the candidate selection process, horizontal wells can be used in a wide range of applications. Figs. 2, 3 (Ref. I), and 4 provide several situations where horizontal wells have been successful economically, including intersecting natural fractures, reducing water and gas coning, exploiting thin oil and gas zones, enhancing heavy oil recovery, tapping unswept oil, improving sweep, producing attic oil, and connecting discontinuous zones. Limited success has also been observed for thermal and low-permeability applications. In spite of the above documented successes, several challenges still face this technology: sufficient prework including reservoir characterization during the candidate selection process, effectively integrating horizontal wells in the overall reservoir management strategies, sufficient post-appraisal of performance versus a plan in trying to learn more about their successes and failures with horizontal wells, and the perception that horizontal wells are only applicable in selected cases and not desirable if vertical wells are already performing well. It is not correct to say that horizontal wells can be a savior where vertical wells have proven unsuccessful. However, one should note that a majority of good horizontal wells were in reservoirs where the vertical wells were good. As a general rule, readers are encouraged to consider horizontal wells as the primary option for a field, unless otherwise applicable.

Abstract As part of a larger project, the relationship of horizontal well productivity and reserves to geology and reservoir properties has been examined at the Winter and Senlac heavy oil fields in Saskatchewan and at the Pembina field in Alberta. In the Winter Cummings Sand pool, vertical wells have not been successful in exploiting 36 million m 3 of heavy oil that occurs in a thick sand bar. Horizontal wells have average production of 22 m 3 /well/day and indicated ultimate reserves of 15.000 m 3 /well in the portion of the pool studied. Developed reserves are strongly dependant on standoff of the wellbore above the oil-water contact with at least 4.5 m of standoff required to produce beyond payout. In the Senlac Cummings-Dina pool, vertical wells are unsuccessful whereas horizontal wells are producing heavy oil at economic rates, The main sand body is possibly an estuarine deposit that occurs in a channel between continental and marine depositional realms. In the portion of the field studied, horizontal wells have ultimate reserves of 25,000 m 3 /well. Standoff of the wellbore above the oil-water contact IS not an obvious control of reserves developed but there is a positive correlation between reserves and wellbore length. Success of horizontal wells in the Pembina Cardrum light oil pool is strongly dependant on geology and reservoir properties. Horizontal wells located In areas of thick permeable conglomerate and permeable sandstone are successful whereas those drilled in low permeability reservoirs are failures. Introduction As part of a larger study, the authors have investigated the results of horizontal drilling in three sand pools in western Canada, The three pools are: Winter Cummings Sand Pool a producer of heavy oil in the L1oydminister area of western Saskatchewan Senlac Cummings-Dina Sand Pool which also produces heavy oil near L1oydminister and the Pembina Cardium Pool an important producer of light oil in western Alberta (Figure I). Winter and Senlac each have original oil-ill-place in occurs In thick sands having excellent reservoir properties. Both pools have extensive bottom water zones so that water coning has been a severe production problem in vertical wells because of the adverse mobility ratio of oil to water. Generally vertical wells have been uneconomic whereas there has been successful cold production from horizontal wells. The Pembina Cardium light-oil pool was discovered in 1953 and contains approximately 250 million m 3 (1.600 million STH) of recoverable reserves. The Cardium oil reservoirs are of interest for horizontal development because or their vast size and because there is a large amount of unrecovered oil-in-place despite secondary recovery being in place for a long period of time. At the time this project was undertaken. Amoco had drilled several horizontal wells in the study-area in the southwest part of Pembina field. Eight of these horizontal wells, drilled in areas of poor reservoir were unsuccessful whereas a horizontal well drilled in an area of good reservoir appears to be economic. This report is drawn from a larger study conducted under the sponsorship of Saskatchewan Research Council.

Abstract Horizontal wells in an Improved Oil Recovery (IOR) project can potentially improve sweep efficiency, and the overall economics. In cases of marginal economics, the use of horizontal wells can make IOR more viable. Due to these advantages, many operators are beginning to apply horizontal wells in their IOR projects. Much valuable experience is being gained from these projects. This state-of-the-art review document is written for the benefit of engineers, planners and managers, who are new fo the application of horizontal wells in IOR projects. It is emphasized that in order to optimize sweep and drainage of oil using horizontal wells, one has to engineer an IOR project around the specific reservoir conditions prevailing in target locations and the interactions between horizontal wells and the main recovery mechanisms of the IOR project. Several limitations of the current technology together with their corresponding economic risks are pointed out. Based on a review of these, some project design considerations and guidelines for the use of horizontal wells in IOR projects are presented. It is recommended that these considerations be reviewed from time to time as more experience is gained on the performance of horizontal wells in various IOR projects and as innovations in technology mitigate some of the limitations of the current technology, thereby reducing technical and economic risks. Introduction Most of the current horizontal wells have been drilled to improve returns/ reserves of pools producing under primary mechanisms. When these operations reach their economic limits under the current phase, industry would have amassed a large inventory of depleted or watered/ gassed out horizontal wells. Some of these horizontal wells may be extremely valuable during the Improved Oil Recovery (IOR) phase, where the focus will be on improving volumetric sweep as well as, on accelerated production. Due to these considerations, the use of horizontal wells in IOR projects (using not only the existing horizontal wells, but also new injectors and producers, whenever warranted) is receiving increasing attention. Horizontal wells may not be able to correct all the maladies leading to poor oil recoveries in IOR projects using conventional vertical wells. However, in many cases, they may be able to sufficiently lower impediments to proper drainage by enabling injectant to more efficiently sweep/displace oil. Such impediments could be due to coning, insufficient injectivity/ productivity, heterogeneities, fractures, anisotropies, poorly connected or ‘compartmentalized’ reservoirs, viscous fingering, recovery processes affected by severe gravity over-ride, etc. With the removal of these obstacles, there is a potential to lower unit injection/production costs as well as, overall capital costs as fewer new horizontal wells (as opposed to several new vertical wells) may be needed in a given IOR project. As a result, IOR is becoming viable in certain oil pools where it was otherwise unattractive. In a recent review of the IOR potential of Saskatchewan's oil pools' (jointly conducted by PRI and CERI), it was concluded that the economic viability of IOR at a number of Saskatchewan pools is significantly improved by the use of horizontal wells.

Abstract CL Consultants Limited has been involved in over seventy horizontal wells in S. E> Saskatchewan. From this experience has arisen a number of observations as to the tolls and skills needed in geosteering and the determination of reservoir quality. The mandate of the wellsite geologist is to place and maintain the wellbored in an predetermined location deemed as optimum. Samples, hydrocarbon detection, survery data, and LWD tools are constantly providing information to the wellsite geologist. How the geologist in the field uses this information to steer the bit to and within the reservoir and make determinations as to reservoir quality will be discussed. Introduction In 1989 CL Consultants was contracted to provide the Hydrocarbon Logging and the Wellsite geologist for a well in central Alberta. This project was to drill the Nisku horizontally. The depth of the zone was clearly outlined and a predetermined depth to go horizontally was defined Using the hydrocarbon logging equipment in particular the chromatograph, an oil contact was identified. Once this contact was reached it was clear what depth had to be maintained in the horizontal leg. The well proved to be very successful and upon completion of the job many observations were made and many questions where raised Correlation of the samples and the hydrocarbon data to the wireline data was very concise Porosity and reservoir quality could be defined while drilling. This, combined with the ability to steer the bit into the best reservoir made the proposition of horizontal drilling very exciting. Today, the skills tools and knowledge have greatly increased. With this expansion this techniques, the responsibilities of the well site geologist have changed and expanded. On a typical vertical well one geologist is responsible for tracking the wellbore as it drills through the various strata to a generally predetermined total depth Samples penetration rate and hydrocarbon detection provide many clues to that is occurring down hole. Once the primary objective is drilled the Geologist reports observations on porosity, fluorescence, and other hydrocarbon evidence The zone is then logged and all the information is compiled and the fate of the well is determined. Reservoir quality is based primarily on the open hole logs. The role of the geologist in a horizontal application creates an entirely different operational situation on the location. The entire process starts with the project geologist Interpreting the final is the most optimum location for the wellbore in the reservoir. Prior to drilling this "best spot" is outlined to the wellsite geologist in the form of a window that must be maintained. Once the wellsite geologist is on local on the build section has to be monitored and the correlation of the over lying strata must be carefully followed to ensure the reservoir is coming in according to the prognosis. Any changes in the build section are discussed with the project geologist to see if any angle changes to the build are required. Once the reservoir is encountered the window is maintained. If the rock changes a change in wellbore trajectory is necessary.

Abstract Horizontal wellbore drilling technology has drastically escalated the productivity of oil and gas and become a portentous technology in petroleum industry. However, horizontal wellbore drilling is principally hampered by wellbore cleaning hydrodynamics which in turn is complicated by the buildup of drill cullings in the lower side of the annulus thereby reducing the drilling rate and transport performance of drilling fluids. A method and apparatus has been developed to enhance wellbore cleaning employing a transverse axial-travelling dynamic-pressure jets system (TAD-Jets system) in collaboration with conventional axial laminar flow in a multiple variant conduits, orbically cascaded and embedded in the drillstring. In tandem, a single twenty-seven-variable equation has been derived which has the capability and versatility of predicting the transportation efficiency regardless of the wellbore geometrical architecture, formation heterogeneity and rheological properties of the drilling fluid there-in annulus confined. Practical examples are presented to test this mathematical model. Introduction The concept of horizontal wellbore cleaning pertains to heterogeneous flow of complex mixtures of solids in horizontal pipes. 1,2 Many investigators have attempted to solve the problem of horizontal wellbore cleaning through three main avenues: Designing drilling fluids systems of various physico-chemical compositions with the hope of increasing fluid carrying capacity. 3,4,5 Designing drilling pipes with ridged external geometrical configurations capable of conveying drillcuttings utilizing auger principle as well as optimizing drillstring rotational and reciprocational motions to induce drillcuttings dynamic suspension and increase drilling fluid carrying capacity 6,7 ; The third approach has been to optimize drilling fluid velocity profile by manipulating the regime a f flow between laminar and turbulent 8,9,10 .This has resulted into many drillcuttings transportation model like Moore's, Chien's, Zedlers' and Iyoho's just to mention a few. Although these research works have contributed significantly to the solution of this problem, nonetheless wellbore cleaning problem has yet to be understood and solved because up to now wellbores collapse when the turbulent flow meant to enhance carrying capacity of the drilling fluid exceeds formation fracturing pressure. On the other hand drillstrings do stick in the wellbore when tfe drilling fluid flow is too low to dislodge, dynamically suspend and convey the drillcuttings from the annulus below the dril1string. In the current study an attempt has been made to design a transverse axial-travelling dynamic-pressure jet system which will enhance the dynamic suspension of drillcuttings and improve their- transportation in a laminar flow regime. The overall aim is to enhance transportation efficiency of any given drilling fluid without: increasing the conventional flow rate above its critical value, increasing drillstring motion and changing drillstrings external geometrical configuration. This approach will be most appropriate for turbodrilling where the drillstring does not rotate and it's reciprocational motion is minimum. The system will reduce the necessity of manufacturing different drilling fluids which could pollute environment. Wellbore stability will be improved as drillpipe motion is not needed for the systems operation. This will ensure safe drilling and reduced drilling time and cost.

Abstract Steamflooding with horizontal wells promises to be a highly effective method for recovering heavy oils from shallow, thin formations. As is often the case for poorly consolidated heavy oil formations, sand production could constitute a serious production engineering problem. For horizontal wells, this problem could be exacerbated as the sands/formation fines could settle inside, and choke off sections of a horizontal well completely - leading to loss of production. To alleviate this problem, it is often necessary to case the horizontal wells. This paper reports results of a series of scaled model steam injection experiments investigating the role of a perforated casing on the recovery performance. Fluid production rate, well pressure drop, cumulative oil recovery and cumulative oil-steam ratio for open and cased horizontal wells are determined and compared to determine the impact of the casing. It is concluded that a casing, though necessary to control sand production into a horizontal well, could lead 10 lower cumulative oil recovery and lower thermal efficiency for the recovery process. For example. oil recovery and the cumulative oil-steam ratio in the absence of a casing were 49.7% of IOIP and 0.62, respectively. The corresponding values in the presence of a casing were 42.9% and 055, respectively. Introduction With innovations in lateral and horizontal drilling technology, more horizontal wells are being used to recover oil and gas world-wide. It has been widely recognized that the main advantages of horizontal wells over conventional vertical wells include larger reservoir contact area, ability to reduce the effects of gas/water coning, as well as the higher probability to intersect systems of vertical fractures in fractured reservoirs. In thermal recovery applications, horizontal wells - due to their extended contact with the reservoir - promise high production rates and improved steam sweep efficiency. For these reasons, many thermal horizontal well projects have been started up, and field-tested in Alberta and Saskatchewan 1–3 . The main production mechanism for the AOSTRA Underground Test Facility (UTF) in Fort McMurray, Alberta is steam-assisted gravity drainage. The pilot has been so successful that an expanded Phase B which involves more and longer horizontal wells is being implemented for commercial operation 1 . For Esso Canada Resources Ltd. 's Cold Lake horizontal well project, the first phase of operation involves cyclic steam stimulation of vertical wells to provide steam injectivity. Steam is then injected down these vertical injectors to push oil towards the horizontal producer 2 . Scepcre Resources Ltd.'s North Tangleflags, Saskatchewan pilot 3 also utilizes vertical steam injectors to mobilize and displace the heavy oil into a long horizontal producer. Sand production is perhaps the most widespread and costly production problem associated with many thermal recovery projects. The sand and formation fines could either impair production by choking the wellbore or reduce production by preventing the proper operation of downhole pumping equipment. Also, they will require the replacement of equipment because of erosion damage 4 .

Abstract With the recent rebirth of horizontal well technology comes a need to understand the flow of multiphase fluids within the horizontal wellbore. This understanding is required by both the production and reservoir engineer in their attempts to optimize reservoir exploitation. In Canada, a number of horizontal wells have been drilled in heavy oil areas, which are prone to sand production because of the unconsolidated nature of the reservoir. This poses an additional problem as it potentially adds an extra flowing phase and further complicates the flow regime as the sand settles and forms dunes. As a first approach to investigating sand transport in horizontal wells, a pipeline flow model was used to simulate the axial component of emulsion/sand flow. Although non-Newtonian behaviour may occur, crude oil emulsions are often nearly Newtonian, with viscosities up to 100 times that of the continuous phase. Pipeline flow of these emulsions may be either laminar or turbulent, Of interest are the frictional headlosses and delivered concentrations for sand transport by these mixtures. Predictions of pipeline performance can be made using existing experimental measurements for deposit free sand transport by Newtonian fluids of viscosity ranging between 5.8 mPa.s and 38 mPa.s, These tests included both laminar and turbulent flow of a 190-jJm diameter sand. Unfortunately delivered sand concentrations were not measured in these tests. The test results have been extrapolated using models that recognize which concentration variation is likely to occur. It is concluded that turbulent flow is much more effective than laminar flow for sand transport. Introduction Horizontal wells were first used for oil recovery over fifty years ago. Over the years they had limited success until recent developments in drilling and completion made them more feasible. These technological developments have resulted in a phenomenal increase in the number of horizontal wells drilled. In Canada, horizontal wells are employed in a variety of reservoir settings and resource types. A common use of horizontal wells is in the heavy oil areas where productivity is low due to the high viscosity of the crude oil, and recoveries are marginal because of the influence of a bottomwater zone. One area of concern when producing from a heavy oil unconsolidated formation is the flow of oil/water emulsions and sand in the horizontal well. If a stationary deposit of sand is formed, the resultant partial obstruction will increase the pressure drop and energy consumption for a given volumetric flow rate. Unfortunately this flow regime has not been studied systematically for wide ranges of deposit thicknesses and fluid viscosities so that mechanistic models for them have yet to be produced. For deposit-free flow, which requires higher flow rates, rather more is known. This is especially true for mixtures whose flow is turbulent. Much less is known about laminar flow of a slurry type system where the sand particles can settle. In this communication we attempt to illustrate the present state of knowledge as it would apply to horizontal well and pipeline flow.

Abstract This paper examines the effect of horizontal wellbore hydraulics and flow direction in the recovery from idealized heterogeneous reservoirs subject to bottom-water drive. It is shown that wellbore hydraulics significantly influence the inflow along the wellbore. However, the total rate of the well is not affected by wellbore hydraulics. It is also shown that the heterogeneities give rise to different wellbore pressure drops for different flow directions. A novel multi-level technique where the coarse-grid. fine-grid and wellbore equations are solved separately was developed. Preliminary test runs with this technique show substantial reductions in CPU time when compared to the standard technique. Introduction The inclusion of wellbore hydraulics in reservoir simulation with horizontal wells has received much interest recently [1,2]. It was shown in [I] that wellbore hydraulics can have a significant effect on the inflow (flow into the well) along the wellbore. Although the prediction of the production from a horizontal well may be very similar with or without wellbore hydraulics. the inclusion of wellbore hydraulics yields a substantially different drainage pattern along the wellbore. To increase the resolution of the flow around the wellbore a hybrid grid system which consists of local elliptical refinement of the coarse Canesian grid was used. The studies in [I] were restricted to homogeneous reservoirs. This paper examines the effect of wellbore hydraulics and wellbore flow directions in the prediction of recovery from heterogeneous reservoirs. The reservoirs under study contain zones with permeability contrasts and shale streaks. This paper also describes a novel solution technique for converging the systems of coarse-grid equations, fine-grid equations and wellbore flow equations. In [I], all these equations were converged simultaneously using Newton's method. In this paper, a multi-level technique is described which allows the separate solution of the different systems of equations. Thus, the coarse grid equations, the fine grid equations and the wellbore equations were solved separately. Attempts have been made to solve separately the coarse and fine grid equations [3,4], but have not been very successful. The method described here is more comprehensive than those in [2] and [3] because the wellbore is also included in the calculations. The key to the success of this multi-level technique is the transfer of information between the different systems through judicious specifications of boundary conditions. The advantages of this technique are highlighted. PROBLEM DESCRIPTION The examples were derived from one of the cases in [11. Heterogeneities were represented by permeability contrasts and shale streaks. The reservoir is discretized into a 9x9x6 grid system shown in Figures 1 and Table I. Initial pressure and saturations are also given in Table 1. Data on fluid properties, relative permeabilities and capillary pressures are from the Seventh SPE Comparative Solution Project [2]. Fluids were produced at a constant liquid rate of 1431 std m 3 /day (9000 STB/day) from a horizontal well drilled in the top layer (Layer 1). The well passes through the gridblock centres and the entire length is open to flow.

Abstract Horizontal drilling has revolutionized the petroleum industry's exploitation of low productivity reservoirs such as heavy oil, tight and naturally fractured reservoirs, reservoirs with gas and/or water coning problems, as well as EOR applications. This paper studied only applications of horizontal wells in low productivity conventional heavy oil reservoirs under primary production. Currently, there are many field applications of horizontal well technology in Saskatchewan heavy oil reservoirs. The performance from horizontal wells drilled in heavy oil reservoirs to date is generally very encouraging. Although horizontal drilling technology is generally understood. there are still some key questions concerning the effective application of horizontal wells in heavy oil reservoirs. The objective of this paper is to study the impact of key parameters of the horizontal well design using a complete reservoir model which incorporates pressure drop in the horizontal wellbore. Several practical cases were studied for heavy oil reservoirs with viscosity ranging from 100 to 10000 cP. The key parameters evaluated included wellbore length and diameter. The results will be described in terms of oil production, costs and economic profitability. Results indicated that longer horizontal wells were more desirable than shorter wells due to larger drainage areas translating to higher reserves productivity. Wellbore diameter has a more significant impact on reservoirs with heavier crude oil. The pressure drop in horizontal wells had no significant impact all productivity in heavy oil reservoirs. Therefore, it is more likely that ill the future, we will see longer length and smaller diameter horizontal well applications in heavy oil reservoirs. Introduction There are more than a thousand horizontal wells world-wide, and more than 150 horizontal wells are producing in Canada (1). Their popularity continues to grow. Applications of horizontal well technology in low productivity reservoirs, such as heavy oil pools have not only shown higher production rates compared to vertical wells (2), they also have tended to reduce sanding due to larger contact area with the formation causing a lower fluid velocity near the wellbore (2 and 3). In heavy oil reservoirs with water coning problems, horizontal wells have shown higher recovery than vertical wells (4). Although the success of the horizontal well technology in the heavy oil pool development has been very encouraging, there is still much discussion on how to design horizontal wells effectively for heavy oil applications. There are still some questions regarding the key parameters in horizontal well design. They are the following: Does the length or the diameter of the wellbore cause a significant pressure drop due to friction loss along the wellbore (impacting the well productivity)? What is the optimum wellbore diameter for a desired production rate? What is the role of viscosity undetermining optimal well length or diameter? To be able to answer the above questions, this study was divided into two parts. The first part evaluated, the flow mechanics and recovery processes of several heavy oil projects using horizontal well technology. The second part is an economic analysis which uses cashflow model to find the optimum profitability for a given project. Conclusions were then derived. using a combination of technical and economic analysis.

Abstract With the increase in the number of horizontal well projects worldwide. several reviews of the potential applications of the technology have been published_ However, contrary La much of the established literature, horizontal well technology is still in its infancy. Horizontal drilling may he commonplace, but still requires considerable improvements. Many field applications have not provided the extra-ordinary production increases that were expected. This review of the Slate of the art of horizontal well technology focuses on the shortcomings in the knowledge base in such areas as drilling, well completion, recovery strategies, and reservoir performance predictions. Various field results and experiences have been evaluated and compared to the expectations based on literature publications. A set of recommendations is proposed on areas requiring further research and development to: ensure better realization of the expectations, expand the application to new areas, and improve the potential for commercial success based on the combination of conventional and horizontal wells. Introduction Horizontal wells were used over forty years ago for hydrocarbon production mainly in Russia. The concept was revived recently due to improvements in directional drilling and the requirements for large offshore developments. The increase in popularity can be associated with proven and expected capability for improving production in some applications. Despite this popularity, there is still a great deal of apprehension towards the application of horizontal wells due partly to: cost, lack of understanding of the technology, and insufficient published production data on the successful applications. Horizontal wells are generally more expensive, risky, and more difficult to drill than conventional vertical wells. However. the cost of horizontal drilling has decreased substantially in recent years from about 3 times the comparable vertical well in 1984 to about 1.5 times in 1986 1 . A recent survey of worldwide horizontal drilling projects reported 133 medium and long radius wells with lengths of 300 m or more along the horizontal section2. This listing excluded the large number of short radius wells (with lengths under 300 m) as well as those wells drilled from subsurface shafts and tunnels. From the widely diverse applications cited in this survey, no generic well or development can typify the current horizontal well technology. Hence, the scope exists for innovative applications to a wide range of reservoir types and recovery processes. Extensive publications of the application of horizontal wells have appeared in literature. The potential of horizontal wells for both conventional oil recovery and for the recovery of heavy oil and oil sands are well documented 3, 4 Reservoir scenarios where horizontal wells present clear advantages over conventional wells include: thin reservoirs (less than 15 m), reservoir with high vertical permeabilities, naturally fractured reservoirs, reservoirs in environmentally sensitive or restricted areas, and reservoirs where gas or water coning problems preclude efficient operation of vertical wells. It would therefore: appear that no new reviews arc called for, until new developments are made. However. the approach in this review is slightly different.

Abstract The Use of horizontal wells for oil reservoirs which underlying water can be attractive because water production may be reduced. In this paper, the displacement of oil by a rising water crest is considered. This is the main mechanism by which oil is produced where operation above Muskat's critical coning rate is required. The arrangement which has been studied involves a series of very long, equally-spaced, parallel, horizontal wells located just below a horizontal reservoir boundary. It is first assumed that the oil and water have the same properties and methods are given for calculating the progress of the interface. Decreasing the well spacing improves che fractional recovery but reduces the production quantity per well. The method extends to infinite well spacing, i.e. to isolated wells. The effect of oil and water densities and viscosities on the stability of the rising crestal interface are also considered. There is a critical production race beyond which fingering will occur. This critical rate for fingering is different from that for cresting or coning and it presents a serious limitation to the effectiveness of horizontal wells for the production of heavy oil from reservoirs with underlying aquifers. With heavy oils, production at economic races involves not only displacement by a rising water crest, but also, because of viscous instability, the fingering of water upwards through the oil above the crest. Introduction This paper is concerned with the production of crude oil from reservoirs which are underlain by an active aquifer. Production at high rates from such reservoirs results in coning and premature high Water cuts. Conventional coning theory is largely concerned with the concept of the horizontal pressure gradients within the oil layer being reflected by a change in the vertical position of the oil-water interface. If the flow rate is low then the pressure gradient is insufficient to lift the water to the production well and water-free recovery is possible. There is a critical rate of production above which water is produced. While this concept is applicable in the case of oils having fairly low viscosities within reservoirs of reasonably high permeability, it is frequently uneconomic to produce at rates below the critical ones. This is particularly true for heavy oils lying above water where the rate must be considerably above the critical one for the operation to be economic and where, as a result, water inevitably rises to the production well. This is usually completed at the top of the reservoir. In these cases the mechanism becomes one of vertical displacement of the oil by the rising water cone and the quantity of dry oil which can be produced is related to the volume of the cone. More exactly, the dry production is equal to the volume of oil which has been displaced from the interior of the cone after making allowance for the initial oil saturation and the efficiency of displacement by the Buckley-Leverett mechanism.