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  1. Producing Horizontal Wells Horizontal wells prove versatile for improved oil recovery

    Hemanta K. Sarma, Kenji Ono Japan National Oil Corp. Chiba, Japan The diversity of Canadian horizontal well applications illustrates the improved oil recovery potential of this technology. Canada has been a pioneer in IOR with horizontal wells since the late 1970s. Improved oil recovery (IOR) horizontal well applications are increasing rapidly. Currently, about 5% of the over 7,500 horizontal wells worldwide involve IOR. As more horizontal wells are drilled, it is inevitable that IOR will be a significant proportion of these applications. Most IOR with horizontal wells has been successful, both in terms of oil productivity and economics. In most cases, project cost has been realized within months of production. Moreover, thanks to experience and improved technology, horizontal drilling is becoming more economical. The 1993 Joint Association Survey of drilling costs on 845 U.S. horizontal wells indicated that at $80.76/ft, a horizontal well was only 8% more expensive to drill per foot than a vertical well.1 Another equally, or perhaps more, important aspect is that these applications encompass a diverse array of reservoirs with various characteristics and IOR processes (Table 1)(63172 bytes) . This clearly demonstrates horizontal well versatility and viability. Applications Typically, horizontal wells are chosen to overcome the following key problems and limitations that often plague conventional IOR applications with vertical wells: Insufficient well exposure in the formation Poor injectivity and smaller drainage radius Poor knowledge of the heterogeneity/lithology away from well Higher pressure drawdown resulting in severe gas/water coning and sand egression Inefficient displacement process because of well/reservoir constraints and radial flow In thermal processes, less efficient use of thermal energy. In a nutshell, attaining and maintaining adequate injectivity levels have been major challenges in conventional enhanced oil recovery (EOR), and many failures are attributed to injectivity. In some chemical floods, such as polymer floods, polymer solution injectivity and shear degradation are major concerns. Higher pressure for improved injectivity often is unwise and/or impossible because of formation damage through unwanted and uncontrollable fractures. In contrast, horizontal wells provide the following attractive features to overcome or circumvent some of these limitations: Higher sweep efficiency and exposure of the injectant to a larger contact area Lower injection pressure requirement to inject the same fluid volume Lower pressure drawdown resulting in less-severe coning and sand problems Reduction of the adverse impacts from an active aquifer or gas cap Higher gross injectivity and oil productivity Benefits from a knowledge of heterogeneity and gravity drainage More direct-heat input to the target zone in thermal methods, such as lower heat losses to other zones. Fewer wells, less land requirement, and less environmental concerns. The Canadian horizontal wells are in diverse reservoirs, both heavy and light oils, with various IOR processes, both thermal and nonthermal. SAGD Steam-assisted gravity drainage (SAGD) involves two parallel wells, one above the other.2 The top well is the steam injector. In some applications, the top steam injector is a vertical well. When steam is continuously injected through the top well, it heats the oil and forms a steam chamber which grows upward and sideways. The temperature within the chamber becomes essentially equal to the injected steam temperature. At the interface with the cold oil, the steam condenses and heats the oil. Hot fluids (oil and water) then drain, by gravity, to the lower horizontal producer. The chamber should continue to grow as steam is injected. Compared with its lateral stable growth, the chamber growth upward is unstable and forms viscous fingers of more mobile steam. In addition to the benefits of gravity drainage, the process also provides a means for more systematic reservoir coverage and larger contact volume and, more importantly, SAGD keeps the oil hot during its flow to the producing well underneath. The SAGD process has been successful in several heavy oil reservoirs in Canada that have a wide range of oil viscosities, 13,000 cp at 19 C. (66 F.) to over 5 million cp at 7 C. (45 F.). SAGD has an enormous potential for the exploitation of the Athabasca oil sands, which have estimated reserves exceeding 1,320 billion bbl. For many medium heavy oil reservoirs underlain by active bottom water zone, SAGD also may be the only viable means to produce the remaining oil. Notable SAGD projects are: Alberta Department of Energys underground test facility (UTF) that was formerly known as the Alberta Oil Sands & Technology Research Authority (Aostra) UTF Imperial Oil Resources Ltd. and Amoco Canada Petroleum Co. Ltd.s Cold Lake projects Shell Canada Ltd.s Peace River project Sceptre Resources Ltd.s Tangleflags steam flood. UTF project Located about 44 miles NW of Fort McMurry, Alta., Aostras UTF project was initiated in 1984 in collaboration with several operators. The objective was to evaluate SAGD for recovering Athabasca bitumen from deeper depths (150 m). Table 2 (39213 bytes) lists basic Athabasca bitumen properties. The UTF horizontal wells were drilled from tunnels in the limestone, 15 m below the oil sands.3 In Phase A, steam injection began with three short, 60 m, horizontal laterals. For Phase B, which began in 1992, longer horizontal laterals (500 m) were drilled. Both phases performed above expectations. By the end of 1997, the Phase B recovery factor is expected to reach nearly 60%. As related to cost, the current project is estimated to be self-sustaining at a production rate of 4,000 b/d. For a field-scale commercial project, the needed self-sustaining rate is about 30,000 b/d. Peace River Shells plans at Peace River include changing the basic SAGD process after a few years. The change will augment the process by creating a pressure difference between adjacent well pairs.4 In this Enhanced SAGD or Esagd process, a pressure differential will be created by lowering the injection pressure in one well pair thus causing steam to flow from the high-pressure chamber to the lower-pressure chamber (Fig. 1)(64403 bytes) . Note that the transition zone refers to a more-permeable (1 Darcy) basal zone with a bitumen saturation less than 65%. This basal transition zone facilitates the initial steam injectivity below the fracture pressure. The formation is deeper (500 m) than at the UTF, but reservoir temperature (16.7 C.) and pressure (537 psi) are significantly higher. Compared to the UTF, both permeability and oil viscosity at reservoir conditions are much lower at 200,000 cp and 1.5 Darcies, respectively. Cold Lake pilot Imperial has operated the Cold Lake pilot for over 10 years and produced more than 330,000 bbl of bitumen through a 150-m long horizontal well at an average oil/steam ratio (OSR) of 0.38. The SAGD configuration had a vertical steam injector above and a horizontal producer below.6 7 The pilot produced no primary oil because of the high oil viscosity (50,000-100,000 cp) and all recovery is attributed to the SAGD. Tangleflags Sceptre Resourcess Tangleflags North field in Saskatchewan has been one of the most successful SAGD projects.8 The reservoir is shallow (450 m) with a fairly well-developed clean sand (95% quartz). Pay thickness is about 27 m, and the oil is heavy (13 API) with a dead oil viscosity of 13,000 cp. The pay is underlain by an active aquifer and overlain by a gas cap. Initial reservoir pressure and temperature was 592 psi and 19 C. Formation porosity is within the range of 30-35% with a high average permeability over 4 Darcies. During the primary production in 1982-84 under solution-gas drive and gas-cap expansion, the cumulative pool production stood at a meager 198,000 bbl, about 0.6% of the original oil-in-place of 32 million bbl. The initial high oil production rate declined rapidly accompanied by a steep water cut increase. The cyclic steam stimulation offered a limited initial success. It produced about 5,350 bbl of oil at a favorable steam-oil ratio of 4.5 before the aquifer influx soon dominated and caused the water cut to climb to almost 99%. Conventional steamflooding (that is, with vertical wells) was not a viable option because the bottom water would most likely act as a heat sink and cause severe heat losses. Hence, the horizontal well option was carried out. The plan was that the formation would provide an excellent vertical downward sweep to an underlying horizontal producing well. Accordingly, a 530 m 3 130 m area with a pay thickness of 15 m was chosen for the pilot. The study suggested that the pilot would recover almost 50% of the oil in place, 1.5 million bbl in 5 years. The pilot implementation strategy (Fig. 2)(32397 bytes) was adopted as follows: Steam was injected through a set of four vertical wells near the gas-oil contact to ensure a higher heat input rate and to provide a rapid steam overlay across the pilot area. Hot fluids (oil/water) were to drain, by gravity, to the horizontal producer above the water-oil contact. Preferential downward flow of hot fluids plus the reduced pressure drawdown by the horizontal well for lessening the dominance of the aquifer influx would result in a less severe water cut. The pilot has been operational since June 1988, with a 423-m horizontal well. The chronology (Table 3)(24933 bytes) suggests that it has been successful both technically and economically. Both the water-oil ratio and steam-oil ratio dropped with accompanying higher oil production rate. Also, the flood achieved a more favorable temperature distribution over 2-years, resulting in more efficient steam utilization. In situ combustion Conceptually, in situ combustion (ISC) promises the highest oil production efficiency with the least energy cost among all thermal processes. Also, it is less susceptible to constraints of formation depth or thickness. However, results reported from the limited worldwide field applications present a rather disappointing picture of ISC. One means available to make ISC work is with horizontal well technology. Battrum field In Mobil Canadas Battrum field, Saskatchewan, an ongoing wet-ISC project in a sandstone reservoir, two horizontal wells were drilled to combat the poor volumetric sweep efficiency and high operational costs.9 The poor volumetric sweep was caused by a secondary combustion gas cap formed because of the density difference between gas and oil and the absence of a vertical permeability barrier. The gas cap dominated one part of the reservoir while the mobile bottom water resulted in high water cuts in another part of the reservoir. Also, high gas velocities and low-temperature oxidation (LTO) caused stable and highly viscous oil-in-water emulsions that reduced inflow at some wells. The net effects of the problems were: Combustion gas override An immediate channeling of the injected air to the production well, causing poor conformance and inefficient pressure maintenance A high operating cost attributed to the production and treatment of oil produced at a very high ISC GOR of 1,965-2,246 scf/bbl, treatments for breaking down highly stable oil-in-water emulsions formed by the high GOR and/or LTO, and problems with pump failures, corrosion (carbonic acid), and sand production. The two horizontal wells, Well 16D-20 (610-m long) and Well 12B-22 (406-m long), were drilled in December 1992 and August 1993. In Well 16D-20, the heel and toe are 870 m and 555 m away from the nearest injection wells. Well 12B-22 is closer to injection wells ( Well performance data suggest that the wells have improved the vertical sweep efficiency, measured in terms of increased oil rate, and lowered GOR and WOR.9 Of the two wells, Well 16D-20 has been more successful in enhancing the vertical sweep efficiency. The field data in Table 4 (20174 bytes) demonstrate their relative performance. Eyehill In another ISC project in Eyehill Cummings, Sask., Murphy Oil Co. Ltd. reported improved oil recovery in a terminated ISC project with three horizontal wells. These wells helped recover over 94,000 bbl of the mobilized but previously bypassed heavy oil.10 Miscible floods Horizontal wells were drilled to improve the performance of the miscible hydrocarbon floods in the Rainbow Keg River G Pool and the Brazeau River Nisku A and D pools. Rainbow Keg River Husky Oil Ltd.s horizontal producer in the Rainbow Keg River G Pool hydrocarbon miscible flood in NW Alberta augmented the well productivity index (PI) by more than 3.5 times its best vertical well PI.11 The pool is predominantly limestone with a middle Devonian pinnacle reef reservoir (Fig. 3)(46942 bytes) . The maximum relief of the pinnacle is 190 m above the inter-reef facies and the original oil-water contact. Average formation porosity is low (10%); however, it has a good horizontal permeability (565 md) with a kv/kh = 0.07. The oil is light (39.1 API) with a viscosity of 0.48 cp at the reservoir temperature of 81 C. The reservoir has always been above the bubble point pressure, 1,827 psi, and hence, there is no free gas cap. Although there is an underlying aquifer, it is in poor communication with the overlying pay zone and hence, poses no serious water coning problem during production. The existing solvent flood was initiated in 1972 by injecting the solvent at the top zone and producing through a vertical well in the foreslope (Fig. 3)(46942 bytes) . Excessive solvent injection helped pressurize the reservoir and raise the oil rate to over 2,516 b/d, but it also resulted in an almost immediate solvent breakthrough at the producing well. The solvent-oil-contact (SOC) was driven downwards resulting in a large oil sandwich loss. In 1983, the solvent injector was recompleted as a dual well to improve the oil productivity but with little success. Eventually, the oil rate declined to 943 b/d in 1985 because of increased solvent recycling caused by the downward move in SOC towards the producing interval. It was decided to drill a horizontal producer to minimize solvent recycling and enhance the production of the unswept oil. As the gas coning was dictated by the pressure drawdown, it was envisaged that a horizontal well would allow the desired oil production rate but at a much lower pressure drawdown compared to a vertical well. Hence, the objective was to arrest the oil sandwich loss by reducing gas coning and to improve pool PI. The feasibility study suggested that a 150-m long horizontal well would achieve about 70% reduction in the pressure drawdown at a given production rate. As the sandwich loss was proportional to the square root of the drawdown pressure, it implied that a horizontal well within its drainage zone would cut the loss by about 50% of what would have occurred in a vertical well. To maximize the sweep of the oil, the horizontal producer was to be located as low as possible but above the current water-oil contact (WOC); hence, it was crucial to ascertain the existing WOC reliably before the well was drilled because there would be little room for remedial actions should the horizontal well enter the water zone. A vertical pilot was drilled to estimate the WOC before horizontal well target depth was chosen. A 178-m long horizontal well was drilled at a TVD of 1,943 m in 66 days at a cost of C$2.4 million. The horizontal section was left as an open hole. The time and cost overruns were 50% and 70%, respectively, but these overruns were primarily caused by lost time in the vertical section of the well. Soon after the well was put on stream in July 1989, a PI of 15 b/d/psi, 2.5 times the best existing PI in a vertical well, was achieved. By October 1989, PI improved further to 29 b/d/psi. This PI improvement also indicated some well clean up during production. The initial 10-month horizontal well oil production of 125,800 bbl was enough to payout all drilling and completion costs, and it has been an economic success. Overall, the horizontal well has contributed to a net increase in the pool oil production and decrease in the pool GOR. This well produced 786,000 bbl of oil in the first 4 years. Encouraged by its results, Husky has drilled two more wells in this pool, both longer (400-600 m) than the first one and at much lower cost (1.5 time the vertical well cost). Other Rainbow Keg wells The success at Keg River G pool led to 12 more horizontal wells in six other mature HC miscible floods operated by Husky. In all cases, wells have been drilled successfully in progressively riskier target reservoirs and with increased well length (up to 720 m). More important, the cost was paid off within the first year the wells were on production. Reference 12 suggests that based on Huskys field data, a horizontal well enhanced the productivity at offset vertical wells in Rainbow Keg River E Pool.12 It experienced a 10-15% increase in the oil production and a temporary cessation in the rising GOR trend. According to Reference 12, the improved drainage at the offset vertical well was caused by the pulling effect of the horizontal well and/or cross flow along the borehole into the area near its adjacent vertical well(s). The 3D simulation studies also confirmed this hypothesis. If it turns out to be a general phenomenon, it will have the following positive implications: 1.When horizontal and vertical wells are closely spaced, there is less fear of drawing gas from the vertical to the horizontal well. 2.Extending a horizontal well nearer to offset vertical wells can improve drainage and reduce gas coning. 3.Re-entry into watered-out or gassed-out vertical wells with multiple laterals may be a possible alternative to maximize the production. Brazeau River Petro-Canada Inc. has successfully redeveloped Brazeau River Nisku Pools A and D with two 400-m long re-entry horizontal wells in its existing vertical miscible floods.13 Both wells are in 3,200-m deep reef-type pools with bottom water. Horizontal wells added incremental oil recovery from pools which otherwise would have been under blowdown. In 1990, the Nisku A pools prevailing oil rate was 2,768 b/d with a GOR of 10,106 scf/bbl. The pool recovery was 70% with 25% recoverable oil still in situ. As the GOC descended to 10-15 m above the perforations, further production through vertical wells was not viable and the only course available was blowdown of the pool. However, with the horizontal well, an additional 1 million bbl oil were recovered (4% OOIP) with an average PI of 11 b/d/psi. First-year production alone paid out the cost. Currently, the pool is on blowdown. In Nisku D pool, the problem with conventional miscible flood was rapid gas breakthrough that occurred within 6 months. At an average oil rate of 2,516 b/d, the GOR was 14,036 scf/bbl. The horizontal well helped drop the GOR to 2,246 scf/bbl at an average PI of 65 b/d/psi. The cumulative oil production as of February 1994 was 654,000 bbl or 10% OOIP. Like in Nisku A pool, all costs were realized in the first year of production. Other horizontal wells Other examples of horizontal wells in Canada include wells in Pelican Lake, South Bodo, and redevelopment of mature light and heavy oil reservoirs in Saskatchewan. Pelican Lake Located about 174 miles north of Edmonton, Alta., Pelican Lake is operated by CS Resources Ltd.14 The tremendous success of horizontal wells in this complex reservoir reinvigorated this old oil field where over 100 conventional wells existed prior to 1987 when CS Resources acquired it. Prior to horizontal wells, several EOR methods, including water flooding, cyclic steam stimulation, steam flooding, and ISC were tried in Pelican Lake but with very little success. Net pay in its 150 sq km operational area is 4-6 m with 14 API oil of viscosity 600-1,000 cp at 20 C. Although the average kh is about 3 Darcies with a porosity of 26%, the geology is very complex. As shown in Fig. 4 (34137 bytes) , the thin sandstone payzone is bounded by claystone both above and below. Even within this thin sand, there are two zones: a bar complex in the upper zone and a bar complex margin in the bottom zone. The upper bar complex is comprised of clean, coarser-grained sand with a higher oil saturation, while the bottom bar margin consists of finely grained sediments with numerous shale breaks. Obviously, in such a reservoir, a vertical well will have a marginal scope to effectively recover the oil. Efficient oil recovery seems possible only through horizontal wells. However, from operational aspects, drilling a horizontal well in such a thin target formation bounded by the claystone has been a challenge with regard to maintaining its trajectory. Nevertheless, 17 horizontal wells have been drilled in three phases. A typical well trajectory is shown in Fig. 4 (34137 bytes) . The first phase wells were about 500-m long. In the subsequent phases, the well lengths were increased to 1,000 m and 1,500 m. With each phase, the well cost dropped significantly, from C$1,800/m to C$400/m, primarily because of improved understanding of the geology, drilling techniques, and experience. More recently, Sperry-Sun Drilling Services drilled its first three-branch, multilateral horizontal well using a lateral-tie-back-system (LTBS). The LTBS allowed a total well exposure in excess of 2,800 m.15 All wells are pumped by downhole progressive cavity pumps. The improvement in the oil productivity has been significant. Compared with the vertical well PIs, the horizontal well PIs have been almost 5-30 times better. Also, well productivity has improved with the well length. For instance, for 1,500-m wells, the PI improvement was 25-30 times that of a vertical well, whereas, for 500-m wells, the PI improvements have been within the range of 5-10 times that of vertical wells. South Bodo Pool South Bodo pool is a channel sandstone heavy oil reservoir located in eastern Alberta where the current horizontal well oil production rate is 409 b/d.16 However, prior to the drilling of 15 horizontal wells in 1992, all 6 vertical wells were shut-in. The key to the success was the redevelopment of the reservoir with horizontal wells by integrating 3D seismic data with available geological and engineering data. This helped gain better confidence in mapping the nature and orientation of the channel sands with regard to their vertical and lateral extent. As a result, horizontal wells could be placed at optimum locations within the target sand, and the sand/water production could be minimized. The impact of horizontal wells has been dramatic, both on the oil production rate and the water cut. The current average oil production rate of 409 b/d brought a new life to the pool whose average vertical well rate was a meager 19-25 b/d before the shut-in. Mature reservoirs in Saskatchewan Success similar to that obtained in the South Bodo pool has been repeated in the redevelopment of three mature light and heavy oil pools with horizontal wells.17 These three pools in Saskatchewan are: Edam West Sparky sand, Midale Bed Unit 5, Weyburn, and Cummings-Dina heavy oil pool. Edam West Sparky is a tidal channel sand with a pay thickness over 20 m with porosity of 34% and horizontal permeability of 7 Darcies. The dead oil viscosity is around 10,000-30,000 cp. The reservoir is underlain by a mostly passive aquifer. With 10 horizontal wells, pool production has been 3,208 b/d. Horizontal well oil rates of 94-283 b/d have been 3-10 times better than those of vertical wells, 3-75 b/d. Midale Bed Unit 5, Weyburn, has a marly zone that is a microcrystalline dolomitized lime mudstone and a vuggy zone with fragmented limestone. This is the target zone where two horizontal producers were drilled in this previously waterflooded reservoir. The pay thickness is 1-4 m with a porosity of 22% and permeability of 5-20 md. The zone contains low-viscosity, 1.2 cp oil. With the two horizontal producers, the average unit oil production rate has improved to 491 b/d. Compared to a vertical well rate of 220 b/d, the average horizontal well rate has been 270 b/d. The incremental reserves attributed to the two horizontal wells is 566,000 bbl. Shell now has over a dozen horizontal wells in the unit with longer horizontal wells (770 m) parallel to the fracture trend.18 The Cummings-Dina heavy oil pool is a sandstone reservoir with fine-to-medium grained quartzose sand deposited in fluvio/estuarine environment. It is shaly at places and has a bottom water zone. The oil pay is about 17 m thick with a porosity of 31-35%, horizontal permeability (kh) of 4,800-7,700 md, and vertical permeability (kv) of 0.85-0.95kh. The lower zone near the WOC has low kh and kv which help lower the water cut. The reservoir oil viscosity is over 3,000 cp. All vertical wells were shut-in due to high water cut. It now has 32 horizontal producers which solely contribute to the pool average production rate of 3,145 bbl with each horizontal well having produced over 151,000 bbl. Thus, horizontal wells by themselves have effectively increased the pool reserve and extended its life. Future potential Some not-so-encouraging EOR processes such as chemical processes (polymer, surfactant, and alkaline/surfactant/polymer) seem to be gaining renewed interest, thanks to the horizontal well technology because it allows higher gross injectivity, larger contact area, and residence time and yet, reduces the shear degradation during the injection. Multilateral/multibranch horizontal wells now offer a potential to further enhance the sweep efficiency and increase the contact area. Vapex process Vaporized solvent extraction (Vapex) process proposed by Butler and Morkys in 199119 also shows potential to recover heavy oils with much less thermal energy requirement. More important, Vapex appears to help upgrade the heavy oil while being produced, thus reducing some upgrading cost. This upgrading is attributed to the precipitation of asphaltenes as depositions on the rock matrix. Thus, the in situ oil becomes lighter. And a lighter oil is easier and more economic to handle, process, and transport. Another attractive feature is that the solvent in the Vapex can be relatively inexpensive and it should also be possible to extract it from the candidate reservoir oil during the process. Several Canadian operators have been actively evaluating its field potential in collaboration with government energy agency, Canmet. In situ combustion, which has not been as successful, may get a boost if the recently developed COSH (combustion override spilt-production horizontal well process) proves to be successful in the field.20 The process appears to have potential in many Canadian reservoirs, and to be competitive to SAGD with regard to energy cost requirements. Conceptually the process is best described with the help of Fig. 5 (26403 bytes) as the following four steps.20 1.Continuous gas injection (with the gas containing oxygen) is carried out through a row of vertical wells completed in the upper part of the pay zone. During this operation, cold water is circulated in the annulus to minimize damage due to combustion. The reasons for not proposing horizontal gas injectors are: Currently no means are available to protect the well from combustion damage Variations in the injectivity along the well and backflow Violent gas phase combustion effects. 2.Remote gas producers help the split gas-phase flow. These wells can be either vertical or horizontal wells but are to be completed in the top part of the payzone. 3.A bottom horizontal producer located parallel to the row of vertical gas injectors drains the oil. The producer is placed towards the bottom of the pay for maximum oil recovery. 4.During combustion, a hot gas chamber forms around each vertical well. Convection effects and the pressure gradient due to the liquid production draw this oxygen-rich gas downward to react with the hydrocarbons. Once the ISC starts, the hydrocarbon coke, gas, and some liquid hydrocarbons should provide the fuel needed for sustaining the combustion. The process is still in the R&D stage, but if successful, it would have the following positive implications: High recovery potential of gravity drainage in addition to providing a hot mobile path for the oil to the horizontal producer and high ISC energy efficiency. Splitting of produced gas and oil phases to separate wells would reduce problems associated with the oxygen breakthrough at the producing well. Moreover, the segregation of the oil and gas flows should ease the pumping operations and maintain the high oil relative permeability when the horizontal well starts producing oil. Lower pressure differential will be sufficient to achieve the required injectivity and cause less emulsification problems. Combustion front movement and its location will be more easily controlled with the pressure drawdown at the horizontal well. Shorter distance between the front and the producer will lead to a faster payout. Producer will be less prone to combustion damages as the splitting of gases will inhibit the flow of oxygen and other gases to the well. Even if they do, it can be controlled more easily through the gas injection and/or gas producing wells. Failures Causes for horizontal well failure (68659 bytes) Even though the preceding discussions suggest that most horizontal well IOR applications have been successful both technically and economically, several have failed, and hence, largely gone unreported for obvious reasons. Therefore, horizontal wells are by no means a panacea for all IOR situations. In some situations, economics demand a certain threshold oil rate and favorable royalty breaks for them to be successful at the prevailing oil price. A 1993 review by the Canadian National Energy Board (NEB) suggested that a significant percentage of Canadian horizontal wells have not been economic. The NEB reviewed 189 nonthermal horizontal wells from 13 fields with a WTI oil price of $20/bbl, adjusted for transportation and quality as the basis. According to this basis, the 14 API Lloydminster/Hoole crude would fetch C$13/bbl and 19 API Provost/Suffield crude would fetch C$14.50/bbl. The criterion for an economic well was set at a minimum oil production of 50,000-75,000 bbl/well. Only 65% of Canadian horizontal wells (such as 123 wells out of 189 wells surveyed) met this threshold economic criterion. On an average, the reserve multipliers attributed to larger drainage areas of horizontal wells were within the range of 2.5 to 3.0. This compares favorably with an average cost multiplier of 2.0 with respect to a vertical well. In addition, the other major technical and/or operational reasons that often cause horizontal well failures are listed in the accompanying box. Multidisciplinary approach The single most important factor why horizontal well applications have enjoyed such a high success rate is that most applications have had foundations built on a multidisciplinary approach with inputs from all groupsgeophysics, geology, production, drilling, and reservoir. The evolution of this multidisciplinary approach has been need-based; as at the initial stage, the technology was considered a high-risk one and the industry has been less prepared for high-risk ventures in recent years. The industry needs to build further on this positive team-work approach. Under the prevailing circumstances, the industry has been reluctant to make new investments in IOR activities. However, it appears to be encouraged by the potential that horizontal well technology holds, and is taking a serious look at the productivity improvements it has brought in mature and marginal oil fields. Teamed together, horizontal well technology and IOR are positioned to be an economically viable and attractive option that can reinvigorate dwindling old oil fields. Acknowledgment We thank the Japan National Oil Corp. for the permission to publish this article. References 1.Joint Association Survey on 1993 Drilling Costs, API, November 1994. 2.Butler, R.M., Steam-assisted Gravity Drainage: Concept, Development, Performance and Future, Journal of Canadian Petroleum Technology, February 1994, pp. 44-50. 3.ORourke, J.C., et al., UTF Project Status and Commercial PotentialAn Update, May 1994, CIM 94-40, 48th Annual Tech. Meeting of Petroleum Society of CIM, Calgary, June 12-15, 1994. 4.Goobie, L.M.A., and Good, W.K., Shell/Alberta Department of Energy Peace River Horizontal Well Demonstration ProjectA Test of the Enhanced Steam-Assisted Gravity Drainage Process, CIM 94-41, 48th Annual Tech. Meeting of Petroleum Society of CIM, Calgary, June 12-15, 1994. 6.Bezaire, G.E., and Markiw, J.A., Esso Resources Horizontal Hole Project at Cold Lake, CIM 79-30-10, Annual Technical Meeting of the Petroleum Society of the CIM, Calgary, May 1979. 7.Adegbesan, K.O., et al., Performance of a Thermal Horizontal Well Pilot, SPE 22892, SPE Annual Technical Conference & Exhibition, Dallas, Oct. 6-9, 1991. 8.Jespersen, P.J., and Fontaine, T.J.C., The Tangleflags North Pilot: A Horizontal Well Steamflood, Journal of Canadian Petroleum Technology, May 1993, pp. 52-57. 9.Ames, B.G., et al., Improved Sweep Efficiency Through the Application of Horizontal Well Technology in a Mature Combustion Project, Battrum Field, Saskatchewan, Canada, HWC 94-48, Canadian SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 10.Morgan, R.J., Can Horizontal Wells Inject New Life into an Oil Combustion Pilot? Paper 25, Fifth South Saskatchewan Petroleum Conference, Regina, Oct. 18-20, 1993. 11.Adamache, I., et al. Horizontal Well Application in a Vertical Miscible Flood, Journal of Canadian Petroleum Technology, March 1994, pp. 19-25. 12.Fong, D.K., et al., An Unexpected Benefit of Horizontal Wells on Offset Vertical Well Productivity in Vertical Miscible Floods, HWC94-09, SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 13.Lee, J.I., and Jerhoff, T.F., Redevelopment of Brazeau River Nisku A and D Vertical Miscible Floods with Horizontal Wells, HWC94-05, SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 14.Fontaine T., et al., Development of Pelican Lake Area Using Horizontal Well Technologies, Journal of Canadian Petroleum Technology, November 1993, pp. 44-49. 15.Smith, R.C., et al., The Lateral Tie-back System: The Ability to Drill and Case Multiple Laterals, IADC/SPE 27436, IADC/SPE Drilling Conference, Dallas, Feb. 15-18, 1994. 16.Groten, G., South Bodo Pool Development with 3-D Seismic Drilling, 11th Annual Heavy Oil and Oil Sands Tech. Symp., Calgary, May 2, 1994. 17.Bohun, D., et al., Case Histories of Mature Light and Heavy Oil Pool Re-Development in Saskatchewan, HWC94-02, Canadian SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 18.Jones, P.W., et al., Stimulations of Horizontal Wells in Shell Canada, HWC94-70, Canadian SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 19.Butler, R.M., and Morkys, I.J., A New Process (Vapex) for Recovering Heavy Oils using Hot Water and Hydrocarbon Vapour, Journal of Canadian Petroleum Technology, January-February 1991), pp. 97-100. 20.Kisman, K.E., and Lau, E.C., A New Combustion Process Utilizing Horizontal Wells and Gravity Drainage, Journal of Canadian Petroleum Technology, March, 1994, pp. 39-45. 21.Sarma, H.K., Horizontal Well Production: A Research Perspective, HWC 94-11, Canadian SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 22.Huang, W.S., et al., Case History of a Horizontal Well Waterflood Project in New Hope Shallow Unit, TexasAn Update, HWC 94-08, Canadian SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 23.Sauquet, B.C., et al., Steam Injection in a Low-Permeability Reservoir through a Horizontal Well in Lacq Superieur Field, SPE 20526, 65th SPE Annual Tech. Conf. & Exh., New Orleans, Sept. 23-26, 1990. 24.Kuhach, J.D., and Myhill, N.A., Optimizing of a Mature Steam Flood Utilizing Horizontal Wells, Midway Sunset Field, HWC94-49, Canadian SPE/CIM/CANMET Intl Conf. on Recent Advances in Horizontal Well Applications, Calgary, Mar. 20-23, 1994. 25.Carpenter, D.E., and Dazet, S.C., Horizontal Wells in a Steamdrive in the Midway Sunset Field, SPE 24127, SPE/DOE 8th Symposium on EOR, Tulsa, Apr. 22-24, 1992. 26.Bruckert, L., Horizontal well improves oil recovery from polymer flood, OGJ, Dec. 18, 1989, pp. 35-39. 27.Dietrich, J.K., The Kern River Horizontal Well Steam Pilot, SPE 16346, SPE California Regional Meeting, Ventura, Apr. 8-10, 1987. 28.Martins, E.J, et al., Recovery of Attic Oil Through Horizontal Drilling, SPE 26334, 68th SPE Annual Tech. Conf. & Exh., Houston, Oct. 3-6, 1993. The Authors Hemanta Sarma is an invited research consultant at the Enhanced Recovery Laboratory of Japan National Oil Corp.s Technology Research Center, Chiba, Japan, where he advises on research and development and field applications. Previously, he worked for the Petroleum Recovery Institute of Calgary, Oil India Ltd., and ONGC, India. Sarma has a Bachelor of Technology in petroleum engineering from the Indian School of Mines, an MS in chemical engineering from the University of Calgary, and a PhD in petroleum engineering from the University of Alberta. He is a member of the SPE and is a Professional Engineer in Alberta. Kenji Ono is the director of the Enhanced Recovery Laboratory at the Technology Research Center of the Japan National Oil Corp., Chiba, Japan, and is responsible for the strategic planning of the EOR/IOR programs for JNOC. He has held various managerial and technical positions in the Japanese petroleum sector, both in domestic and international operations. Ono has a BS and an MS in petroleum engineering from the Waseda University, Tokyo. He is a member of the SPE and the Japanese Association for Petroleum Technology. Copyright 1995 Oil & Gas Journal. All Rights Reserved.

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