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Horizontal well applications in steamflooding

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Horizontal wells are being employed in innovative ways in steam injection operations to permit commercial exploitation of reservoirs that are considered unfavorable for steam, such as very viscous oils and bitumen and heavy oil formations with bottomwater. This page discusses some of the ways in which horizontal wells have been used to enhance steamflooding.


Numerous papers have explored steam injection using horizontal- vertical-well combinations by use of scaled physical models or numerical simulators. For example, Chang, Farouq Ali, and George[1] used scaled models to study five-spot steamfloods, finding that for their experimental conditions, a horizontal steam injector and a horizontal producer yielded the highest recovery. Fig. 1 shows a comparison of oil recoveries for various combinations of horizontal and vertical wells and for four different cases: homogeneous formation, 10% bottomwater (% of oil zone thickness), 50% bottomwater, and homogeneous formation with 10% pore volume solvent injection before steam. Huang and Hight[2] carried out numerical simulations of a variety of hypothetical situations involving horizontal and vertical wells. A few field-tested applications of horizontal wells are briefly described next.

Vertical injectors, multilateral producer: Kern hot plate test

Dietrich[3] described the Kern Horizontal-Well Pilot, in a high viscosity (about 5,000 cp) oil reservoir, shown in Fig. 2. Key data are given in Table 1. Eight vertical injectors were used to inject steam at an average rate of 1,900 B/D (CWE). The producer consisted of 8 branches of ultra-short radius horizontal wells. The project operated for about 14 months. The production response from the wells averaged 120 B/D. The project was not economic (steam-oil ratio of 15) because of unfavorable placement of the horizontal producer and other factors.

Vertical injectors and horizontal producer with bottomwater: Tangleflags project

Jespersen and Fontaine[4] described the Tangleflags project that utilizes a system of vertical injectors and horizontal producers. There are 11 producers. Table 1 gives the key data for the project. Fig. 3 shows the first well, together with the estimated sizes of the steam zones around the vertical injectors at three different times. The original horizontal well (400 m [1,312 ft] in length, but only 107 m [351 ft] were open to flow) was drilled for primary production, but the water cut became prohibitive within months, at which time it was decided to inject steam into the offset vertical wells. As a result, the water cut declined rapidly and stayed at a low value. The well produced almost 2.5 million bbl of oil. It should be noted that a small, discontinuous primary gas cap is present over the field. Temperature surveys showed that the injected steam migrated into the gas cap and during the early part of the project, exerted a downward drive, restricting the advance of the oil/water contact. At a later stage, steam injection rate was decreased and fluid flow was gravity controlled.

There are several other steam injection operations like Tangleflags. If the vertical permeability is high, and gas cap absent or small, an operation utilizing horizontal producers and vertical injectors may be viable.

Steam assisted gravity drainage

Steam assisted gravity drainage (SAGD) is an outstanding example of a steam injection process devised for a specific type of heavy oil reservoir utilizing horizontal wells. Use of this technology has expanded rapidly in Canada. For more information about this technology see Steam assisted gravity drainage.

Cyclic steam stimulation and other uses of horizontal wells

Horizontal wells are being used for cyclic steam stimulation, much in the same manner as vertical wells, in Cold Lake, Alberta, and in Eastern Venezuela. In Cold Lake, horizontal well lengths are of the order of 3,000 ft, and steam slugs are very large (100,000 to 200,000 bbl). The resulting steam/oil ratios are 2 to 4, and performance is superior to SAGD continuous steamflood.[5] In Venezuela, wells are around 1,000 ft in length, and the steam slugs are of the order of 50,000 bbl. Response is good, with average stimulation ratios of 2 to 4 over a production period of 6 months.

In California, horizontal wells have been used sparingly in thermal projects, mainly because of sand control problems but also because of the fact that vertical wells are very cost effective, and it is difficult for horizontal wells to be competitive. Horizontal wells have successfully been incorporated into existing thermal projects to supplement conventional vertical-well performance for both Midway Sunset field cyclic steam[6][7] and Cymric/McKittrick field steamfloods.[8] In the Duri field, Indonesia, horizontal wells are also being used to supplement conventional vertical-well steamflood.[9] Table 1 shows reservoir data for these three areas. All of these latter applications are accessing bypassed oil in mature projects for which vertical wells would be impractical. Fig. 4 is a schematic drawing showing the wedges of oil sand in the Midway Sunset cyclic steam project at the very bottom of the zones that cannot be accessed by the existing vertical wells but will be drained by the horizontal wells. Fig. 5[9] shows the result of a seismic study of the mature Duri steamflood. Highlighted on the map are pockets of oil that were bypassed by the flood because of proximity to a fault. The operators are strongly considering a suite of horizontal wells to access these reserves.


  1. 1.0 1.1 Chang, H.L., Ali, S.M.F., and George, A.E. 1992. Performance Of Horizontal-Vertical Combinations For Steamflooding Bottom Water Formations. J Can Pet Technol 31 (5). PETSOC-92-05-04.
  2. Huang, W.S. and Hight, M.A. 1989. Evaluation of Steamflood Processes With Horizontal Wells. SPE Res Eng 4 (1): 69-76. SPE-14130-PA.
  3. 3.0 3.1 Dietrich, J.K. 1988. The Kern River Horizontal-Well Steam Pilot. SPE Res Eng 3 (3): 935-944. SPE-16346-PA.
  4. 4.0 4.1 Jespersen, P.J. and Fontaine, T.J.C. 1993. The Tangleflags North Pilot: A Horizontal Well Steamflood. J Can Pet Technol 32 (5). PETSOC-93-05-05.
  5. Scott, G.R. 2002. Comparison of CSS and SAGD Performance in the Clearwater Formation at Cold Lake. Presented at the SPE International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference, Calgary, 4–7 November. SPE-79020-MS.
  6. Chona, R.A., Love, C.L., Rajtar, J.M. et al. 1996. Evaluation of a Horizontal Infill Well in a Mature Cyclic-Steam Project. Presented at the International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, 18-20 November 1996. SPE-37087-MS.
  7. McKay, C., Jones, J., and Pomerene, J. 2003. Successful Horizontal Producers in Midway-Sunset Thermal Operations. Presented at the SPE Western Regional/AAPG Pacific Section Joint Meeting, Long Beach, California, 19-24 May 2003. SPE-83479-MS.
  8. Cline, V.J. and Basham, M. 2002. Improving Project Performance in a Heavy Oil Horizontal Well Project in the San Joaquin Valley, California. Presented at the SPE International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference, Calgary, Alberta, Canada, 4-7 November 2002. SPE-78981-MS.
  9. 9.0 9.1 9.2 Sigit, R., Satriana, D., Peifer, J.P. et al. 1999. Seismically Guided Bypassed Oil Identification in A Mature Steamflood Area, Duri Field, Sumatra, Indonesia. Presented at the SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, 25-26 October 1999. SPE-57261-MS.

Noteworthy papers in OnePetro

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See also

Steamflood design

Thermal recovery by steam injection

Cyclic steam stimulation design

Steam delivery systems for EOR

Steamflood heat management

Horizontal wells