Steam-Soak Performance in South Oman
- S.A. Rice (Petroleum Development Oman LLC)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1991
- Document Type
- Journal Paper
- 459 - 466
- 1991. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 1.14 Casing and Cementing, 4.1.9 Tanks and storage systems, 5.4.6 Thermal Methods, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.7.2 Recovery Factors, 5.5 Reservoir Simulation, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale
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With about 2 x 10 stock-tank M3 [12.6 x 10 STB] of medium/heavy oiloriginally in place (OOIP) in south Oman, considerable scope exists forincreasing oil recovery by thermal methods. The viability of thermal recoveryin south Oman was tested with a steamflood pilot in the Al Khlata sands of theMannul field and a 2-year steam-soak project to test the applicability of steamsoak in five south Oman oil fields producing heavy oil. This paper describesthe performance of the latter project. The wells selected for the test programincluded a wide range of south Oman reservoir and oil the main reservoir drivemechanisms of depletion, solution-gas, and edge- and bottomwater drive, thereservoir sandbody types, and oil viscosities from 80 to 4000 mPa's [80 to4,000 cp]. Steam-soak operations were successful, and oil productionaccelerated significantly, with an average stimulated production rate twicethat before stimulation. Acceleration was less marked in wells where reservoirenergy is limited or where the primary (cold) water cut is more than 30 %. Atprimary (cold) water cuts >50 %, no increase in oil production rate wasprimary (cold) water cuts >50 %, no increase in oil production rate wasobserved. The process was simulated numerically for several wells, with theresults in close agreement with performance. Improved understanding of theprocess resulting from the simulation allowed the most important factorsinfluencing performance to be identified and aided process optimization in thefield test. Two small-scale steam-soak projects currently are being assessedfor implementation in the early 1990's.
In south Oman, most reservoirs contain medium to heavy oil in sandstones.The OOIP of these reservoirs is about 2 x 10 stock-tank M3 [12.6 x 10 STB],with an expected average primary recovery factor of about 10%. A large scopeexists for increasing oil recovery by thermal EOR methods. PetroleumDevelopment Oman LLC embarked on a program to test the viability of thermalrecovery in south Oman with a steamflood project in the Al Khlata sands of theMarmul field in 1985. A 2-year steam-soak project began in Oct. 1986 to testthe applicability of steam soak in five south Oman fields.
Madhava et al. described the reservoir properties of south Oman fields andthe strategy and production methods used to develop them. They also describedthe basis for the steam-soak tests in several fields. The major objectives ofthe steam-soak project were (1) to gain field experience, (2) to understand theprocess and field performance, (3) to identify the most attractive candidatesteam-soak projects, and (4) to reappraise facilities to reduce costs. Thispaper describes the field performance and the understanding of the steam-soakprocess gained during these tests.
South Oman Reservoirs
Reservoirs usually occur at depths ranging from 800 to 1300 m [2,620 to4,260 ft]. The wells selected for the steam-soak tests are in reservoirs in theAmal, Marmul, Mukhaizna, Nimr, and Rahab fields (Fig. 1). Properties of theselected reservoirs and wells listed in Table 1 are typical of those in southOman.
Reservoirs in south Oman are found mainly in the Haima group and the AlKhlata and Gharif formations, which were formed under various depositionalenvironments: aeolian, braided stream, glacial, fluvial, and alluvial.Connectivity and continuity range from poor to good. poor to good. Recovery,owing to depletion drive above the bubblepoint pressure (reservoir liquidexpansion), is in the range of 0.5 to 1 % pressure (reservoir liquidexpansion), is in the range of 0.5 to 1 % stock-tank OOIP (STOOEP) in allreservoirs. Either bottom- or edgewater provides moderate to strong drives andwill enable from 5 to 15 % provides moderate to strong drives and will enablefrom 5 to 15 % STOOIP to be produced before the economically limiting of rateor water cut is reached. Primary reserves depend mainly on oil viscosity andformation geology. In Marmul, solution-gas drive alone will enable up to 4%STOOIP to be recovered.
Wells and Facilities Used
Wells were cased with 24.4-cm [91/2-in.] L80/VAM casing and cemented withClass G cement plus 40% silica flour. Most were completed with internal gravelpacks. A packer-type completion was run in most wells, with insulated tubingand a downhole expansion joint. An insert pump (8.9 cm [3.5 in.]) was installedwith a maximum lifting capacity of 180 M/d [1,130 B/D]. A bypass nipple wasincluded in the completion string to facilitate pumping.
In four of the fields, a single-pass mobile steam generator that could belocated close to the wellhead was used. It had a maximum capacity of 220 t/d[1,390 B/D cold-water equivalent (CWE)] at a measured tubing-head pressure of15.5 MPa [2250 psi] and a steam quality of 80%. In the Marmul field, steam fromthe steam-pilot boilers was available through an insulated line. Steamvolumetric injection rates were measured with an orifice plate, and steamquality was measured by chloride ion determination and/or a steam-densityprobe. A mobile test unit and cooler were used during the first month probe. Amobile test unit and cooler were used during the first month of hot production;thereafter, normal field facilities were used for metering.
Steam-soak experience in the U.S. indicated that the local reservoirproperties and the drive mechanism(s) operative are the main factorsdetermining performance. Operational variables, such as completion interval,steam injection rate, soak duration, and both number and duration of cycles,affect performance very weakly. Because performance is mainly inherent to awell, the selection of suitable and representative wells was veryimportant.
Existing thermally competent wells were screened to select candidates inwhich stimulation would not cause production at pump-limited rates and in whichthe net/gross ratio was >0.6 and the pump-limited rates and in which thenet/gross ratio was >0.6 and the current water cut was less than 50 %.About 20 wells with gross rates below 100 M/d [630 B/D] and 50% water cut wereidentified.
Further screening reduced the number of candidate wells to 12 that hadcharacteristics embracing the main drive mechanisms, formations, and range ofoil viscosities in south Oman. In addition, three of the wells selected hadwater cuts of more than 10 % before steam injection, and in another two wells,water cut was expected to develop during the first cycle. These wells arerepresentative of those in a later phase of production life.
Because the reservoirs are fairly deep, under high pressure (typically 10MPa [1,450 psi]), and contain highly undersaturated oil, injectivity isinitially limited (about 50 to 200 t/d [315 to 1,260 B/D CWE]), flow within thereservoir is viscosity-dominated, and about 20 to 50% of injected heat is lostfrom the insulated injection-tubing string. Heat-loss calculations showed thatat steam injection rates less than 40 to 60 t/d [ less than 250 to 380 B/D CNW](depending on depth), only hot water entered the formation. The presence of anactive edge or bottom aquifer may reduce the thermal efficiency of the steamsoak and even prevent any stimulation of productivity once aquifer waterarrives at the well. Tables 2 and 3 list the production performance of eachcycle for each well. performance of each cycle for each well.
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