Fiber-Optic Distributed Temperature Sensing Technology Used for Reservoir Monitoring in an Indonesia Steam Flood
- Dhirendra K. Nath (Halliburton) | Riki Sugianto (Chevron North America Exploration and Production Co.) | Douglas B. Finley (Well Dynamics Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2007
- Document Type
- Journal Paper
- 149 - 156
- 2007. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 5.9.2 Geothermal Resources, 1.14 Casing and Cementing, 5.1.5 Geologic Modeling, 1.6 Drilling Operations, 1.6.9 Coring, Fishing, 3.2.6 Produced Water Management, 2.4.6 Frac and Pack, 5.4.6 Thermal Methods, 2.4.3 Sand/Solids Control, 2.2.2 Perforating, 2.4.5 Gravel pack design & evaluation, 3.2.5 Produced Sand / Solids Management and Control, 5.6.11 Reservoir monitoring with permanent sensors, 1.2.1 Wellbore integrity, 4.1.2 Separation and Treating, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 3.3 Well & Reservoir Surveillance and Monitoring
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- 726 since 2007
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The world's largest steamflood operation is conducted on the island of Sumatra in Indonesia. Fiber-optic distributed-temperature-sensing (DTS) surveys are used in the Sumatra fields to provide valuable data for reservoir management. The DTS profile data can determine the temperature and extent of a "steam chest,?? a phenomenon that occurs when steam injected into a steam-injection well moves away from the perforations until it encounters an impermeable barrier in the formation. The steam then extends laterally until breakthrough occurs at the producing well. Because oil is produced by gravity drainage, the steam chest (also known as a steam-saturated volume) grows downward. DTS surveys also have the capacity to determine the temperature gradient for either overburden or underburden reservoirs. This information is vital for properly setting steam-injection target rates. The information is also used to mitigate steam breakthroughs and eruptions, as well as to identify bypass oil.
Steamflood operations experience many types of problems, including inefficient injection rates, wasted heat to the casing, sanding in producers, liner failures, and pump failures. There is also an ongoing need to improve the efficiencies of vapor collection systems, well-test stations, and central gathering stations. Based on these challenging problems, periodic wellbore temperature surveys are required to improve heat management and, ultimately, profitability. Conventional temperature logs cannot be run in these wells without first pulling the pumps from the completion. Therefore, a fiber-optic DTS system attached to the production tubing was suggested.
This paper will present case histories of successful applications of fiber-optic DTS surveys that improved steamflood management in this steamflood field in Indonesia.
The benefits from fiber-optic DTS monitoring were
- Significant improvement in the understanding of steam breakthrough zones along the pay-zone interval of production wells.
- Improved understanding of the steam path in steam-injector wells.
- Improvement of the real-time temperature profile in observation wells to identify steam-zone development and unswept or bypassed oil zones in the steamflood patterns.
The steam-flood field is a multibillion-barrel, heavy-oil-producing field that lies on the central Sumatra basin in Indonesia (Fig. 1). The field consists of approximately 4,114 producers, 1,610 steam injectors, and 450 temperature-observation wells. Thermal enhanced oil-recovery (EOR) methods are implemented to reduce oil viscosity and improve oil recovery from this heavy-oil-bearing formation. Active steamflooding began in 1985.
Typically, one steam injector well is surrounded by a pattern of producing wells. Each well pattern in the field will generally include a temperature-observation well to monitor formation temperature response to the steamflood.
This steamflood field includes three primary oil-producing sands. The two deeper sands have a combined pay thickness of approximately 140 ft and range from 400 to 700 ft in true vertical depth (TVD). These sands are the principal oil-bearing sands and account for approximately two-thirds of the original oil in place (OIP). These two sand layers are the primary steam injection targets. The producing sands are unconsolidated, with formation liquid permeability ranging from 100 to 4,000 md. Formation porosity ranges from 15 to 45%. The crude oil is heavy, with API gravity ranging from 18 to 22°API at 60°F.
Because of the highly unconsolidated formations in the steamflood field, completing the wells with sand-control equipment is standard practice. The conventional completion methods that have been used to control sand production are cased-hole gravel packs (CHGP), openhole gravel packs (OHGP), and cased-hole frac packs (CHFP) (see Fig. 2). In each completion, a 65/8- or 4-in. screen liner, depending on the casing size, is installed before performance of the gravel-pack or frac-pack treatment.
With all enhanced recovery techniques, early breakthrough of the injected fluid at a producing well is a major issue because it can significantly impact the production of each individual well. Because of the subsequent consequences to field economics, steam management is critical to the economical operation of all steamfloods. Particularly as the areas mature and begin their rampdown, careful attention is required to identify steam breakthrough so that it can be prevented or mitigated. Immediate attention to assessment and control of this phenomenon can drastically improve the life of a well (Johnson and Sugianto 2002; Sigit et al. 1999).
The process for determining heat requirements for a pattern is complicated, especially with low-density observation wells. Setting injection rates too low will lead to slow steam-chest growth, possible collapse of the steam chest, loss of reserves, and overall lower production. On the other hand, setting injection rates too high will lead to wasted heat in the casing, higher fuel costs, sanding problems in producers, liner failures, pump failures, and overall lower field reliability in the casing-vapor collection systems, well-test stations, and central gathering stations. In some cases, higher rates may contribute to surface steam eruptions.
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Johnson, D.O., Sugianto, R., and Mock,P.H. 2002. Identification of SteamBreakthrough Intervals Using DTS Technology. Paper SPE 77460 presented atthe SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29September-2 October. DOI: 10.2118/77460-MS.
Nath, D.K. 2005. Fiber Optic Used to Support ReservoirTemperature Surveillance in Duri Steamflood. Paper SPE 93240 presented atthe SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 5-7 April.DOI: 10.2118/93240-MS.
Sigit, R., Satriana, D., Peifer, J.P.,and Linawati, A. 1999. SeismicallyGuided Bypassed Oil Identification in a Mature Steamflood Area, Duri Field,Sumatra, Indonesia. Paper SPE 57261 presented at the SPE Asia PacificImproved Oil Recovery Conference, Kuala Lumpur, 25-26 October. DOI:10.2118/57261-MS.