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Carbonate reservoir with waterflood and miscible injection

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This page provides several reservoir management case studies that illustrate carbonate reservoirs in which waterflooding and miscible gas injection techniques have been implemented.

Case 1

Background and geological information

This field produces primarily from a Jurassic-age limestone-dolomite section that has a simple plunging anticline structure. The updip trap is formed by a combination of facies change from dolomite to dense limestone and a bounding fault. The formation is layered and has been divided into 18 correlative zones.

Program used

The field was developed competitively by several operators. When production began, the reservoir pressure declined rapidly under a fluid-expansion drive. The field was unitized, waterflooding began, and pressure decline was arrested. Miscible N2 injection was started eight years later. N2 was selected rather than methane or CO2 because of cost and supply considerations.

The field was developed initially with 89 wells on 160-acre spacing. Selective infill drilling in poorer sections of the reservoir (both areally and vertically) improved the sweep of injected water. The need for fieldwide infill drilling to 80-acre spacing was tested with five wells and shown to be uneconomical because little extra recovery was achieved.

The waterflood was implemented with a 3-to-1 line-drive pattern with low salinity water from a water-source well. Produced water is also injected. Peak water-injection rates reached 250 kBOPD. Three air-separation units produced nitrogen, which was reinjected. Peak injection rate was 86 Mcf/D. A water-alternating-gas (WAG) process is used.

There is no downhole corrosion treatment and no internal treatment of flowlines and pipelines. Flowlines and pipelines are protected cathodically and require selective remediation. Corrosion resistant alloy tubulars and flowlines are used to handle the 2% H2S (originally 8% but reduced by N2 contamination) sour gas produced from the field.

Recovery performance

Primary recovery of 17% of OOIP was expected. Waterflooding increased this to 57%, and the miscible project added another 13% of OOIP.

Field surveillance and management

This field has had several periodic reservoir studies to update and refine the depletion strategy and a sustained surveillance program that includes acquisition of data needed to monitor reservoir behavior and injection efficiency. To obtain an accurate geologic description, the entire pay interval in virtually all the wells was cored. The reservoir surveillance program included the monitoring of production data, injection data, bottomhole pressures, flood balancing, WAG ratios, injection-to-withdrawal ratios, and profitability of each pattern. One of the tools used is a history-matched four-component compositional-simulation model that is based on a stochastic geologic model and advanced scale-up technology. The 3D model contains 100,000 gridblocks and 18 layers. Good matches of pressure and oil, water, and nitrogen production at the field and individual well levels were achieved with quality control of key input data and the use of extensive history-match experience.

Case 2

Background and geological information

This field is a north/south trending anticline separated into north and south domes by a dense structural saddle running east and west near the center of the field. Deposition was in an intertidal-lagoon-bank sequence. Production comes from formations at depths ranging from 4,200 to 4,800 ft (subsurface). The formation is more than 1,400 ft thick. The upper 200 to 300 ft is productive, and the remaining is a water zone of relatively low permeability. The productive upper portion of the reservoir is divided further into the upper and lower reservoirs. The average porosity is 9%, and the average permeability is 20 md.

Programs used

Primary/waterflood depletion

The field was developed initially on 40-acre spacing with 300 wells. The primary producing mechanism was a combination of fluid expansion with a weak waterdrive. In 1963, a unit was created and peripheral water injection began into 36 wells. Production from the unit began declining in 1967 because of insufficient pressure support. A detailed engineering and geologic study identified a flow barrier that was inhibiting pressure support between the upper and lower reservoirs. Implementation of a three-to-one line drive provided the needed pressure support, and production increased. When production began to decline again in 1972, a subsequent reservoir study resulted in a technique to correlate gamma-ray/neutron logs with core data, thus better defining porosity distribution and OOIP. The study resulted in an infill-drilling program to 20-acre spacing, conversion of the injection scheme to an 80-acre inverted nine-spot pattern, and a better reservoir surveillance program.

Infill drilling/miscible process

An oil viscosity of 6 cp makes the waterflood mobility ratio relatively high. From pressure cores and laboratory core floods, waterflood residual oil saturation was estimated to be 34% of PV. Combined, these two factors provided incentive for further infill drilling and evaluation of other recovery methods. A CO2 miscible project was evaluated with laboratory investigations, a field pilot, and reservoir simulations.

The proposed CO2 project consisted of 167 patterns on approximately 6,700 acres that encompassed 60% of the productive acres and 82% of the OOIP of the unit. Every attempt was made to use the original 40-acre wells and the 20-acre infill wells. Infill drilling to 10-acre spacing was an integral part of project development. All the WAG injectors and central producers were new 10-acre wells as a part of 40-acre inverted nine-spot patterns.

Within 2 years of project implementation, 205 infill producers and 158 infill injectors had been drilled. Re-evaluation of the project during implementation resulted in changes to project scope. The CO2 project now consists of 173 patterns on approximately 7,830 acres.

Recovery performance

Projected recovery from primary and waterflooding methods is 30% of the OOIP. Incremental recovery because of the miscible CO2 flood is 15% of the OOIP.

Field surveillance and management

Throughout the years, a number of reservoir description and engineering studies have been conducted with the goal of developing better reservoir management strategies. A detailed, integrated surveillance and reservoir management program was implemented to achieve areal-flood balancing, vertical-conformance monitoring, production monitoring, injection monitoring, data acquisition and management, pattern-performance monitoring, and optimization. The following are some key objectives of field surveillance and management.

  • Integrate all knowledge and data, such as seismic, core, log, laboratory work, and outcrop and field observations, into a fieldwide geologic model and keep it up to date
  • Monitor and understand field performance
  • Increase WAG frequency to minimize problems associated with premature gas breakthrough
  • Maintain a system-operating pressure between the reservoir-parting pressure and the MMP. Falling outside this narrow range would compromise ultimate recovery by fracturing the reservoir or eliminating the miscibility component of the flood
  • Manage the GOR to fit compression limitations for recycled CO2
  • Update assessments of facility capacity
  • Maintain automated injection, production, and artificial lift monitoring systems to capture data needed to develop programs for maintaining flood-front pressure by balancing the WAG schedule, ratios, and CO2 slug sizes
  • Implement proactive corrosion- and scale-treatment programs
  • Use new infill wells for injection purposes to minimize downhole mechanical problems
  • Maintain a continuous injection-well profiling program for flood management purposes

Case 3

Background and geological information

The field is a carbonate reef-mound complex of Late Pennsylvanian to Early Permian age with a formation composed of limestone with minor amounts of shale. It reaches a maximum thickness of 918 ft and averages 315 ft. Skeletal and oolitic grainstone shoals form the most significant reservoir facies. More than 90% of the porosity is secondary because of freshwater dissolution of unstable framework grains. Cores indicate the presence of fracturing and enhanced dissolution along fractures. Channeling of water and/or CO2 is evident between many injector/producer pairs.

Program used

Primary development was followed by a centerline waterflood that was converted subsequently to a five-spot waterflood with two infill-drilling campaigns. A polymer-augmented waterflood was implemented on the basis of data from the new wells. The possibility of enhanced natural gas liquids production was identified with compositional reservoir simulation studies. A CO2 miscible WAG injection process was then initiated.

Recovery performance

CO2 -WAG injection is expected to result in an additional recovery of 12% of the OOIP, bringing the total estimated ultimate recovery to 64% of OOIP. The solvent extraction capability of CO2 has resulted in an increase of up to 6,000 B/D in natural gas liquids production.

Field surveillance and management

Interdisciplinary teams composed of geoscientists; reservoir, production, and facilities engineers; and field operation staff conducted reservoir management. Cores from 30 of the wells were analyzed for stratigraphy and depositional sequences, and these interpretations provided the basis for a reservoir model that has been updated and enhanced throughout the life of the field. 3D geologic and simulation models are integrated into the surveillance process for flood optimization, workover and drill well planning, and WAG management.

Case 4

Background and geological information

The reservoirs in this field are part of a Devonian atoll reef and carbonate shoal complex consisting of limestone with traces of:

  • Dolomite
  • Pyrite
  • Anhydrite

The hydrocarbons are trapped stratigraphically by a calcareous shale seal. The reservoir averages approximately:

  • 200 ft of gross pay
  • 8% porosity
  • 50 md permeability

Some stringers have permeabilities of 2000 to 3000 md, which result in high well productivities. Oil characteristics include a gravity of 44°API and a formation volume factor of 1.8 RB/STB. The reservoir depth averages 9,000 ft, and the initial water saturation was 14%.

Program used

The primary recovery mechanism was solution-gas drive. In 1964, the field was converted to a downdip peripheral waterflood. Originally, the field was developed on 160-acre spacing. Selective infill drilling to 80- and 40-acre spacing has been used in updip portions of the field to develop areas of poor reservoir continuity that contain unswept oil.

Recovery performance

Under primary recovery, the field produced 1% of original oil in place (OOIP). Recovery to date under waterflood has been an additional 45% of OOIP. An ultimate recovery efficiency of 49% of OOIP is forecast.

Field surveillance and management

The waterflood is being balanced in four discrete geologic regions or flow units to replace voidage and improve areal-sweep efficiency. The replacement ratio has averaged 100%.

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See also

Reservoir management


Miscible flooding