SPECIAL REPORT: Technology advances continue to unlock additional resources

Jan. 28, 2008
Technology advances are allowing companies to extract more oil and gas from resources that in previous years were uneconomic to develop.

Technology advances are allowing companies to extract more oil and gas from resources that in previous years were uneconomic to develop. These resources include gas found in tight sands, shales, and carbonates; extra heavy oil; and additional oil from mature fields that require enhanced or improved recovery techniques.

Various papers from the SPE Annual Technology, Nov. 11-14, 2007, provide insights into technologies that companies use or will use to facilitate recovery of these resources.

Gas

Hydraulic fracturing is a key technology for obtaining higher producing rates and recoveries from unconventional gas accumulations.

One problem has been that in some locations the height of the created hydraulic fracture may intersect water-bearing sands. A potential solution for this problem, as described in a paper by D.L. Fairhurst and others,1 is to fracture the sands with carbon dioxide contained in a visceoelastic fracture fluid. The method, according to the paper, will minimize fracture growth to prevent fracturing water sands while attaining sufficient fracture length in the gas sand.

The paper describes an optimization study on South Texas tight gas sands that were 20-50 ft away from the water sands. The laminated sand and shale sequences in this South Texas area contain gas sands with 0.05-0.8 md permeability at a 4,500 ft depth while the thicker water-bearing sands have 0.1-2.0 md permeability.

Another tight gas formation, 0.003-0.015 md permeability, in which technology has helped redevelop is the Cleveland formation that lies at 6,500-8,200 ft depths in northeastern Texas Panhandle and Oklahoma (Fig. 1). The formation is an interbedded sequence of sand with thin shale laminations and fine-grained sandstone. A paper by Neil C. Decker and others describes the success of operators such as BP PLC in drilling infill horizontal wells in the Cleveland.2

Click here to enlarge image

The Cleveland formation was discovered in the late 1950s and originally developed with vertical wells on 640-acre spacing and later infill drilled so that wells now have mostly 160-acre spacing. The paper stresses that the success of the infill wells has resulted from acquiring and analyzing data to optimize horizontal well configuration and completion type. The data used come from extensive subsurface mapping, core analysis, openhole logging, microseismic acquired during hydraulic fracturing, injection fall-off tests, and production-decline analysis.

The newer horizontal completions in the Cleveland typically include openhole multiple packers and sliding-sleeve ports to allow fracturing one interval at a time, and studies show that a fraced 1,600-ft horizontal well may provide a 1.4-MMscfd initial production rate and an ultimate recovery of about 1.4 bcf, according to the paper.

New technologies have also been instrumental in accelerating development of Barnett shale gas in North Texas by cutting drilling days and reducing the days for wells to go on stream, according to a paper by Drew Jennings and others.3 In the northern part of the field, the paper attributes the accelerated development pace to the use of polycrystalline diamond compact (PDC) bits, modified drillstrings, and new operating practices that have reduced drilling times by 62%.

In the south part of the field, the paper says, a new approach to critical failure analysis doubled drilling performance through the curved section with new roller cone bits.

The paper explains that in the northern section during a 6-month period, only one PDC bit run was required to drill the 83⁄4-in. vertical section in 23 of 30 wells, cutting costs by $150,000 and reducing drilling time by 62%. In the south, new roller cone bits increased the rate of penetration to 18.8 fph from 10.2 fph, saving $1.68 million over 15 wells.

Acid fracturing is improving gas recovery from the Strawn formation, a carbonate, in the Permian basin of West Texas, according to a paper by G. Zaeff and others.4 The paper attributes the success of the treatments in Terrell County, Tex., wells to a new polymer-free self-diverting acid combined with an existing acid-oil emulsion.

The paper describes the typical treatment as consisting of a linear-gel pad fluid, raw 20% hydrochloric acid, acid-internal emulsion (AIE), linear-gel pad fluid, followed by the self-diverting acid based on a viscoelastic surfactant (SDVA). The ratio of AIE is about 3:1 and the volume of SDVA usually is 2,500-3,500 gal/stage.

Heavy oil

Exploitation of heavy oil and bitumen resources has gained momentum in recent years as demand for crude has increased and crude prices have remained high. The Orinoco tar belt in Venezuela and the oil sands in northern Alberta are two of the areas with the most activity. These regions contain several trillion bbl of extra heavy, less than 10° gravity, oil in place, and various estimates place potential recovery at several hundred billion bbl.

In Venezuela, cold production recovers the heavy oil through long-reach highly deviated, horizontal, and multilateral wells. Recovery of Alberta’s oil sands bitumen, on the other hand, mainly relies on mining and thermal processes. Mining currently accounts for about 750,000 bo/d, while cyclic steam production is about 250,000 bo/d and steam-assisted gravity drainage (SAGD) production accounts for another 200,000 bo/d.

Several mining projects being developed or proposed in Alberta may increase bitumen production by another 2 million bo/d and proposed thermal projects may add another 1.5 million bo/d during the next decade.

Cyclic-steam stimulation with horizontal and highly deviated wells is one option being evaluated by Shell Canada Ltd. in the Peace River area, according to a paper by Paul F. Koci and Junaid G. Mohiddin.5 The paper notes that the Peace River Carmon Creek area holds about 3 billion bbl of 7° gravity oil in place and stimulation studies indicate that the optimum method to develop about half of these resources is through cyclic-steam simulation in horizontal or highly deviated wells (Fig. 2) at close well spacing of less than 75 m.

Click here to enlarge image

The paper notes that Shell also has tested various thermal recovery schemes in Peace River including in situ combustion, steam drive, SAGD, and cyclic steam injection but selected cyclic steam in horizontal wells for Carbon Creek.

Shell plans to develop Carbon Creek in two 50,000-bo/d phases, staged over the projects’ 40-year life. If Shell obtains regulatory approval, construction of the project will start in 2008 for Phase 1 and 2011-15 for Phase 2.

Suncor Energy Inc. has an ongoing SAGD project in the oil sands of Alberta (Fig. 3), but the high steam temperature required it to install special designed downhole pumps. In a paper, F. Gaviria and others say that Suncor installed electric submersible pumps (ESPs) in its Firebag SAGD project that could withstand bottomhole temperatures of 180-209° C. compared with standard ESPs that are rated for 149° C. bottomhole operating conditions.6

Suncor in its Firebag SAGD project in the oil sands of Alberta employs special high-temperature electric submersible pumps (Fig. 3). Photo from Suncor.
Click here to enlarge image

The paper notes that the pumps have reduced the downhole pressures thereby improving the steam/oil ratio, which in turn has reduced operating expenses by several million dollars as a result of reducing the amount of water treated and the fuel used to generate the steam.

The paper says, Suncor is experiencing 500-day run times with the ESPs. Since first installation of an ESP in June 2005, the size and capacity of the pumps installed have increased to 2,500 cu m/day from 1,000 cu m/day. Pump horsepower has increased to 250 hp, up from 150 hp in the initial installations.

Suncor has also changed the intake configuration from a straight intake to a bottom-feeder gas separator (BFGS), then to an advanced gas handler (AGH), and now to a combination of the BFGS and AGH.

The company lands the pumps in the horizontal lateral at a 450-700 m measured depth. The first 21 installations have average ESP run times of 311 days, with the longest being 658 days and the shortest 29 days, according to the paper.

IOR

A novel ceramic coating on the rotors along with an optimized interference fit between the rotor and stator and adjusted elastomer rigidity in progressing-cavity pumps (PCPs) have improved downhole pump run times in the alkaline-surfactant-polymer (ASP) flood portions of Daqing oil field in northern China, according to a paper by C. Gang and others.7

Because of the injected alkali lye reaction with the formation, the flood experiences severe scale near the wellbore, on the surface of downhole equipment, and in pipe IDs. The paper described the scale as an amorphous state silicon dioxide, hexagonal-spherical calcite, and conventional calcite, along with minor minerals.

Since 2003, 43 PCPs with ceramic-coated rotors averaged 416-day run times with the longest being 512 days, according to the paper. The paper also noted that since 2005, four pumps with the ceramic-coated rotor, optimized interference fit, and adjusted elastomer rigidity had a 178-day average run time with the longest run time of 649 days.

Polymer flooding is another enhanced oil recovery used in the Daqing oil field. A paper by D. Wang and others says that at yearend 2006, more than 63 million bbl/year of oil production, sustained for 5 years, is attributed to polymer flooding.8

Since it was started 12 years ago, the paper attributes the success of the polymer floods to:

  • Recognizing when profile modification is needed before injecting polymer and when zonal isolation is needed during polymer injection.
  • Establishing an optimum polymer formulation, injection rate, and individual well production allocation.
  • Understanding the time-dependent variation of the polymer molecular weight in the injected slugs.

The paper describes the polymers used at Daqing as having 12-38 million Dalton molecular weights that are designed and supplied to meet the various reservoir conditions. It says the optimum polymer-injection volume varies but is about 0.7 pore volume, depending on the water cut of an area. Other design criteria it lists are a 1,000 mg/l. average concentration that can be more at individual injection stations and a 0.2 pore volume/year injection rate.

In another part of the world, redevelopment of Daleel oil field in Block 5 in northern Oman will entail use of horizontal water-injection wells. A paper by L. Zhang and others summarizes the positive response obtained with horizontal injection well in several pilot test at Daleel.9

Production from Daleel is from a Shuaiba carbonate formation at 1,500-1,610 m depth that came on stream in 1990 and produces a 38° gravity oil with 0.85 cp viscosity. Before Daleel Petroleum LLC acquired the field from Japex Oman in 2002, it had been depleted with vertical and horizontal wells.

The paper notes that recovery factors in similar fields have increased to 35-40% with waterflooding compared with on 15-20% with primary.

With a 35% recovery factor, ultimate oil recovery in Daleel will be 196 million bbl, according to the paper.

In other fields in Oman, Petroleum Development Oman (PDO) has had success in reducing unwanted water production in horizontal wells through use of swelling elastomers, according to a paper by Majid A. Mahrooqi and others.10

A large electric oven will vulcanize the Swellfix swelling elastomers on the standard tubulars (Fig. 4). Photo from Shell.
Click here to enlarge image

These elastomers swell when water contacts them, thereby isolating the water producing zone. The paper explains that the water-based elastomers are wrapped around normal casing joints and vulcanized together (Fig. 4). An osmosis process swells the elastomer when bottomhole temperatures are 50-90° C.

PDO targets the elastomers to isolate fractures, faults, and thief zones and not water influx from the matrix unless the matrix zone is confined and obvious.

The paper notes that PDO has deployed these elastomers in more than 100 horizontal wells and to March 2007 is attributing a recovery of 2.4 million bbl of addition oil to the use of this technology.

References

  1. Fairhurst, D.L., et al., “Advanced Technology Completion Strategies for Marginal Tight Gas Sand Reservoirs : A Production Optimization Case Study in South Texas,” Paper No. SPE 109863, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  2. Decker, N.C., et al., “Applied Technology Helps Revitalize a Maturing Giant Field: Learnings From the Cleveland Formation’s Horizontal-Well Redevelopment Program,” Paper No. SPE 109948, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  3. Jennings, D., et al., “Elevated Activity Levels Driving Technology Development at Record Pace: Barnett Shale, North Texas,” Paper No. SPE 109636, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  4. Zaeff, G., et al., “Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas,” Paper No. SPE 107978, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  5. Koci, P.F., and Mohiddin, J.G., “Peace River Carmon Creek Project—Optimization of Cyclic Steam Stimulation Through Experimental Design,” Paper No. SPE 109826, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  6. Gaviria, F., et al., “Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installation in Canada,” Paper No. SPE 110103, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  7. Gang, C., et al., “Technical Breakthrough in PCPs’ Scaling Issue of ASP Flooding in Daqing Oil Field,” Paper No. 109165, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  8. Wang, D., et al, “Key Aspects of Project Design for Polymer Flooding,” Paper No. 109682, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  9. Zhang, L., et al., “Horizontal Waterflooding in Shuaiba Carbonate Reservoir of Daleel Field in Oman From Pilots’ Performance to Development Era,” Paper No. SPE 108392, SPE ATCE, Nov. 11-14, 2007, Anaheim.
  10. Mahrroqi, M.A., et al., “Improved Well and Reservoir Management in Horizontal Wells Using Swelling Elastomers,” Paper No. SPE 107882, SPE ATCE, Nov. 11-14, 2007, Anaheim.