On 31 May 2001, Melrose completed the acquisition of various lease interests immediately adjoining existing interests in the Turner Gregory field area in Mitchell County, Texas. The lease interests acquired cover approximately 1,000 acres with proved reserves of 1.8 MMbbls and a discounted net present value of US$5.2 million. Current production from these leases is approximately 40 bopd net to the interests acquired. The acquisition cost was US$1.0 million.
Petrozene could easily increase production an average of 260% or more.
Melrose update: Turner Gregory field interests Work on the Turner Gregory Unit in 2004 was focused on bringing wellbores into regulatory compliance, including the abandonment of some old wells, prior to water injection operations commencing. In the meantime, average daily production declined in line with expectations by 10% during 2004 to 106 boepd. http://72.14.253.104/search?q=cache:s3Y9pHp8SXUJ:www.oil-barrel.com/pressreleases/melrose310305.pdf+....
Some DD bearing upon our new unit in Mitchell County: Mark Pawlewicz1 and Mitchell Henry2 1 U.S. Geological Survey, Lakewood, CO 2 U.S. Geological Survey, Denver, CO
Burial history models for boreholes in the Delaware and Midland basins, and the Central Basin Platform of the Permian Basin, west Texas and southeast New Mexico, calibrated using vitrinite reflectance (Ro), provide a means to evaluate the burial and thermal history of the most significant petroleum province in the United States.
Results indicate that the earliest petroleum generation began in Late Pennsylvanian time for the Woodford Shale in the northern Delaware basin and in Early to Late Permian time for other areas in the region. An exception is along the north margin of the Midland basin, where the Woodford Shale is just in the early stages of petroleum generation. Only four of six wells achieved temperatures high enough to generate gas; the earliest maturation conditions (1.2 %Ro) for gas generation exist in the Permian Simpson Group strata in south-central Midland basin.
The modeling indicates: (1) in the Delaware basin, the Woodford Shale, Barnett Shale, Wolfcampian strata, Bone Spring Limestone, and Delaware Mountain Group are in the oil window, and all but the Delaware Group are within the gas window; (2) for the Midland basin, Simpson Group, Woodford Shale, Barnett Shale, Wolfcampian strata, and Spraberry Formation achieved the oil window, and also the gas window except for the Spraberry; (3) for the east margin of the Central Basin Platform, the Simpson Group, Woodford Shale, Barnett Shale, and Wolfcampian strata are within the oil and gas windows, whereas the Clear Fork Group is only in the oil window; (4) on the west margin of the Central Basin Platform, all formations have passed into the gas window.
GEOLOGIC OVERVIEW
Clearfork is the Permian basin's discovery field. It was found in 1920 on the Eastern Shelf in northwestern Mitchell County. The first well pumped 10 bopd from an openhole completion in the Upper Clearfork after shooting with nitroglycerine. Main pay in the 3,000-ft Lower Clearfork was found when this well was deepened in 1921. Three large secondary units now account for most Clearfork production.
The field is a stratigraphic trap, dipping west at 60 ft/mi. The Permian-age Upper Clearfork zone is a lenticular anhydritic fine-crystalline dolomite with occasional small vugs and rare fractures. The overall Upper Clearfork interval is around 560 ft thick, and continues to thicken toward the basin. Pay porosity ranges from 4% to 16%, with the average being 7.4 %. Permeabilities average around 0.5 md, but occasionally reach 50 md. Gypsum and silty laminations are common in the Upper Clearfork environment, indicative of a low-energy tidal flat or lagoon.
The Middle Clearfork zone has better porosity development and reasonable well-to-well correlation. Average dolomite porosity is around 8%, with average permeability of 1 md. The initial Middle Clearfork reservoir pressure was 1,100 psi, and it produces 25° API sour oil. Although an apparent oil/water contact exists around 1,000 ft, the Middle Clearfork pay produces by limited solution gas. Core interpretation suggests that the Middle Clearfork is a series of stacked shoal complexes. Breakthrough of fracture treatments and injection water along a N 75° E bearing to the adjacent 10-acre well occurs frequently, due to an East/ West preferential permeability trend.
A NEARBY CASE STUDY: BRIEF HISTORY, SOUTHWEST "WESTBROOK UNIT":--(note the production numbers)
By 1964, 99 wells were on leases that would later be incorporated into the Southwest Westbrook Unit. The unit was formed in 1969 and operated by Union Texas. In its final form, the unit covers 3,833 acres, with calculated original oil in place of 61.6 million bbl. Union Texas immediately drilled injectors and converted producers to injectors to initiate injection. There were 26 injectors on 160-acre spacing.
Beginning in 1971, the unit's south end was infill-drilled on a 40-acre five-spot pattern. This continued until 1986, when the 40-acre five-spot pattern in the unit's north end was implemented in areas thought to be productive. In 1991, Meridian (Burlington) took over as operator and drilled, on 10-acre spacing, selected areas that its studies indicated to be the most productive. The injection pattern then became an east - west line drive, due to an east - west preferential permeability trend that was noted in several areas of the unit as it was down-spaced.
Gruy purchased the unit from Burlington in 1997 and continued to drill the 10-acre locations in what were thought to be the more productive, less risky areas. In 2004, a new team recommended a program of higher-risk drilling and recompletions, and it was initiated that same year. Cimarex bought the property from Gruy in June 2005 and continued this methodology at a much accelerated rate. Cumulative output is now 18.1 million bbl of oil.
THE SOLUTION
In 2003, a new team appointed to study the unit's upside was presented with a pre-approved program that was carried out as directed. The new team was not familiar enough with the idiosyncrasies of the Clearfork formation within this unit. Thus, it was unable to make changes to the proposed drilling or recompletion candidates, other than to experiment with various forms of stimulation to optimize well productivity. It should be noted that this program was an experiment to improve conformance by drilling the proposed injectors on five-acre spacing north-to-south, and 20-acre spacing east-to-west, to make the east - west permeability trend work to improve recovery.
One of the shortcomings of this area's Clearfork floods is that the injection-to-withdrawal rate averages 3.5 to 1. Since the Southwest Westbrook Unit's well count in 2005 was 109 producers and 66 injectors, this is an uphill battle for operators trying to improve sweep efficiency.
During the Meridian and pre-2003 Gruy tenures, stimulation of the Middle Clearfork zone included small acid breakdowns, followed by cross-linked sand fracture treatments diverted with graded rock salt, and some surged acid treatments. Before Gruy became operator, producers and injectors were sand fracture-treated. However, Gruy was concerned about the ability to control water placement in the injection wells by using hydraulic fracture treatments.
Therefore, the firm looked at other stimulation forms that might keep the water in the productive zones and minimize the chances of stimulating into the aquifer or into so-called "thief zones" associated with wells in the east - west permeability trend. These thin (2-to-4-ft), high-permeability zones in injection wells could potentially take all of the injection water and immediately water out the producer to the east or west of the injector in an incomplete injection row.
With this in mind, and the lackluster success of the surge acid jobs previously attempted, the team tried simple acid stimulations, chemically retarded acid stimulations, foamed CO2 cross-linked acid fracture stimulations, and foamed CO2/ acid fracture stimulations. Because nine of the 11 wells to be drilled in 2003 were slated to be injectors, the decision was made to produce them prior to putting them on injection.
Results were disappointing, with most wells producing at an initial flush rate of 25 bopd and quickly declining to 5 to 8 bopd. Injection rates were equally disappointing, once the wells were put on injection. Most would only take 75 to 100 bwpd initially, and then decline to 0 to 40 bwpd in the unit's northern end. However, the unit's southern end has better reservoir characteristics, and most injectors in that area are able to take 300 to 400 bwpd.
Burlington's previous work was reviewed, along with that of the offset operators. Two things became apparent. First, mud logs on previously drilled wells showed that there were more Upper Clearfork zones that could be exploited. Second, the team noticed that offset producers had developed both the Middle Clearfork and Upper Clearfork zones on leases offsetting undeveloped acreage, in the unit that had been previously written off as not having economic productive capacity. A drilling and recompletion program was put together and submitted to Gruy's management to exploit these areas.
In the interim, the team learned about BJ Service's LiteProp fracturing technique. LiteProp is a proppant used in hydraulic fracturing that has a specific gravity of 1.25 and a closure range tolerance up to 5,000 psi. When it is pumped in a near-saturated brine water with a specific gravity of 1.20, the result is a near-buoyant proppant. This buoyancy allows the proppant to be placed farther out in the induced hydraulic fracture without viscosity-enhanced fluids for proppant transport.
These non-gelled or slick brine water fluids are essentially non-damaging compared to polymer-laden fluids that have been pumped historically at Westbrook. The lack of viscosity also works favorably in controlling fracture height growth development, therefore increasing the potential to stay in zone (and out of water at Westbrook), thus creating a longer effective fracture length. It was also believed that a proppant partial monolayer could be created in this low-closure reservoir to further enhance conductivity in the induced hydraulic fractures. The effects and theory of proppant partial monolayers are well documented and were first introduced to the industry in 1959.
All factors considered, the team believed the Clearfork formation to be an excellent candidate. This, combined with having no other ideas for new or innovative stimulation treatments, led to implementation of slick water hydraulic fracture treatments using lightweight proppants.
Treatments yielded 80 to 100 bopd during flush production, and declines decreased significantly after six months so that, after a year-and-a-half on production, the rate was still 20 bopd, Fig. 1. It should be noted that most of the wells that were drilled or recompleted in 2004 are in areas not supported by injection. Unit production (Fig. 2) shows output at about 480 bopd prior to initiation of the 2004 program, and peaking at ±1,200 bopd before falling off, due to lack of activity during the marketing process and a lack of injection support. The unit was marketed, but the offers were not significant enough to merit consideration. In 2005, no drilling was scheduled, although 20 recompletions were performed, with results similar to those of 2004.
The team once again evaluated the properties, based on the 2004 and 2005 programs, and developed a go-forward agenda to enhance both primary and secondary recovery of the Upper Clearfork and Middle Clearfork zones. The base case used for evaluation was the drilling of 50 wells in 2006 and 43 in 2007. The base case also included performing 43 recompletions in 2006 and 39 in 2007. At current commodity prices, the economics far exceed Cimarex's requirements. Even at $30/bbl held flat, the project still surpasses Cimarex's economic hurdles substantially.
Prior to kicking off aggressive exploitation, Cimarex once again tested the market. Even though a strong bid was made to purchase the property, the firm believed in the project so strongly that it declined the offer and initiated the 2006 program. Results to date have been far above expectations. Work has included six wells that have produced from 110 to 185 bopd initially, while three wells have held output above the 100-bopd level for 45 days. Planned exploitation for 2006 and 2007, which includes more treatments, should yield 6.6 million additional bbl of oil.
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