Gilbert E. Klefstad
Transco Exploration Co.
Houston
A potential giant gas field was discovered in 1989 in the very mature exploration province of South Louisiana by Transco Exploration Partners (TXP) and Exxon Co., U.S.A.
The West Chalkley prospect is located in Cameron Parish, La., and is productive in Upper Oligocene Miogypsinoides sands. The discovery is in the same producing trend as prolific South Lake Arthur field, where Miogyp sands have reserves of about 1 tcf.
The prospect was generated by a combination of trend analysis, subsurface well control, and reflection seismic data. The feature appears to be a faulted anticline separate from the nearest production in the area, Chalkley field, which is about 1 mile to the east and was discovered in 1938.
TXP and Exxon, working independently, recognized the potential prospect and acquired leases.
TXP started discussions with the landowner in February 1988 and acquired a 960 acre lease in June. Exxon leased approximately 2,100 acres surrounding the TXP lease about 1 month later.
TXP subsequently sold the prospect to Exxon on Oct. 12, 1988.
DISCOVERY WELL
A potential giant gas discovery in South Louisiana is probably the largest gas discovery in the onshore U.S. in the last 10 years.
The Exxon 1 Sweet Lake Land & Oil Co. reached total depth of 15,600 ft July 4, 1989. Log analysis indicated nearly 500 net ft of gas pay in the 805 ft gross productive interval.
Testing through perforations near the base of the pay zone yielded flow rates as high as 21.028 MMcfd and 330 b/d of condensate.
The well was put on production in March 1990 and has produced at rates as high as 45.4 MMcfd and 740 b/d of condensate.
The West Chalkley prospect is about 18 miles from the Gulf of Mexico (Fig. 1).
Nearest production to the prospect is Chalkley field, about 1 mile to the east. Discovered in 1938, Chalkley field produces from reservoirs as shallow as 8,500 ft and as deep as 13,000 ft.
Cumulative production for Chalkley field was 17 million bbl of crude and condensate and 360 bcf of gas through 1988. The area has been actively drilled for decades with 245 wells drilled within a 2 mile radius, five of them deeper than 14,600 ft.
CHALKLEY POTENTIAL SEEN
West Chalkley prospect lies within the Tertiary (Lower Miocene-Upper Oligocene) producing trend of South Louisiana.
It is located downthrown to the regional Oligocene expansion fault system that forms the Camerina embayment. Miogyp is shown on part of a biostratigraphic chart pertinent to South Louisiana (Fig. 2).
TXP set out to explore for prospects along the expanded Miogyp sand trend in fall 1987.
TXP recognized exploratory potential at Riceville in Camerina and Miogyp sands, acquired some leases, and sold the prospect to another operator.
TXP elected not to pursue the areas around Southeast Gueydan, South Lake Arthur, South Thornwell, and Lacassine Refuge fields for various reasons.
Early analysis of the Chalkley field area of the trend, however, was very encouraging.
Well logs with the Miogyp marker and sands present on the west side of the field were available, acreage appeared unleased, and modern seismic data were available at reasonable prices. These factors convinced TXP to review the seismic data base and integrate existing well control.
The Miogyp marker is a limey zone present in all wells in the area and easily correlated.
The Miogyp sand is a few hundred feet below the marker (Fig. 3).
One of the key wells is the 2 Lynal, located on the northwest flank of the prospect. This well was interpreted as seeing the marker but stopping short of the sand section.
The other well critical to the prospect was the 1 Mecom, which was interpreted as seeing the marker and also seeing some Miogyp sand before faulting into Cibicides hazzardi at total depth. The Mecom well also had a show of gas in Miogyp sand.
REGIONAL SEISMIC CONTROL
TXP had a 2 by 2 mile regional seismic grid in the Chalkley area (Fig. 4).
Two regional seismic lines helped in recognizing the potential of the West Chalkley prospect. Both of these lines were recorded 30 fold in 1984 with an asymmetrical split spread and dynamite or a combination of dynamite and air gun as a source.
The lines were reprocessed in fall 1987, and it was these reprocessed data that were used in the initial interpretation. East-west Line 9 tied the Union Oil Co. of California wells to the west and the 1 Mecom well to the east (Fig. 5).
By projecting the Lynal 2 well onto north-south Line 16 (Fig. 6) and mapping a reflection believed to represent the Miogyp marker, it was apparent that one could get high to both the Mecom and Lynal wells. TXP started a data search and bought two brokered lines.
North-south Line 3 had been shot and processed in 1982. TXP reprocessed the data but could not improve on the original. The data were of little value as a result of a great many skips north of the prospect.
The second brokered line, Line 2, was shot and processed in 1980. TXP obtained significant improvement reprocessing this line. Line 2 confirmed the presence of northeast dip away from the top of the prospect.
Using these data, TXP made a structure map of the area mapping a seismic reflection believed to be the Miogyp marker.
ECONOMICS
The prospect was estimated to have a maximum of 1,100 acres under closure.
The maximum hydrocarbon column was estimated at 335 ft. The most likely reserves estimate was conservatively placed at 105 bcf of gas and 2.84 million bbl of condensate.
These reserve numbers were based on 700 productive acres, 100 average net ft of pay, and a recovery factor of 1,500 Mcf/acre-ft and 27 bbl of condensate/MMcf.
With an estimated $2.1 million cost for a 16,500 ft dry hole and a composite probability of success of 20%, the prospect generated very attractive economic parameters.
Transco attempted to negotiate a 6 month, 1,440 acre seismic option but eventually agreed to a 960 acre lease. Exxon also recognized the potential prospect and about 1 month later acquired leases covering approximately 2,100 acres surrounding the TXP lease.
TXP had been deferring discretionary drilling expenditures for some time in response to low product prices and had assembled a large inventory of prospects. Exxon expressed an interest in Transco's West Chalkley prospect, and a farmout was signed Oct. 12, 1988.
DRILLING 1 SWEET LAKE
The Exxon 1 Sweet Lake Land & Oil Co. was spudded Mar. 16, 1989.
Proposed to 15,500 ft, drilling operations went smoothly with surface casing set at 2,994 ft and 9-5/8 in. and 7-5/8 in. set at 9,190 ft and 13,904, respectively.
At 13,904 ft the well had encountered six "poor to fair" mud log shows, none of which had logged out as pay. However, the log clearly showed the Miogyp marker at 13,700 ft, and Miogyp paleo top came in at 13,470 ft.
It was exciting to be running about 500 ft high to the seismic mapping. This led to suspicion of a velocity anomaly that was later confirmed by velocity survey conducted in the discovery well.
The first log with pay was run May 23, 1989, to 14,660 ft. The well was then deepened to 14,901 ft and 15,110 ft and logged each time before the decision to run 5-1/2 in. casing was made.
The 5-1/2 in. liner stuck short of TD 15,110 ft and was cemented at 14,807 ft. A 4.4 in. hole was drilled on to 15,600 ft, still in the Miogyp section.
The final logs, an induction/short normal and induction-density-gamma ray, were run July 3-4, 1989, and 2-7/8 in. liner was run to 15,595 ft .
FORMATION EVALUATION
Three conventional cores were taken during drilling.
The amount of conventional core was limited because the core barrel jammed on all three attempts. A core at 14,107-125 ft recovered 14.5 ft with sandstone porosities of 12.2-23.4% and permeabilities of 0.35-175 md.
A core at 14,1 52-160 ft recovered 6 ft of silty sandstone with porosity and permeability of 10.9-24.9% and 0.64-53 md, respectively.
The third conventional core, at 14,901-932 ft, recovered 30 ft of 31 ft with porosities of 12.0-14.7% and permeabilities of 0.14-0.77 md.
In addition to the 2-1/2 inch conventional cores, 154 sidewall cores were recovered from the productive interval and analyzed.
The logs run at 13,904-15,110 ft include dual induction laterolog, sidewall frac log, sonic log, gamma ray, compensated neutron log, litho-density log, electromagnetic propagation log, and microlog. A high resolution dipmeter was also run over this interval exhibiting dips of about 10 to the northwest in the upper portions of the productive interval.
A Repeat Formation Test tool was extensively used over the productive interval. A total of 52 pressure tests and 11 jug samples were taken. The pressure gradient throughout the interval was measured at 0.15 psi/ft.
The total pay count reached 485 net ft of gas pay between 14,063-868 ft. The pay sands have an average porosity of 20% and average water saturation of 31.4%. The composite 1 in. dual induction log over the depth interval 14,000-15,000 ft is shown (Fig. 7).
WELL TESTING
The well was initially perforated at 14,836-848 ft, 14,854-860 ft, and 14,863-866 ft. Later perforations were added from 14,670-674 ft, 14,681-702 ft, and 14,722-742 ft.
The well was then tested at rates of 6.7 MMcfd and 139 b/d of condensate with 9,522 psi flowing tubing pressure on an 11/64 in. choke. Shut in bottom hole pressure was 12,060 psi.
Later tests yielded flow rates of 12.028 MMcfd and 330 b/d of condensate. Flowing tubing pressure on a 21.5/64 in. choke was 8,744 psi with a 1% bottom hole pressure drawdown.
Pressure buildup analysis conducted following the flow tests indicated that the well bore was not damaged. The permeability and static bottom hole pressure calculated to be 6.81 md and 11,968 psi, respectively. The estimated radius of investigation is 570 ft with no reservoir boundaries apparent from the buildup analysis.
The gas and fluid analysis found 0.5 mole % hydrogen sulfide and 2.66 mole % carbon dioxide. Gas-oil ratio is 34,400 scf/bbl.
Thermal content is 1,075 Btu/cu ft. Bottom hole pressure is 12,015 psi, and reservoir temperature is 300 F.
EXPLOITATION
During and after the drilling of the well, several speculative seismic lines were shot in the area. These lines were purchased following the completion of the well. The suspected velocity anomaly was confirmed with a vertical seismic profile conducted in the discovery well.
The average velocity to the Miogyp sand at the wildcat is approximately 7,800 ft/sec compared to more than 8,1 00 ft/sec in the dry hole 3 miles to the west.
A structure map was made on the top of the Miogyp pay sand after integrating the initial well and all of the seismic available at that time (Fig. 8).
TXP and the operator jointly acquired approximately 60 miles of additional seismic data to further define the structure and assist in determining delineation drilling locations. The seismic acquired was 240 channel, 60 fold, 165 ft group interval.
Because of the H2S and CO2 content of the gas and to facilitate higher flow rates, the decision was made to replace the initial test string with CRA P-110 chrome alloy tubing. Following that operation, the well has been on production at rates as high as 45.4 MMcfd of gas and 740 b/d of condensate from perforations in the bottom 115 net ft of pay.
CONCLUSION
This very significant reservoir lay hidden for 50 years following the discovery of Chalkley field. Many explorationists may have assumed that the Mecom well was on the flank of the Chalkley structure at the Miogyp level.
The acquisition of east-west seismic Line 9, however, disputed that and suggested the presence of an older buried structure situated west of the old field. This older structure does not manifest itself in datums much younger than the Miogyp.
In the Gulf Coast of the U.S. many operators are abandoning exploration efforts in the onshore areas because they are "so mature," preferring instead to focus on the offshore Gulf of Mexico shelf. The offshore shelf certainly remains an attractive exploration area.
However, the author contends that because of the availability of high quality, low cost seismic data and the areawide leasing schedules conducted in the OCS Gulf of Mexico that the offshore area may not have experienced as much drilling but has certainly been more intensely scrutinized and evaluated than many onshore areas.
It is also important to note that the prospect was found without the benefit of a 3-D seismic data set, a sophisticated geophysical workstation, or the "alphabet soup technology" of AVOs or HCls. It was found instead by using basic exploration procedures.
By integrating the subsurface well control, a loose regional grid of modern seismic data augmented with reprocessed older data, and fresh geologic thinking, these older onshore areas can yield impressive results.
ACKNOWLEDGMENTS
The author acknowledges the help and support of Transco Exploration Co. and many of its past and present employees. Special recognition is due the two outstanding explorationists responsible for generating the prospect, Conrad J. McGarry and J.J. Shelton. The contributions of Keith Vincent and R.L. Brusenhan in lease acquisition and farmout negotiation are also acknowledged, Thanks go to Susan Downs, Judye Murray, W.B. Miller, and Rayer Chain for their assistance in preparing the manuscript. Thanks also to Geophysical Pursuit Inc. for granting permission to use its seismic data.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
