Stephen C. Hurley James R. MurphyMurphy Exploration & Production Co. New Orleans
Susan S. MastorisLandmark Graphics Corp. Houston
New exploration technologies can transform the way an independent oil company explores for hydrocarbons and develops reserves. For one independent, Murphy Exploration & Production Co. (Murphy Expro), a unit of Murphy Oil Corp., the metamorphosis began in 1988 when it launched its first comprehensive project using 3D seismic data and computer aided exploration (CAEX) workstations.
In a declining 38 year old field in the Gulf of Mexico, 3D tools and methods have enabled Murphy to increase oil and gas reserves during the past four years by 21% and 30%, respectively.
Many of the new reservoirs were discovered in highly faulted complexes of relatively small, subtle traps. Further, the discoveries were accomplished with a drilling success rate of about 90% in an area where exploratory dry holes had been the rule rather than the exception. Murphy Expro has been able to maintain field production rates by adding new production at remarkably low finding costs for this region.
As a result of the project's success, Murphy has committed itself to advanced oil finding technology. Between 1988 and yearend 1992 the company acquired more than 12,000 line miles of 3D seismic in five Gulf of Mexico fields including Ship Shoal 113.
This article describes how the change to 3D philosophy and practice took place at Ship Shoal 113 and its impact on Murphy Expro.
SHIP SHOAL 113 AREA
Murphy Expro began exploring for and producing hydrocarbons offshore in the 1950s. For the ensuing three decades the company located reserves the way most companies did, applying traditional techniques based on 2D seismic and well control and testing ideas with the drill bit.
Before Murphy's involvement, the Ship Shoal field had been discovered in 1955 in some 50 ft of water 90 miles off Louisiana. Prolific in oil and gas, the area was soon organized into a federal lease block unit. During the next several years, various partners drilled about a dozen wells into and around the central salt dome of what is now Ship Shoal 113 Unit field.
Murphy Expro acquired Ship Shoal 113 Unit on a 1961 farm-in and became principal operator of the 33,125 acre field unit, accumulating a 50% to 70% interest on the various leaseholds there. Current partners include Phillips Petroleum Co. and Energy Development Corp.
Production in Ship Shoal 113 comes from 70 Lower Pleistocene through Upper Miocene sands ranging from 2,500 ft to 14,000 ft deep (Fig. 1). The field area is comprised of five primary structural features. A late-moving piercement salt dome dominates the central area, trapping multiple pays mainly on the northern and southern flanks. Northeast of the piercement, two growth faults trap stacked pays in Pliocene/Miocene sediments. An east-west trending shale ridge captures Pliocene pay. And to the southwest a series of low-relief, shallow anticlines trap bright spot related gas.
RESERVES, PRODUCTION
From the early 1960s, Ship Shoal 113 and neighboring South Pelto 20 Unit field have been bread and butter properties for Murphy and its partners. In the 26 years from 1963 through 1988-before the first 3D based well contributed any significant production-Ship Shoal 113 Unit alone produced 80 million bbl of oil and 305 bcf of gas.
Production increased steadily throughout the 1960s to a 1971-72 peak, then generally declined through 1985 despite a continuous drilling and workover program.
Murphy Expro believed that even after decades of drilling, substantial new reserves were waiting to be found. Away from the central salt dome, the Ship Shoal area contains numerous relatively small, irregular traps. These include radial faults related to the piercement salt and antithetic and spur faults associated with major fault systems trending east and northeast from the dome. The traps were thought to contain significant oil and gas. Production could be revitalized by developing such reserves.
The Murphy Expro team normally maintained a backlog of on- and off-structure prospects to drill. The team's 30 year record in Ship Shoal 113 had been good, with 68% drilling success: 157 completions and 73 dry holes. However, many of the field's dry holes had resulted from exploratory drilling among the smaller, off-structure fault traps.
The existing 2D seismic - which had poor quality due to out of plane migration caused by steeply dipping reflectors-added to exploration risk. Geologic ideas necessary to develop high-confidence drilling locations had become increasingly difficult to generate. As fewer wells were drilled, production rates drifted lower. Reserve additions began to decrease while per barrel finding and development costs began to rise.
INITIAL USE OF 3D
Murphy Expro and its partners in 1987 committed to the acquisition of a 3D survey over Ship Shoal 113 Unit field. At the time, 3D was generally considered to be a pioneering technology, but the benefits were seen to outweigh the perceived risk.
Some 2,600 line miles were acquired over the southern portion of the field unit. The survey covered about 80 sq miles on a tight 55 ft grid for $1.6 million-a bargain price resulting from the industry's economic turmoil.
Bay cables were deployed because of shallow water depths-20 ft to 70 ft-and the presence of more than 600 surface obstructions including platforms and well jackets. Processing had to account for a full range of shot and receiver azimuths recorded.
Murphy Expro realized that CAEX - interactive workstation technology - was required to interpret the 3D seismic data. The company got up and running on its first CAEX workstation in spring 1988, about the time the processed data were delivered.
"Using 3D on the workstation, we first did postmortems on our dry holes to see what went wrong," a geophysicists said. "When we compared images from 3D with our previous data, we could see structures appear and faults change position. "
Suddenly, with CAEX hindsight, it was obvious significant geologic potential remained untapped.
The new data and 3D workstation enabled the Murphy Expro team to map prospect ideas in great detail. For the first time, all 250 wells in the field could be analyzed and tied together in a regional context.
The team discovered seismic anomalies and structural features that were not apparent in the 2D data. New 3D based drilling locations were proposed, resulting in a number of discovery wells.
RESOLVING A KEY TARGET
As an example, one 3D based location was drilled into a subtle, faulted structure that had been poorly delineated on 2D data (Figs. 2A & B). This location was considered especially risky because it was flanked by four 1960s vintage dry holes. A new dry hole there would cost Murphy and its partners more than $1.5 million.
The primary trapping mechanism associated with the feature mentioned above was a major growth fault that trended west from the piercement dome and slid along the shale ridge. The 3D survey's find sampling rate and high quality data readily enabled the team to image the growth fault and trapped pays in a three way closure north of the fault.
The team used several workstation techniques - including color manipulation, amplitude extraction, and arbitrary lines - to improve the view of the target zone, delineate the pay sands' areal extent, and design a highly effective deviated path for the discovery well.
The 3D imaging revealed strong amplitudes - in this play associated with the Pliocene pay sands - cutting off abruptly at the fault (Fig. 3). By selecting highly contrasting colors, the prospective pays were clearly seen.
The team employed amplitude extraction to further isolate the strong amplitude changes and delineate each prospective reservoir's areal extent. Amplitude extraction maps (Fig. 4) were used to evaluate the economics of each reservoir and, by overlaying such maps, to design a deviated well path that penetrated each reservoir at an optimum point.
Arbitrary cross-sections - generated at various angles and orientations around the fault-tied the seismic response at the existing dry holes to the proposed well location, providing the team with a better understanding of the prospect.
Spudded less than 1,000 ft from the nearest dry hole, the No. 47 discovery well was drilled directionally to 12,000 ft and encountered 168 ft of pay (Fig. 5). Log evaluation and sidewall core analyses proved 123 ft of gas and 45 ft of oil. Abnormal pressure was encountered at total depth, coincident with the shale sheath.
A synthetic seismogram was subsequently constructed from sonic and formation density caliper logs. It directly tied the zero-offset vertical seismic profile and the 3D seismic data set. This allowed the team to further quantify reservoir extent and program a series of deviated wells to efficiently exploit the various reservoirs.
Four additional wells have been successfully completed to develop the oil and gas reserves found in the discovery well. It is estimated that ultimate recovery from this trap will approach 2 million bbl of oil and 60 bcf of gas.
Elsewhere in this geologically complex area, Murphy has applied a methodology similar to that described above, discovering and successfully developing reserves trapped by other faults.
LOWERING THE COST
Such successes convinced Murphy and its partners to extend 3D coverage across the area. In 1989, some 4,500 line miles were shot over the eastern portion of Ship Shoal 113 and contiguous parts of neighboring properties, particularly South Pelto 20 field, where Murphy and its partners also hold interests.
To date, prospects generated from the initial two 3D surveys in Ship Shoal 113 and the contiguous properties have resulted in 31 successful completions and three dry holes, a success rate exceeding 90%, up from the previous 68%. Most of the 3D based wells have been discoveries in complex and subtle traps, often adjacent to the many dry holes drilled in Ship Shoal 113 during three decades.
Twenty three of the successful 3D based completions are located within Ship Shoal 113 Unit itself. Daily oil production from the unit before Hurricane Andrew was 9,916 b/d. One third of the oil production is contributed by 42 active wells of various vintages drilled before the 3D program. Two-thirds of current Ship Shoal 113 oil production comes from the 23 wells based on 3D technology. These 23 wells also account for about 90% of the unit's current 32 MMcfd of gas production (Figs 6A & B). Oil and gas production is expected to increase as repair of hurricane damage is completed and additional 3D based wells are drilled.
To date, finding and development costs of 3D based reserve additions have been $4/st-tk bbl equivalent (BOE). This compares with much higher costs per BOE for new reserve additions in Ship Shoal 113 immediately before 3D was introduced.
CONCLUSION
When a highly experienced geoscience team like Murphy Expro's is given 3D seismic and CAEX workstations to accomplish its mission, oilfield economics can be substantially improved.
Murphy Expro saw drilling success ratios increase, dramatically reducing dry hole costs. Drilling confidence soared, enabling the company to accelerate exploration. Reserve additions are now booked more quickly and at lower cost. Production has been accelerated - also at lower cost - significantly improving the project's cash flow.
Murphy Expro is aggressively extending its commitment to 3D technology by placing the 3D data acquisition program in high gear. An additional 1,750 line miles are being acquired over the extremely promising western portion of Ship Shoal 113 field. When this survey is completed, the unit will have been completely blanketed with 3D seismic.
Two other proprietary 3D surveys are being shot for Murphy in the Gulf of Mexico: about 1,500 tine miles over two blocks of a South Timbalier field and some 3,000 line miles over five blocks in the Mobile Bay area.
Clearly, 3D seismic data and CAEX workstations have become important aspects of Murphy Expro's competitive exploration and production strategy for the foreseeable future.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.