Eugene Island Block 330 Field--U.S.A. Offshore Louisiana

David S. Holland, John B. Leedy, David R. Lammlein

Search and Discovery Article #20003 (1999)

(Published in AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas Feilds, Structural Traps III, p. 103-143; adapted for online presentation)

SUMMARY OF FIELD PARAMETERS

BASIN: Gulf of Mexico

BASIN TYPE: Passive Margin

RESERVOIR ROCK TYPE: Sandstone

RESERVOIR ENVIRONMENT OF DEPOSITION: Deltaic (Delta Front Sands)

RESERVOIR AGE: Pleistocene

PETROLEUM TYPE: Oil and Gas

TRAP TYPE: Rollover Anticline

Editor’s. Note: Tables 4-11 present these and other parameters, which in the original article composed an Appendix (not included here). Features given in these tables are categorized according to: Field Summary, Table 4; Discovery, Table 5; Structure and Trap, Table 6; Stratigraphy, Table 7; Reservoir and Seal, Table 8; Source (Rock), Table 9; Production, Table 10; and Drilling and Completion, Table 11. Structure-contour maps, on the main resevoirs, are shown individually and as a Time-lapse (or animated) sequence.

INTRODUCTION AND LOCATION

The Eugene Island Block 330 field is located in the Gulf of Mexico offshore Louisiana, U.S.A., approximately 272 km (170 mi) southwest of New Orleans (Figure 1). The field covers portions of seven 2024-ha (5000-ac) blocks (Figure 2) in the west-central part of the Eugene Island area, South Addition. The Eugene Island Block 330 field lies within the northern Gulf Coast basin, near the southern edge of the Louisiana Outer Continental Shelf (OCS). Water depths in this area of the shelf range from 64 to 81 m (210 to 266 ft).

The field consists of two rollover anticlines, bounded to the north and east by a large arcuate, down-to-the-basin growth fault system. More than 25 Pleistocene sandstones are productive at depths of 701 to 3658 m (2300 to 12,000 ft). Faulting and permeability barriers separate these sands into more than 100 oil and gas reservoirs.

The Eugene Island Block 330 field was the largest producing field in Federal OCS waters from 1975 to 1980 (Figure 3). The field now ranks second in annual hydrocarbon production (Figure 3) and fourth in cumulative hydrocarbon production (Figure 4). Ultimate recoverable reserves are estimated at 307 million bbl of hydrocarbon liquids and 1.65 tcf of gas. The field is ranked number 437 among the giant oil and gas fields of the world (Carmalt and St. John, 1986).

HISTORY

Our 20-year evaluation of the Eugene Island Block 330 field may be divided into three phases: pre-discovery, discovery, and post-discovery (including development, production, and continued exploration and development). Pennzoil's Block 330 history of operations (Figure 5) characterizes activities in the entire field.

Pre-Discovery

Evaluation of this part of the Louisiana OCS began in 1968 as part of the industry's preparation for the 1970 OCS lease sale offshore southwest Louisiana (Figure 5). In the 1970 sale 240,361 ha (593,458 ac) were offered for lease.

The technical evaluation for the lease sale delineated several rollover anticlines downthrown to a major, arcuate growth fault system in the Eugene Island Block 330 area. Favorable sand conditions for the area were extrapolated from lithofacies and isopachous trends defined by well data (Norwood and Holland, 1974). Prior to the lease sale, Pennzoil regarded the Block 330 area as a gas prospect, because the Pliocene-Pleistocene objective section was considered geochemically immature. Before 1970, wells drilled to the north of Block 330 in Eugene Island Blocks 266, 273, and 292 had established gas production in Pleistocene sands at depths between 915 and 1525 m (3000 and 5000 ft).

Four blocks--Eugene Island 314, 330, 331, and 338--were leased by various companies in the 1970 lease sale (Figure 2). Of the remaining blocks encompassing the field, Blocks 313 and 332 were leased in 1974, and Block 337 in 1976. Bonus bids for the seven blocks totaled $174 million, or an average of $5,355 per acre.

Discovery

Only 2 months after acquiring the leases (Figure 5), exploratory drilling was under way with the simultaneous drilling of the Pennzoil Block 330 #1 well (completed 6 March 1971) and the Shell Block 331 #1 well (completed 24 March 1971). The Pennzoil well, drilled on the crest of the structure (Figure 6), reached a total depth of 1920 m (6300 ft) and penetrated four hydrocarbon-bearing sandstones totaling 34 m (110 ft) of net oil and gas sand. The Shell well, located 100 m (330 ft) west of the Block 330/331 lease line (Figure 6), was drilled to a total depth of 3383 m (11,098 ft), and logged five hydrocarbon-bearing sandstones totaling 60 m (198 ft) of net oil and gas sand. The two wells established a cumulative hydrocarbon column of about 458 m (950 ft), identified six major Pleistocene productive zones (four oil and two gas/condensate), and discovered a major oil and gas field.

Subsequent exploratory drilling encountered additional pay zones, and confirmed and delineated the original reservoirs. To date, 31 exploratory wells have been drilled in the Block 330 field (Figure 7).

Fig. 1. Eugene Island Block 330 field location map, offshore Louisiana.

Fig. 2. Acquisition history and current lease ownership of blocks comprising Eugene Island Block 330 field. Initial lease bonus and year acquired are shown. All blocks are currently held by production. Only the south half (S 1/2) of Block 314 is included in the field.

Fig. 3. Annual hydrocarbon production rank, Eugene Island Block 330, U.S. Federal OCS waters. U.S. Minerals Management Service (MMS) data.

Fig. 4. Top four cumulative oil- and gas-producing fields, U.S. Federal OCS. Cumulative production to 30 June 1987.

Fig. 5. Eugene Island Block 330 exploration, development, and production history.

Post-Discovery

The first development well was spudded on Block 330 from Pennzoil's "A" platform in November 1971 (Figure 5). Ten production platforms have been set and 227 development wells drilled in the Eugene Island Block 330 field (Figure 7). The 258 exploratory and development wells together have identified more than 25 pay sands.

During the period 1982-1986, additional hydrocarbons were discovered and developed on the upthrown side of the large growth fault system in Eugene Island Blocks 330, 315, and 316, and also south of the field in Eugene Island Blocks 336, 337, and 354. These adjacent fields will not be addressed in this discussion.

Production in the Eugene Island Block 330 field began in September 1972, which is 1 year and 9 months after initial lease acquisition (Figure 5). Maximum fieldwide daily production of 95,290 bbl of liquids and 482,000 mmcf of gas was attained in 1977 (Figure 8). Cumulative production through September 1987 is more than 271 million bbl of oil and condensate and 1.259 tcf of gas (Figure 8). Daily production was 23,600 bbl of liquids and 111 mmcf of gas, as of September 1987.

Pennzoil's Eugene Island Block 330 has been producing since March 1973. Lewis et al. (1982) provide a petroleum engineering review of the development and production history of the field. Cumulative production through September 1987 is more than 101 million bbl of oil and condensate and 477 bcf of gas. This represents 37% of the liquid hydrocarbons and 38% of the gas produced from the entire field. The oil production decline rate (Block 330 only) has averaged 11% per year.

Fig. 6. Initial 1970 seismic structure map of the JD sandstone, Eugene Island Block 330 field vicinity. Locations of Pennzoil #1 and Shell #1 wells shown.

Fig. 7. Exploratory and development summary for the Eugene Island Block 330 field.

Fig. 8. Cumulative and daily average hydrocarbon production for Eugene Island Block 330 field. The drop in daily average production in 1983 was the result of a pipeline rupture.

DISCOVERY METHOD (Table 5)

Pennzoil-United, a forerunner of the present-day Pennzoil Company, and its partners, in an effort to lease acreage in the newly emerging Pliocene-Pleistocene trend offshore Louisiana, began evaluation in 1968 for the December 1970 Federal OCS lease sale. Pennzoil's evaluation strategy was to give top ranking to prospects that (1) have the potential for large reserves, (2) are located on the crests of structural highs (especially four-way dip closures), and (3) are located within subbasins with alternating sand-shale sequences.

Electrical well logs and paleontological reports formed the data base for a regional stratigraphic study of the western part of the Louisiana continental shelf. Six types of stratigraphic maps were prepared for as many as 17 regional stratigraphic markers in the Pleistocene, Pliocene, and upper-middle Miocene. The maps included:

1. Paleobathymetric maps: showing water depth at the time of deposition. Several authors, among which are Limes and Stipe (1959), Fisher (1969), and Norwood and Holland (1974), observed and documented the relationship between rock facies, depositional environment, and hydrocarbon accumulations in the Pleistocene, Pliocene, and Miocene rock systems of the Gulf of Mexico. It was generally accepted that deposition in water depths of 91 to 457 m (300 to 500 ft) is optimum for hydrocarbon accumulations in the Gulf of Mexico. This range in paleodepth for the shale is classified as outer neritic (outer shelf, paleoecological zone 3) to upper bathyal (upper slope, paleoecological zone 4). Mapping of paleoenvironmental data defines the shape of the delta platform, proximity to the delta plain, and hence the distribution of the alternating sand-shale facies (Norwood and Holland, 1974).

2. Sand percentage maps: sand percentages between 10 and 35% defining the alternating sand-shale facies, the most favorable facies for hydrocarbon accumulations.

3. Net sand maps: indicating total sand and potential reservoir rock within a stratigraphic interval.

4. Isopachous maps: predicting stratigraphic interval thicknesses with limited control.

5. Trend analysis maps: combining optimum paleobathymetric and sand percentage fairways with known production to highlight areas of possible prime hydrocarbon accumulation.

6. Fence diagrams: visual aids for understanding stratigraphic variability.

long with the stratigraphic study, reconnaissance seismic structural interpretation and mapping of key horizons were initiated using available contractor 6- and 12-fold seismic data. Numerous anomalies within prime depositional trends were identified. Additional 12- and 24-fold seismic data were purchased to provide infill coverage over prospects selected for more detailed mapping and evaluation. Over highly selective areas, including the Eugene Island Block 330 area, proprietary seismic data were shot and processed. By combining the subsurface information with detailed seismic-reflection and velocity data, structural interpretations were completed on three Pleistocene horizons throughout the evaluation area.

Through this regional seismic mapping procedure the Block 330 prospect was identified (Figure 6). An anticlinal structure with excellent trapping conditions was mapped on the downthrown side of a large growth fault system, with the crest on Block 330. Geological data indicated that the Block 330 anticline was located in a prime Pleistocene depositional fairway. Subsequent exploration drilling confirmed the anticline as part of a giant oil and gas field.

Current Exploration Technology

Since the conclusion of the initial exploration and development phases in 1973, the Eugene Island Block 330 field has been the subject of continuing geologic, geophysical, and engineering studies (Figure 5). Today's advancements in geophysical acquisition, processing, and interpretation have increased the importance of seismic data in reevaluating developed fields and defining new prospects. In 1986, 1637 km (1017 mi) of 3D seismic data were acquired to evaluate Block 330. These data are interpreted on an interactive workstation to identify and evaluate prospects for additional exploration and development drilling. The use of 3D data has enhanced mapping resolution by defining individual fault-block reservoirs more precisely.

Hydrocarbon indicators recognized on seismic data over the Block 330 area correlate with many of the oil and gas reservoirs in the field. Figure 9 shows a 3D seismic section over Block 330. High-amplitude reflections and flat spots are associated with the productive zones. For example, the high-amplitude flat spot at about 1.5 sec is a reflection from the oil-water contact within the HB sandstone. Petrophysical and log analyses indicate that most oil and gas reservoirs have reduced acoustic impedance values relative to those of water sands and shales (Figure 10). This explains the observed correlation between seismic-reflection amplitudes and hydrocarbon accumulations in the field.

Extracted amplitude displays (Figure 11) are generated from the 3D data set to aid in the evaluation of seismic hydrocarbon indicators and in the definition of productive limits controlled by oil-water contacts, faults, and permeability barriers.

In addition to traditional stratigraphic techniques using well logs and paleontology, seismic stratigraphy combined with dipmeter analysis is used to define stratigraphic sequences and lithologies. These data indicate that the Eugene Island Block 330 field is within the sand-rich delta-front facies of a Pleistocene delta complex (see Stratigraphy).

Fig. 9. 3D seismic line over crest of Block 330 showing HB amplitude at approximately 1.5 seconds, and JD sandstone amplitude at approximately 1.9 seconds.

Fig. 10. Characteristic petrophysically derived acoustic impedance vs. depth plot for water sands, shales, and hydrocarbon-bearing sands, illustrating the empirical basis for observed bright seismic amplitudes associated with pay zones in the field.

Fig. 11. Extracted amplitude map of JD sandstone generated from 3D seismic data volume with superimposed structural contours.

Surface Manifestations

Recent advances in petroleum geochemistry have helped establish the value of near-surface geochemical surveys (Jones and Drozd, 1983; Faber and Stahl, 1984; Brooks et al., 1986). Results from these studies demonstrate that the composition of gases in near-surface soils and marine sediments commonly shows a striking similarity to the composition of the underlying hydrocarbons.

Sediments from sea-bottom piston cores, collected on Eugene Island Block 330 along surface fault traces, contain minor anomalous concentrations of light hydrocarbons and aromatic sulfur compounds. The latter are particularly significant because these dibenzothiophenes are important constituents of the Eugene Island 330 crude oil. The presence of the hydrocarbon microseepage, and a significant heat-flow anomaly identified from analyses of well and sea-floor data, suggest present-day fluid migration associated with the major growth fault bounding the field on the north and east.

STRUCTURE (Table 6)

Tectonic History

The Block 330 field is located in the Gulf Coast basin (Figures 12 and Figures 13). The siliciclastic portion of the basin extends from the Sigsbee escarpment on the south to the northern pinchout of Tertiary sediments on the coastal plain, and from the Florida escarpment to the East Mexico shelf (Martin, 1978). Grabens and down-to-the-basin faulting are present along the inner coastal plain. These graben and fault systems are related to the formation of the Gulf of Mexico by early rifting and subsequent sea-floor spreading and subsidence in the Jurassic through Early Cretaceous (Hall et al., 1982). According to the compilation of hydrocarbon provinces by St. John et al. (1984), the Gulf Coast basin is classified as 1143 under the modified scheme of Bally and Snelson (1980) (i.e., basins located on the rigid lithosphere, not associated with the formation of megasutures; Atlantic-type passive margins that straddle continental and oceanic crust; overlying earlier backarc basins). Klemme (1971) classifies the Gulf Coast basin as IICc/IV (i.e., continental multicycle basin; crustal collision zone-downwarp into small ocean basin; open/delta basin).

Regional Structure

Structural features on the Louisiana OCS include salt domes, salt-withdrawal subbasins, growth faults, and diapir-related faults. Rollover anticlines are common on the downthrown sides of growth faults (Bruce, 1973). The mobilization of salt into anticlines, domes, and diapirs is of particular tectonic importance in the Gulf Coast basin.

Woodbury et al. (1973) subdivided the salt structures in the Texas and Louisiana coast, shelf, and slope areas according to the shape, size, and horizontal cross-sectional area of the salt at a depth of 3658 m (12,000 ft). Based upon their system, the Eugene Island Block 330 field is near the northern edge of the salt-tectonic province characterized by semicontinuous diapiric uplifts (Figure 14).

Deformation related to salt movement has been occurring since Late Jurassic (Martin, 1978) and continues today (Humphris, 1978). Deformation was contemporaneous with sedimentation, being both a consequence of and an influence on deposition. The rapid influx of Upper Cretaceous and lower Tertiary terrigenous sediments mobilized the salt, prograded the northern Gulf margin to the south, and produced regional, down-to-the-basin growth faults.

Local Structure (Time-lapse, or animated sequence)

The Block 330 field is located within an oval-shaped structural and depositional basin (Figure 6) on the downthrown side of a large, arcuate down-to-the-basin growth fault system (Holland et al., 1980). Antithetic faults and other permeability barriers divide the sandstone into more than 100 oil and gas reservoirs (see Reservoirs section).

Along the northern rim of the subbasin, hydrocarbons accumulated in two anticlines formed by rollover on the downthrown side of the growth fault system (Figure 6). The anticlines have different growth histories and are separated by a small syncline. Maximum structural growth for the eastern anticline occurred within Angulogerina "B" time (1.8 MYBP) (Figure 15), after which the growth rate steadily decreased. The eastern structure is sharply defined and has as much as 549 m (1800 ft) of structural closure. The western anticline has less relief, with 122 to 152 m (400 to 500 ft) of structural closure. Maximum structural growth occurred later than that of its eastern counterpart.

Fig. 12. Structural-physiographic map of the northern Gulf of Mexico area. Location of Figure 13 cross section A-A^prime shown as heavy dashed line. Modified after Martin (1978).

Fig. 13. Diagrammatic cross section (A-A^prime) of northern Gulf of Mexico. Location shown on Figure 12. Modified after Martin (1978).

Fig. 14. Major groups of salt diapirs and salt tectonic provinces in the northern Gulf of Mexico. (Holland et al., 1980, after Woodbury et al., 1973.)

Fig. 15. Eugene Island Block 330 field composite type log. Spontaneous potential curve on the left and resistivity curve on the right. Holland et al., 1980.

STRATIGRAPHY (Table 7)

Sediments in the Gulf Coast basin are entirely Mesozoic and Cenozoic in age, occurring in offlapping sequences that become generally younger to the south (Figure 13). Beginning in the Late Cretaceous and early Tertiary, the northern Gulf received a large influx of terrigenous sediments presumably in response to the Laramide orogeny to the west. Thick accumulations of siliciclastic sediments were deposited in depocenters overlying the Jurassic Louann Salt. These depocenters shifted generally seaward and eastward throughout the Cenozoic (Woodbury et al., 1973). The Pliocene-Pleistocene section in the Gulf Coast consists of transgressive and regressive sequences of fluvial-deltaic facies. Caughey (1975) described the Pleistocene section as a fluvial, delta-plain, delta-front, and prodelta regressive sequence.

The major producing sandstone reservoirs in the Eugene Island 330 field are shown on the type log (Figure 15). These Pleistocene sandstones are interpreted to have been deposited as delta-front sands (Figure 16). Gently sloping shingled seismic reflectors (Figure 17), classified by Mitchum et al. (1977) as oblique-progradational, are interpreted as representing delta-front depositional surfaces. Dipmeter data (Figure 18) show depositional current dips that indicate delta-front foreset bedding (Gilreath and Maricelli, 1964). These delta-front sequences typically have 15-30% sand in beds that show a range in thicknesses and have gradational bases and sharp upper contacts (Martin, 1978). Norwood and Holland (1974) recognized the relatively high percentages of Pleistocene reservoired oil in these alternating sand-shale facies.

Seismic stratigraphic-sequence analysis illustrates the numerous sequence boundaries defined by reflection terminations and distinctive reflector character (Figure 19). Synthetic seismograms are used routinely to tie well data to seismic data. Seismic stratigraphy utilizes this accurate seismic identification of reservoir facies to help extrapolate and predict sand conditions and geometries away from well control.

Seismic stratigraphic-facies analysis also indicates that the source of sediments deposited in the subbasin was from the north, predominantly through Block 331. The developing structure in Block 330 deflected sediment dispersal. During the Angulogerina "B" time (1.8 MYBP) of maximum growth on the Block 330 structure, the OI through JD reflectors are interpreted as onlapping the structural crest (Figure 19). Channels evident at the GA horizon (Figure 20) indicate transport away from the anticline during the younger Trimosina "A" time (0.5 MYBP). Erosional channels are of high exploration interest owing to their part in redistributing reservoir sediments.

Fig. 16. Depositional model for sandstones in Eugene Island Block 330 field. The delta-front facies are shown as alternating sand and shale. Modified after Norwood and Holland (1974).

Fig. 17. 3D seismic line showing shingled reflections of the GA horizon, indicating delta-front sand deposition on Block 330.

Fig. 18. Dipmeter interpretation of the GA sandstone, Block 330 #B-13 well. Current patterns correspond to shingled seismic reflectors. Holland et al., 1980.

Fig. 19. Seismic line across the southern part of Block 330, showing stratigraphic interpretation, sequence boundaries, and onlapping reflectors onto the 330 structure. SP log curve insert shows
Eugene Island 330 #2 well tie.

Fig. 20. Seismic stratigraphic interpretation, showing GA sandstone channeling into underlying HB sandstone.

 TRAP (Table 6)

The trapping mechanism for the field is four-way dip closure on two rollover anticlines located on the downthrown side of the growth fault (i.e., JD sandstone, Figure 6 and Figure 27 A). Faulting was contemporaneous with deposition. The fault has been active since at least the early Pleistocene (2.1 MYBP) and continues to be active today. Maximum thinning is seen during Angulogerina "B" time (1.8 MYBP). Additional porosity pinchout traps, due to facies changes or nondeposition, are found on the flanks of the Block 330 anticline, as seen on the LF sandstone structure map in Figure 29A.

Impervious shales above individual reservoirs act as seals (Figure 15). Shale beds only a few feet thick, if continuous, are known to be effective vertical seals. Lateral seals are formed by major or minor faults, although permeability barriers caused by facies changes also are common (Figure 29A).

RESERVOIRS (Table 8)

Most of the production in the field is from the seven Pleistocene sandstones shown in Figure 15. Six of these are predominantly oil sands; the JD is gas productive; and the OI produces both oil and gas. Many of these sandstones are divided into two or more units. For example, the GA sandstone is divided into five units, of which the GA-1, GA-2, and GA-5 sand units are productive. More than 25 producing sandstone units have been developed in the field.

Reservoir parameters for the major oil and gas sands on Pennzoil's Block 330 are listed in Appendix 1. Porosities average about 30% and water saturation ranges from 20 to 40%. Permeabilities range from 10 md to more than 6 darcys. Approximately 80% of the reservoirs have permeabilities of more than 100 md and about 20% have more than 1 darcy (Holland et al., 1980).

The major producing sandstones are categorized as quartzose to slightly arkosic arenites. Although the grain size ranges from coarse silt to medium sand (Appendix 1), most sandstones are fine grained and well sorted. A wide range in grain roundness has been noted.

Quartz (both monocrystalline and polycrystalline) is the predominant framework mineral, amounting to as much as 89% of the bulk rock volume. Feldspars and chert also are present, and may represent as much as 25% of the total composition. Rock fragments (igneous, metamorphic, and shale balls) account for 13% of the sandstone composition. Heavy minerals (zircon and chlorite), mica, and glauconite are present in small percentages.

The depositional shale and clay content is variable and can comprise as much as 9% of the bulk rock volume. This shale is structural, laminated, or dispersed as pore fillings. Various cements are present, including authigenic clay (0 to 8%), silica (0 to 9%), dolomite (0 to 12%), pyrite (0 to 2%), and feldspar (trace).

Porosity is commonly primary intergranular (Figure 21A and Figure 21B) or reduced primary intergranular. Some secondary moldic porosity also formed by feldspar dissolution (Holland et al., 1980).

Fig. 21. SEM photomicrographs of sidewall core samples. (A) Intergranular pore (P) lined with partially recrystallized illite (I). GA sandstone, E.I. 330 #C-3, 5039 ft (scale = 10 microns). (B) Sand grains (G), intergranular pore (P), and open pore throats (PT) in clean, shale-free sandstone. HB sandstone E.I. 330 #C-17 ST, 5358 ft (scale = 30 microns). (C) Primary, intergranular pore (P) lined with pyrite octahedrons (PY). Feldspar (F) is partially leached, resulting in secondary porosity development. JD sandstone, E.I. 330 #B-2, 7491 ft (scale = 4 microns). (D) Pore walls coated with partially recrystallized, discontinuous, detrital illite and smectite clays (C). Pore throats (PT) open and well-defined. KE sandstone, E.I. 330 #B-2, 7934 ft (scale = 10 microns).

Fig. 22. Thin-section photomicrographs of selected sidewall core samples from Eugene Island Block 330. (Plane polarized light: scale = 0.25 mm.) (A) Quartz-rich, dolomitic siltstone with intergranular porosity. HB sandstone, E.I. 330 #A-13, 6485 ft. (B) Fine-grained, loosely packed sandstone (subarkose) with well-developed intergranular porosity. JD sandstone, E.I. 330 #A-1, 6603 ft. (C) Laminated, very fine grained sandstone and interbedded silty shale. KE sandstone, E.I. 330 #B-2, 7966 ft. (D) Fine-grained sandstone (subarkose). C, chert; F, plagioclase feldspar; P, pelecypod fragment; Q, quartz. LF sandstone, E.I. 330 #B-2 well, 8338 ft.

Fig. 23. Thin-section photomicrographs. (Plane polarized light: scale = 0.25 mm.) (A) Single lamina of very fine grained, poorly sorted quartz sandstone in shale. Q, quartz; PF, plant fragment. MG sandstone, E.I. Block 330 #A-12, 7712 ft. (B) Two laminae of very fine grained, well-sorted quartz arenite interlaminated with sandy shale. OI sandstone, E.I. Block 330 #A-4, 8764 ft. (C) SEM photomicrograph (scale = 30 microns). Intergranular pores (P) devoid of pore lining minerals (bottom portion) or lined with discontinuous overgrows of sodium feldspar (F), illite and smectite clays (C). LF sandstone, E.I. Block 330 #B-6, 7788 ft. (D) SEM photomicrograph (scale = 8 microns). Large intergranular pore (P) with discontinuous illite and smectite clay coats (C). Pores interconnected through open pore throats (T). OI sandstone, E.I. 330 #B-15, 7815 ft.

GA Sandstone

The GA sandstone is productive in the GA-1, GA-2, and GA-5 units. The GA-1 is the shallowest major producing unit in the field and is found at an average depth of 1311 m (4300 ft). The structural configuration at the GA horizon is an unfaulted rollover anticline (Figure 24A). The eastern structure dips 2 to 3° on all flanks except near the growth fault, where the dip increases to 6°. The productive area at the GA-2 horizon is 341 ha (842 ac), is crestal, and is located wholly within Block 330.

The GA sandstone is interpreted to be a delta-mouth bar deposit, with massive sands as much as 122 m (400 ft) thick (Figure 24B). The sand is very fine to fine grained (0.08 to 0.19 mm) and contains various amounts of detrital shale and clay. The rocks consist predominantly of monocrystalline quartz, with minor quantities of feldspar, chert, and rock fragments. Depositional shale occurs primarily as laminae (Figure 21A ). The sands contain relatively little cement (0 to 4%) except the GA-5 unit, which is heavily cemented by dolomite. Silica cement is seen as overgrowths on detrital quartz grains. Pore-lining clay occurs in small quantities and consists largely of smectite, illite, and kaolinite. Porosity is intergranular and volume is reduced by shale fill or authigenic clay cementation.

The GA-2 unit is a major reservoir having a maximum net oil pay of 30 m (100 ft) and an oil column of 38 m (126 ft). The reservoir is bounded on the southwest by a permeability barrier and on the northeast by dip closure (Figure 24A). The reservoir exhibits a strong bottom water drive (Figure 25) and has a pressure gradient of 0.49 psi/ft. Reservoir parameters for the GA-2 sandstone are listed in Appendix 1.

Original oil-in-place for the GA sandstones is estimated at 40 million bbl, 10 million bbl of which was initially considered recoverable. Cumulative production (March 1988) for the GA sandstone on Block 330 is 14.8 million bbl of oil and 8.8 bcf of gas. Eight wells completed in the GA-2 unit have each produced more than 1 million bbl of oil, and the #C-2 well had produced 2.9 million bbl as of March 1988. The oil gravity is 23° API and the initial gas/oil ratio was 400-500 scf/bbl.

The GA-2 reservoir has overproduced original recoverable volumetric estimates by 43%. It is now believed that the GA sandstones will ultimately produce 17.0 million bbl of oil. This could be the result of the contribution to the overall production from silty and shaly laminated sandstones that originally were not considered pay because of the low resistivity log response. This low-resistivity sandstone has porosity in the 18 to 25% range and permeability of less than 10 md. Even though these zones have little capacity for significant lateral flow, they may recharge the more permeable productive zones adjacent to them.These zones could then be classified as "feeder pay" and would increase the estimated recoverable reserves.

Fig. 24A. Top GA sandstone structure map. Discovery well (E.I. 330 #1) indicated. Contour values subsea level.

Fig. 24B. GA net sandstone isopach map.

Fig. 25. Pressure history for three Eugene Island Block 330 reservoirs.

HB Sandstone

The HB sandstone is divided into the HB-1, HB-1B, HB-2, and HB-3 producing units. The reservoir produces predominantly oil and has a small gas cap in the HB-1 unit. As discussed earlier, high-amplitude seismic anomalies with associated flat spots correspond to the GA and HB pay zones (Figure 9). Average depth of the reservoir is 1463 m (4800 ft). Porosity averages 28% within this generally well-sorted, medium-grained sand. Average water saturation is 33%.

Structurally, the HB sandstone is mapped as rollover anticlines, cut only by minor faulting (Figure 26A). The HB sandstone is productive on the crest of the eastern anticline, and the hydrocarbons are entirely within Block 330 (Figure 26A). The oil reservoir covers 416 ha (1029 ac) and has a maximum oil column of 29 m (96 ft). The gas cap covers 140 ha (345 ac) and has a maximum thickness of 8 m (27 ft).

Original oil-in-place reserves for the HB sandstone are 38 million bbl of oil, 16.4 million of which is considered recoverable. Cumulative production from the HB sandstones on Block 330 is 14.1 million bbl of oil and 16.2 bcf of gas (March 1988). The oil gravity is 25° API, and the initial gas/oil ratio was 361 scf/bbl. The reservoir exhibits a strong water drive and has a pressure gradient of 0.49 psi/ft. Critical in the development of the HB reservoir was the placement of wells outside the gas cap but close enough to the gas/oil contact to effectively produce the oil rim.

The HB sandstones are interpreted as prograding delta-front sands, with net sand thickening generally to the north (Figure 26B). Grain size (0.05-0.25 mm) increases and sorting improves from the base to the top of the sand unit. The framework grains (Appendix 1) are primarily quartz (average 68% of bulk rock volume), with minor amounts of feldspar (7 to 11%), chert (6 to 14%), and rock fragments (1 to 10%) (Figure 22A). The shale within this zone is predominantly laminar. The HB-1 sand contains local concentrations (as much as 27%) of shell fragments. Pore-filling dolomite cement occurs in the finest grained reservoir rock. Pores are also partly occluded by quartz overgrowths and authigenic clay cement (Figure 21B).

Fig. 26A. Top HB sandstone structure map. Discovery well (E.I. 330 #1) shown.

Fig. 26B. HB net sandstone isopach map.

JD Sandstone

The JD sandstone has the largest productive area of any reservoir in the Block 330 field, 2611 ha (6450 ac) and parts of seven blocks (Figure 27A). It is also the only reservoir that produces predominantly gas, with more than 1 tcf of gas originally in place. An estimated 736 bcf of gas and 16 million bbl of condensate are recoverable. The average producing depth is 1981 m (6400 ft).

The structural configuration at the JD horizon is interpreted as two anticlines, separated by an intervening syncline (Figure 27A). The eastern structure is divided into several fault blocks. The JD sandstone is characterized by a relatively high-amplitude seismic reflection, as seen at approximately 1.8 to 2.1 sec on Figure 9.

The JD sandstone is interpreted to be a delta-mouth bar/delta-front deposit (Figure 27B). The distributary mouth is near the intersection of Block 313 and the northwestern corner of Block 331, where the sand is thicker, cleaner, and coarser grained. In Block 330, sand conditions are more variable and distal, with silt and shale laminations, finer grain size, and less sorting.

The JD sandstone on Block 330 is predominantly quartzose, with various, but significant, quantities of shell fragments (0 to 56%) (Figure 22B) and limited amounts of detrital feldspar, mica, and rock fragments. Dolomite and lesser amounts of authigenic clay (illite), silica, and pyrite are present as cements (Figure 21C).

Reservoir parameters for the JD sandstone on Block 330 are listed in Appendix 1. The average porosity is 29% and the average water saturation is 35%. Net pay averages about 11 m (36 ft) and the maximum thickness is 28 m (92 ft). Permeability ranges from 20 to 4100 md and averages 720 md.

The only commercial JD oil reservoir is located in the southern fault block on the eastern structure on Block 338 (Figure 27A). The oil rim has a column of 39 m (129 ft). The gas column above the oil rim is 257 m (842 ft). Faulting is less significant on the western structure, which has a gas column of 113 m (370 ft) and no oil rim. A directional water drive is present, watering out wells successively from west to east.

Cumulative production from the JD sandstone on Block 330 is 226 bcf of gas and 4.7 million bbl of condensate (March 1988). The reservoir has a limited water drive, with bottom-hole pressures dropping from an original 3784 psig to a current 1678 psig (July 1987).

Fig. 27A. Top JD sandstone structure map. Discovery well (E.I. 330 #1) indicated.

Fig. 27B. JD net sandstone isopach map.

KE Sandstone

The KE sandstone is productive on the eastern structure (Block 330) and on the crest of the western structure (Blocks 314 and 331) (Figure 28A). The sandstone consists of the KE-1 and KE-2, each approximately 12 m (40 ft) thick. Both units have gas caps and oil rims. A permeability barrier bounds both KE-1 and KE-2 on the southeastern side of the eastern structure. The average producing depth is 2017 m (6600 ft). The sandstone has an average porosity of 29% and a permeability range from 10 to 4500 md (Appendix 1).

The sand is a delta-front/distributary-mouth deposit, which is as much as 91 m (300 ft) thick in the southeast corner of Block 313 (Figure 28B). The KE sandstone is predominantly fine-grained and contains minor amounts of detrital shale matrix (Appendix 1). Framework grains consist mainly of quartz, with lesser amounts of feldspars, chert, and rock fragments (as much as 21%) (Figure 21D and Figure 22C). Silica and dolomite are the most common cements.

The eastern structure is broken by normal down-to-the-south and antithetic faults that subdivide the reservoir into several producing fault blocks. The reservoir has a maximum oil column of 134 m (441 ft) and a gas cap of 227 m (745 ft). The estimated original recoverable reserves for the eastern structure are 16 million bbl of oil, 18 bcf solution gas, 46 bcf nonassociated gas, and 940,000 bbl of condensate. Cumulative production from the KE sandstone on Block 330 is 14.3 million bbl of oil, 26.4 bcf of gas, and 559,000 bbl of condensate (March 1988). The oil reserves are essentially depleted and production of the gas cap is continuing. The gravity of the oil is 35° API. The initial gas/oil ratio was 893 scf/bbl. The reservoir has a predominant water drive.

Fig. 28A. Top KE sandstone structure map. Discovery well (E.I. 330 #1) shown.

Fig. 28B. KE net sandstone isopach map.

LF Sandstone

The LF sandstone is the most prolific oil-producing reservoir in the field. It has the second largest area with 1472 productive ha (3635 ac) in the oil column and 245 productive gas cap ha (606 ac). Cumulative production is more than 63 million bbl of oil, and ultimate recoverable reserves are estimated at 69 million bbl. Original oil-in-place reserves are 180 million bbl. Average producing depth is 2164 m (7100 ft). Reserves are equally divided between the eastern and western structures. The structure in Block 330 has a gas cap containing 15 bcf gas reserves. The structural configuration at the LF sandstone horizon is similar to that of the shallower sands (Figure 29A). The eastern structure is broken into several fault blocks by down-to-the-south and antithetic faults. A permeability barrier is present on the crest. Figure 30 illustrates the dramatic stratigraphic thinning onto the crest of Block 330 within the JD to LF interval. As suggested by mapping, the Block 330 structure was actively growing during this time, and southward sediment flow was deflected to the west off the crest.

The LF sandstone is interpreted as a distributary-mouth bar deposit, grading into a delta-front deposit to the southeast in Block 330. The gross interval isopach map (Figure 29B) shows thick deposition in the area near Blocks 313 and 331. The sand progressively thins and is shaled out on the crest in Block 330.

The LF in Block 330 is a very fine grained, clean sandstone. The small grain size allows for a high interstitial water surface area and a high (40%) irreducible water saturation. This results in an abnormally low resistivity log response (average 1.3 ohms) and masks its true productivity (Figure 31). The gross sand thickness averages 17 m (55 ft), and, because of the absence of shale, most of this thickness is filled with hydrocarbons.

The LF sandstones are generally quartzose with various, but minor, amounts of detrital shale (Figure 22D). Feldspars, chert, and rock fragments may constitute as much as 30% of the total rock volume (Figure 23C). These sands are more uniformly cemented than the other sandstones in the field. The cements include authigenic clay, silica, dolomite, and pyrite.

The LF sandstone is a combination gas-cap expansion and partial-water-driven reservoir. The pressure gradient is 0.57 psi/ft. The original oil column was 212 m (696 ft) with a gas column of 113 m (370 ft). The oil gravity is 34° API, with an initial gas/oil ratio of 941 scf/bbl.

Fig. 29A. Top LF sandstone structure map. Discovery well (E.I. 330 #1) indicated.

Fig. 29B. Gross interval LF sandstone isopach map. Interpreted distributary-mouth bar deposits reach maximum thicknesses near the southeast corner of Block 313, and progressively thin toward Block 330.

Fig. 30. Seismic line from 3D seismic data volume illustrating stratigraphic thinning within the JD to LF interval over the crest of Block 330.

Fig. 31. Abnormally low resistivity log response of LF sandstone seen in wells on Block 330.

MG Sandstone

The MG sandstone consists of four oil- and gas-productive units in the west-central part of Block 330 and in Block 331 (Figure 32). Permeability barriers are present throughout the area. MG sandstones have produced 4.3 million bbl of oil, 37.9 bcf of gas, and 1.3 million bbl of condensate in Block 330 (March 1988). The oil gravity is 36° API, with an initial gas/oil ratio of 1225 scf/bbl (Appendix 2). The MG sandstone has predominantly produced as a depletion-drive reservoir. The pressure gradient is 0.58 psi/ft.

These deltaic MG sandstones are well sorted and consist of various grain sizes. Mean grain size ranges from very fine (Figure 23A) to coarse (0.07 to 0.57 mm). Quartz is the dominant framework mineral, with feldspar, chert, and rock fragments present in smaller amounts (1 to 18%). Plagioclase feldspar is more abundant than potassium feldspar. The sandstones contain very little cement. Most of the clay is smectite, which is present in laminar and structural form.

Fig. 32. Top MG-1 sandstone structure map. Additional MG sandstone units are similar in structure. MG-1 discovery well (E.I. 331 #2) indicated.

OI Sandstone

The OI sandstone is composed of the OI-1, OI-2, OI-3, and OI-4 units. This sandstone is stratigraphically the deepest major oil- and gas-producing reservoir in the field. Productive depths range from 2134 to 2743 m (7000 to 9000 ft). The only known reservoirs deeper than the OI sandstone are the Lenticulina sands, which produce minor amounts of hydrocarbons on Block 331.

The structural configuration at the OI horizon is two complexly faulted anticlines (Figure 33A). The major down-to-the-south growth-fault system divides into several subparallel faults at the OI horizon. These faults are sealing, as evidenced by the unusual pay separation between fault blocks "A" and "B." Fault block "A" has a 159 m (521 ft) oil column with a 36 m (118 ft) gas cap. Fault block "B," immediately to the north and downthrown to fault block "A," is a gas/condensate reservoir. The gas column extends 536 m (1760 ft) from the crest to the gas-oil contact. The oil column in fault block "B" is 34 m (110 ft) and extends 414 m (1357 ft) below the oil-water contact in fault block "A" (Figure 33A).

The OI sandstones are a distributary channel deposit with a maximum net sand thickness of 67 m (220 ft) (Figure 33B). Generally, the sands are well-sorted, very fine to medium-grained sandstones (Appendix 1), most of which coarsen upward. The rocks are quartzose, and locally contain significant quantities of feldspars (Figure 23B) and rock fragments. Plagioclase feldspar is more common than orthoclase feldspar. OI sandstones contain limited cementing material, with silica and pyrite being the most common. Clays occur mainly in detrital shale laminae (Figure 23D).

Reservoir parameters for the OI sandstones are listed in Appendix 1. The OI sandstone is second only to the LF sandstone in oil production. Ultimate recoverable field reserves are estimated to be 49 million bbl of oil, 60 bcf of solution gas, and 122 bcf of nonassociated gas. Cumulative production on Block 330 is 33.3 million bbl of oil plus condensate and 130.1 bcf of gas (March 1988). The sands are overpressured, with a pressure gradient of 0.76 psi/ft.

Gravity segregation is the dominant drive mechanism in the OI reservoir. PVT fluid studies indicate that normal pressure depletion increases oil viscosity in the reservoir, thereby decreasing the oil mobility and recovery efficiency. Computer reservoir studies indicate that pressure maintenance by crestal gas injection is the most efficient method of secondary recovery for the OI reservoir. Gas injection enhances the natural gravity separation of the oil and gas within the formation by displacing the oil downdip to the producing wellbores.

The gas injection, pressure-maintenance program in the OI fault block "A" reservoir was implemented in December 1979 (Figure 34). A total of 17.3 bcf of gas is planned to be injected over the duration of the program, with 14.4 bcf of gas being recoverable.

During the 7 years of production prior to gas injection, reservoir pressure dropped 1454 psi with production of 11.5 million bbl of oil and 11.75 bcf of gas. In contrast, during the 10 years of gas injection, reservoir pressure has dropped only 671 psi with production of 14 million barrels of oil and 12.1 bcf of gas (Figure 34).

Reservoir recovery is now 52% of the original oil-in-place, and ultimate recovery is expected to exceed 58%. An additional 30% increase to the originally estimated 28% primary-recovery efficiency can be attributed to this pressure-maintenance program. These data confirm the significant role of secondary recovery by gas injection in the OI reservoir on Eugene Island Block 330.

Fig. 33A. Top OI sandstone structure map. Discovery well (E.I. 331 #1) shown.

Fig. 33B. OI net sandstone isopach map.

Fig. 34. Gas-injection project, OI sandstone, Block 330. Oil production (solid line) and gas injection (dashed line) shown.

FAULTS

The major growth fault system bounding the field was instrumental in the formation of rollover anticlinal traps. Faulting was contemporaneous with deposition throughout the Pleistocene and continues today. Salt domes around the periphery of the subbasin were integral in the formation of growth faults, and some of the extremities of the fault system extend to these diapirs. Antithetic faults also are present and subdivide the structure into numerous producing faultblock reservoirs. Faults, especially on the eastern structure, are sealing faults, as evidenced by a down-dip gas reservoir juxtaposed against an updip oil reservoir (as discussed in the section on the OI sandstone) (also see Figure 33A).

The major down-to-the-basin growth faults were initially recognized and mapped using the pre-1970 seismic data. Additional faulting, especially at greater depths, and refined fault locations have been identified using subsequent development drilling, 2D, and now 3D, seismic data.

SOURCE (ROCK) (Table 9)

Petroleum Geochemistry

Recent studies of Gulf of Mexico oils have shown that most offshore oils can be assigned to one of two broad genetic families (Walters and Cassa, 1985; Kennicutt and Thompson, 1988). The smaller and more distinctive family is represented by oils in Pleistocene reservoirs of the Louisiana shelf-slope break region and includes the oils from the Eugene Island Block 330 field. The crude oil of this group is characterized by significantly higher sulfur and vanadium concentrations and lower pristane/phytane ratios relative to other Gulf of Mexico oils. These geochemical characteristics suggest that these oils were derived from a marine source facies deposited under more reducing (anoxic) conditions than for the bulk of the offshore oils.

Representative chromatograms of oil from Block 330 are shown on Figure 35, and the characteristics of the oil are summarized on Table 1, Table 2, and Table 3. Oil from reservoirs above 1951 m (6400 ft) show evidence of considerable biodegradation and water washing, but more deeply reservoired oil is relatively unaltered and contains a full suite of normal alkanes. The unaltered oils are assignable to the paraffinic-naphthenic class of Tissot and Welte (1984), whereas the biodegraded oils belong to the aromatic-intermediate class. Most of the variation in physical and chemical properties of Block 330 oils can be attributed to the effects of biodegradation. Source-sensitive characteristics such as isotopic composition, V/V+Ni ratio, and selected biomarker ratios indicate that all Eugene Island Block 330 oils are genetically similar and were derived from a common source facies. Pleistocene shales associated with the Block 330 reservoirs do not qualify as the source rocks for these oils because of their thermal immaturity (R<inf/0/ = 0.31-0.47%) and low organic carbon content (TOC 0.30-0.80%), and the highly oxidized nature of their predominantly terrestrial kerogen (Holland et al., 1980).

The Eugene Island Block 330 oils show abundant evidence of long-distance vertical migration. Based on a variety of biomarker and gasoline-range maturity indicators, these oils are estimated to have been generated at depths of 4572 to 4877 m (15,000 to 16,000 ft) at vitrinite reflectance maturities of 0.08 to 1.0% and temperatures of 150 to 170°C (300 to 340°F). Their presence in shallow, thermally immature reservoirs requires significant vertical migration. This is illustrated on Figure 36, which represents a burial and maturation history for the field at the time of petroleum migration, that is, at the end of Trimosina "A" time approximately 500,000 years ago. A plot of the present measured maturity values versus depth is superimposed on the calculated maturity profile for Trimosina "A" time to illustrate the close agreement between measured and predicted maturity profiles. The clear discrepancy between reservoir maturity and oil maturity is striking and suggests that the oil migrated more than 3650 m (12,000 ft) from a deep, possibly upper Miocene, source facies. Petroleum migration along faults is indicated based on the observed temperature and hydrocarbon anomalies at the surface and the distribution of pay in the subsurface. These results are consistent with those of Young et al. (1977), who concluded that most Gulf of Mexico oils originated 2438 to 3350 m (8000 to 11,000 ft) deeper than their reservoirs, from source beds 5 to 9 million years older than the reservoirs.

Fig. 35. Whole-oil chromatograms from Block 330 GA-2 and LF reservoirs showing relatively unaltered deeply buried oil and strongly altered shallower oil. Numbers refer to the carbon numbers of the normal alkanes.

Fig. 36. Thermal burial and maturation history at the end of Trimosina "A" time for Eugene Island Block 330 oils based on vitrinite reflectance (R<inf/0/) data. See type log (Figure 15) for ages of sandstone units.

Table 1. Crude Oil Characteristics.

Table 2. Hydrocarbon characteristics--Eugene Island Block 330.

Table 3. Field characteristics--Eugene Island Block 330.

EXPLORATION AND DEVELOPMENT CONCEPTS

Regional Play and General Application of Geologic Parameters

The Pliocene-Pleistocene play on the offshore Louisiana shelf, of which the Eugene Island Block 330 field is a part, is typified by the following geological characteristics:

1. Structural features dominated by growth faults, salt domes, and salt-related faulting.
2. Thick accumulations of predominantly deltaic deposits of alternating sand and shale.
3. Young reservoirs (less than 2.5 m.y. old) with migrated hydrocarbons whose origins are in deeper, organic-rich marine shales.
4. Rapidly changing stratigraphy, due to deposition and subsequent reworking.
5. Numerous oil and gas fields with stacked reservoirs, long hydrocarbon columns, and high producing rates.

The exploration keys to success in this play are identifying prime stratigraphic fairways for favorable sand deposition and locating structures within these fairways that provide good avenues for migration and adequate trapping mechanisms. The timing of the trap formation is also important, and must be related to structural movement and depositional history.

Numerous fields of various sizes, trapping styles, and producing horizons surround the Block 330 field (Figure 37). Most of these fields can be classified into the following trap styles: (1) rollover anticlines, (2) faulted anticlines, (3) diapirs, or (4) upthrown fault traps. Cumulatively, the Block 330 field and its surrounding fields, located on Figure 37, have produced more than 338 million bbl of liquids and 4.748 tcf of gas.

Many of the geological characteristics outlined above can be applied to similar rifted, passive continental margins with thick deltaic deposits. The parameters most characteristic of the Gulf Coast basin are the apparent long vertical migration paths of hydrocarbons into younger reservoirs and the ubiquity of salt domes.

Fig. 37. Field outlines and trapping styles for fields surrounding Eugene Island Block 330 field. Total cumulative production for fields shown is more than 328 million bbl of oil and 4.7 tcf of gas.

Lessons

The Eugene Island Block 330 field is a giant oil and gas field resulting from the favorable occurrence and history of many key geologic parameters and conditions. The field received the highest geologic rankings as an undrilled, presale prospect in 1970 on the basis of geologic and geophysical data and concepts that were state-of-the-art at that time. Clearly, if the Block 330 field were identified as an undrilled prospect in today's exploration environment, with modern data and concepts, it would rank as a top exploration prospect, be better understood geologically and geophysically, and generate a very high level of lease sale bidding interest.

Exploration with modern seismic data would allow us to define in more and finer detail the structural and stratigraphic elements of the field and the seismic hydrocarbon indicators associated with many of the reservoirs. Modern seismic stratigraphic and seismic hydrocarbon indicator theory and interpretation techniques were not available in the early 1970s, and their use undoubtedly would enhance the exploration and development programs. Present-day exploratory drilling would probably closely parallel the 1970s drilling history; wells would be located on the west side of Block 330, at the crest and on the flanks of the structure, to define reservoir numbers, thickness, column, and areal extent. A greater density of better quality seismic data would also help to optimize and refine exploratory well locations, drilling depths, the number of wells necessary, and postdrilling evaluations.

The acquisition of a 3D seismic survey prior to development would be the most beneficial exploitation tool available today. 3D seismic data would be used for precisely locating platforms, development wells, and later exploratory wells and for optimizing well spacing and recovery efficiency, thereby optimizing and expediting field development and production. However, it would be very difficult to improve upon the actual record of initial production 1 year and 9 months after lease acquisition.

Over the years, we have performed numerous geologic, geophysical, and engineering studies of the Block 330 field. The implementation of recommendations from these studies has included projects such as exploration and development drilling, and pressure maintenance by gas injection. From 1978 to 1988, these operations, activities, and natural factors have increased ultimate recoverable reserves from 225 million bbl to 307 million bbl of hydrocarbon liquids and from 950 bcf to 1.65 tcf of gas.

As noted earlier (Figure 5), the field has experienced several phases of exploration and development. Exploratory drilling in 1982-1986 led to the discovery of additional hydrocarbons on the upthrown side of the main growth fault on Block 330, a fourth platform was set on the block, and eight development wells were drilled. In addition, 15 other fields have been discovered in the area over the last 18 years (Figure 37).

Currently, Block 330 is in another reevaluation phase. The most important aspect of our present evaluation is the use of 3D seismic data and techniques to identify new exploration and development prospects previously unidentified by 2D seismic methods and drilling. These highly economic prospects will utilize existing production facilities, add additional recoverable reserves, and extend the producing life of the field well into the future. One example is the HB sandstone prospect in the northwest corner of Block 330 (Figure 38). A proposed development well (Figure 39) will test a high-amplitude seismic event in an undrilled fault block recently identified using 3D data. Seismic amplitudes at the HB sandstone level are as intense as those observed in zones of known pay to the south. Also within this same fault block, two deeper levels of high-amplitude reflectors correlate to known pay zones and are targets for two additional development wells. Using 3D seismic data, we have also identified a deeper exploratory prospect, below present production levels on Block 330, that will be tested by a future exploratory well.

Fig. 38. Top HB sandstone structure map. Potential oil and gas reserves will be tested by a deviated development well from the "A" platform (square) on Block 330.

These prospects and others will be tested by drilling and should add additional economic reserves to an already giant field. Our ongoing evaluation has continually refined our geologic understanding and, although the field is mature, exploration and development continue.

Fig. 39. Seismic line from 3D seismic data volume illustrating the HB development prospect shown in Figure 38.

REFERENCES

Bally, A. W., and S. Snelson, 1980, Realms of subsidence, in Facts and principles of world petroleum occurrence: Canadian Society of Petroleum Geologists Memoir 5, p. 9-94.

Brooks, J. M., M. C. Kennicutt, II, and B. D. Carey, 1986, Offshore surface geochemical exploration: Oil and Gas Journal, v. 84, n. 24, p. 66-72.

Bruce, C. H., 1973, Pressured shale and related sediment deformation: mechanism for development of regional contemporaneous faults: American Association of Petroleum Geologists Bulletin, v. 57, p. 878-885.

Carmalt, S. W., and B. St. John, 1986, Giant oil and gas fields, in M. T. Halbouty, ed., Future petroleum provinces of the world: American Association of Petroleum Geologists Memoir 40, p. 11-54.

Caughey, C. A., 1975, Pleistocene depositional trends host valuable gulf oil reserves: Oil and Gas Journal, v. 73, n. 36, 37, p. 90-94, 240-242.

Faber, E., and W. Stahl, 1984, Geochemical surface exploration for hydrocarbons in the North Sea: American Association of Petroleum Geologists Bulletin, v. 68, p. 363-386.

Fisher, W. L., 1969, Facies characterization of Gulf Coast basin delta systems, with some Holocene analogues: Gulf Coast Association of Geological Societies Transactions, v. 19, p. 239-261.

Gilreath, J. A., and J. J. Maricelli, 1964, Detailed stratigraphic control through dip computations: American Association of Petroleum Geologists Bulletin, v. 48, p. 1902-1910.

Hall, D. J., T. D. Cavanaugh, J. S. Watkins, and K. J. McMillen, 1982, The rotational origin of the Gulf of Mexico based on regional gravity data, in J. S. Watkins and C. L. Drake, eds., Continental margin geology: American Association of Petroleum Geologists Memoir 34, p. 115-125.

Holland, D. S., W. E. Nunan, D. R. Lammlein, and R. L. Woodhams, 1980, Eugene Island Block 330 field, offshore Louisiana, in M. T. Halbouty, ed., Giant oil and gas fields of the decade: 1968-1978: American Association of Petroleum Geologists Memoir 30, p. 253-280.

Humphris, C. C., Jr., 1978, Salt movements on continental slope, northern Gulf of Mexico, in A. H. Bouma et al., eds., Framework, facies, and oil trapping characteristics of the upper continental margin: American Association of Petroleum Geologists Studies in Geology 7, p. 69-85.

Jones, V. T., and R. J. Drozd, 1983, Prediction of oil or gas potential by near-surface geochemistry: American Association of Petroleum Geologists Bulletin, v. 67, p. 932-952.

Kennicutt, M. C., II, and K. F. M. Thompson, 1988, A suggested genetic classification of Gulf of Mexico offshore oils (abs.): American Association of Petroleum Geologists Bulletin, v. 72, p. 205.

Klemme, H. D., 1971, What giants and their basins have in common: Oil and Gas Journal, v. 69, n. 9, 10, 11; pt. 1, p. 85-90; pt. 2, p. 103-110; pt. 3, p. 96-100.

Lewis, R. L., H. J. Dupuy, Jr., and D. S. Holland, 1982, Eugene Island Block 330 field--development and production history: International Petroleum Exhibition and Technical Symposium Proceedings, Society of Petroleum Engineers, SPE 10003, p. 1-13.

Limes, L. L., and J. C. Stipe, 1959, Occurrence of Miocene oil in South Louisiana: Gulf Coast Association of Geological Societies Transactions, v. 9, p. 77-90.

Martin, R. G., 1978, Northern and eastern Gulf of Mexico continental margin: stratigraphic and structural framework, in A. H. Bouma et al., eds., Framework, facies, and oil trapping characteristics of the upper continental margin: American Association of Petroleum Geologists Studies in Geology 7, p. 21-42.

Mitchum, R. M., Jr., P. R. Vail, and J. B. Sangree, 1977, Seismic stratigraphy and global changes of sea level, part 6: stratigraphic interpretation of seismic reflection patterns in depositional sequences, in C. E. Payton, ed., Seismic stratigraphy--applications to hydrocarbon exploration: American Association of Petroleum Geologists Memoir 26, p. 117-133.

Norwood, E. M., Jr., and D. S. Holland, 1974, Lithofacies mapping a descriptive tool for ancient delta systems of the Louisiana outer continental shelf: Gulf Coast Association of Geological Societies Transactions, v. 24, p. 175-188.

St. John, B., A. W. Bally, and H. D. Klemme, 1984, Sedimentary provinces of the world, hydrocarbon productive and nonproductive: American Association of Petroleum Geologists Map Series, 35 p.

Tissot, B., and D. Welte, 1984, Petroleum formation and occurrence: New York, Springer-Verlag, 2nd ed., 699 p.

Walters C. C., and M. R. Cassa, 1985, Regional organic geochemistry of offshore Louisiana: Gulf Coast Association of Geological Societies Transactions, v. 35, p. 277-286.

Woodbury, H. O., I. B. Murray, Jr., P. J. Pickford, and W. H. Akers, 1973, Pliocene and Pleistocene depocenters, outer continental shelf. Louisiana and Texas: American Association of Petroleum Geologists Bulletin, v. 57, p. 2428-2439.

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SUGGESTED READING

Brown, L. F., Jr., and W. L. Fisher, 1982, Seismic stratigraphic interpretation and petroleum exploration: American Association of Petroleum Geologists Continuing Education Course

Fig. 32.

Note Series #16, 181 p. Review of seismic stratigraphy and the geometry of depositional systems.

Dow, W. G., 1978, Petroleum source beds on continental slopes and rises: American Association of Petroleum Geologists Bulletin, v. 62, p. 1584-1606. Reviews conditions required for the formation of petroleum source beds, with special emphasis on the Gulf of Mexico.

Dow, W. G., 1984, Oil source beds and oil prospect definition in the Upper Tertiary of the Gulf Coast: Gulf Coast Association of Geological Societies Transactions, v. 34, p. 329-339. Proposes localized preservation of oil-prone kerogen during the Tertiary in anoxic intraslope basins.

Jackson, M. P. A., and W. E. Galloway, 1984, Structural and depositional styles of Gulf Coast Tertiary continental margins: application to hydrocarbon exploration: American Association of Petroleum Geologists Continuing Education Course Note Series #25, 226 p. Good summary with illustrations of growth faulting, rollover anticlinal traps, and deltaic depositional sequences.

Jones, R. W., 1987, Organic facies, in J. Brooks and D. Welte, eds., Advances in petroleum geochemistry, v. 2: London, Academic Press, p. 1-90. A thorough review of the concept of organic facies, their characteristics and petroleum potential, and the application of the organic facies concept in exploration.

Martin, R. G., and J. E. Case, 1975, Geophysical studies in the Gulf of Mexico, in A. E. M. Nairn and F. G. Stehli, eds., Ocean basins and margins; the Gulf of Mexico and the Caribbean: New York, Plenum Press, v. 3, p. 65-106. Gulf of Mexico physiography and origin.

Nunn, J. A., and R. Sassen, 1986, The framework of hydrocarbon generation and migration, Gulf of Mexico continental slope: Gulf Coast Association of Geological Societies Transactions, v. 36, p. 257-262. Discussion of maturation modeling results, which suggest that Cretaceous and Early Tertiary sediments are possible source rocks for oil in Pliocene-Pleistocene reservoirs.

Rice, D. D., 1980, Chemical and isotopic evidence of the origins of natural gases in offshore Gulf of Mexico: Gulf Coast Association of Geological Societies Transactions, v. 30, p. 203-213. Describes significant differences in isotopic composition of methane in reservoirs across the Gulf of Mexico basin and discusses their origin.

Williams, D. F., and I. Lerche, 1987, Salt domes, organic-rich source beds and reservoirs in intraslope basins of the Gulf Coast region, in I. Lerche and J. J. O'Brien, eds., Dynamical geology of salt and related structures: Orlando, Florida, Academic Press, p. 751-786.

Williams, D. F., and I. Lerche, 1987, Hydrocarbon production in the Gulf Coast region from organic-rich source beds of ancient intraslope basins: Energy Exploration and Exploitation, v. 5, p. 199-218. Discusses a model in which salt structures underlying the continental margin of the northern Gulf of Mexico are suggested to play a major role in determining the origin, distribution, and maturation history of petroleum source beds.

Fig. 33A.

Acknowledgments:

The authors thank Pennzoil Exploration and Production Company and the Eugene Island Block 330 partners for permission to publish this paper. We gratefully acknowledge all current and past Pennzoil U.S. Offshore Division personnel who have contributed to the current understanding of the field, including the following, who have particularly assisted in this and previous papers: V. F. Laiche, R. L. Lewis, D. C. Nester, E. M. Norwood, Jr., W. E. Nunan, C. F. Oudin, III, J. F. Rielly, D. Schumacher, B. R. Stewart, C. E. Sutley, and R. L. Woodhams. Richard Vessel of David K. Davies and Associates, Inc., assisted in the petrographic analysis.

 

We also thank the reviewers whose comments have significantly improved the manuscript, including J. M. Austin, B. E. Ball, F. W. Broussard, D. Curtis, R. McDonald, III, M. J. Padget, R. W. Spoelhof, J. F. van Sant, and K. R. Whaley.

 

We are also grateful to J. L. Howard and S. L. Winzig for typing the manuscript and to J. Rodriguez, Jr., C. Hinojosa, Jr., P. D. Maloney, C. A. Fullbright, and S. A. Shroyer for drafting the figures.

Copyright 1995 American Association of Petroleum Geologists