Wilcox Reservoirs Research Articles

The northern Gulf of Mexico offshore super basin: Reservoirs, source rocks, seals, traps, and successes

The northern Gulf of Mexico federal offshore area easily qualifies as a super basin based upon estimated petroleum endowment of more than 100 BOE and cumulative production of 60 BOE. Like other super basins, it has multiple petroleum systems and stacked reservoirs. Examination of four key elements of these petroleum systems (reservoirs, source rocks, seals, and traps) yields important insights to the geologic processes that result in such an exceptional habitat for conventional hydrocarbons. The bulk of hydrocarbon resources in federal offshore waters is in Cenozoic sandstone reservoirs such as the Paleogene Wilcox reservoir of deep-water subsalt areas. Overall, Cenozoic sandstone reservoirs in both suprasalt and subsalt fields yield the highest flow rates and cumulative production volumes. Notable is the recent addition of the deep-water Jurassic Norphlet sandstone play, the newest and second largest by ultimately technically recoverable resources. Overall, Gulf of Mexico reservoirs are diverse, formed in paleoenvironments ranging from aeolian to deep water. Powering this super basin are three primary marine source rocks centered in the Oxfordian, Tithonian, and Cenomanian–Turonian Stages. These source rock intervals commonly act as top seals, but other Neogene and Mesozoic shales and even carbonate mudstones are also important trap-sealing elements, as proven by analytical work and downhole pressure measurements. The extensive salt distribution and relatively late Cenozoic burial delayed source rock maturation and migration until the culmination of trap formation in many areas. High rates of Cenozoic deposition on a mobile salt substrate also generated a myriad of salt tectonic structures, ranging from simple diapiric closures and extensional fault traps to complex subsalt configurations such as salt-cored compressional anticlines, salt-cutoff traps, and bucket weld traps. Exploration success in the past 20 yr is a direct result of improved seismic imaging around and below salt, as well as advances in drilling, completing, and producing wells and fields.

Southern Gulf of Mexico Wilcox source to sink: Investigating and predicting Paleogene Wilcox reservoirs in eastern Mexico deep-water areas

Source-to-sink analyses show that northern Gulf of Mexico (GOM) Wilcox Group siliciclastic deep-water systems are linked to transport of sediments from the Laramide tectonic belt into the deep basin. Less is known, however, about southern GOM sedimentation. New drilling and discoveries in the Mexican deep water have generated considerable interest since the opening of Mexico to international exploration. To investigate Paleogene deposition in Mexico’s offshore areas, a three-phased approach was employed: (1) seismic mapping of deep-water depocenters, (2) regional stratigraphic analysis of potential basin entry points, and (3) prediction of submarine-fan dimensions using empirical scaling relationships. Isochore and structural mapping of the Wilcox depocenters used available well and seismic data. Potential basin entry points were identified by evaluation of Wilcox fluvial–deltaic systems and tectonic elements. Empirical scaling relationships previously established between fluvial and deep-water segments provide first-order predictions of submarine-fan dimensions. Paleogene Wilcox source-to-sink systems of the greater GOM basin change north to south as a function of varied tectonics and sedimentary accommodation. The United States sector was a passive margin: continental-scale drainage systems fed a broad, gently dipping shelf. By contrast, the southern GOM basin was a tectonically active margin: smaller-scale fluvial systems sourced from the Hidalgoan uplands flowed directly into foreland basins located on the slope. Results presented here indicate that several systems rimming the southern GOM were able to effectively transfer sediment from the mountain belt into the basin. Regional observations and semiquantitative predictions of fan dimensions provide a context for future detailed work based on new well and seismic information.

Leveraging Technology to Win in the Deepwater Gulf of Mexico Wilcox Plays

Tech 101 - Leveraging technology to win in the deepwater Gulf of Mexico Wilcox plays. The focus of my past few years has been on a technology-driven play in the Lower Tertiary-Age reservoirs of the deepwater Gulf of Mexico (GOM). These Upper, Middle, and Lower Wilcox reservoirs represent a large resource base in an infrastructure-rich basin. Chevron-operated production will begin from the Wilcox reservoir in 2014, when the company’s Jack/St Malo subsea development is commissioned. In addition, Chevron’s two most recent deepwater GOM discoveries have been in the Wilcox, and the company continues to hold a very strong lease position for future exploration. Technology Management System Across Chevron: The “Focus Area” Model Like most integrated energy companies, Chevron has evolved a system of technology governance that suits the enterprise. To ensure the technologies critical to providing competitive differentiation are identified and advanced, the company developed a “focus area” model. Decisions are made by governance bodies composed jointly of energy technology company (ETC) and operating company representatives. Strategic drivers are identified and validated for the various Technology Focus Areas (such as exploration, reservoir management, or deepwater development), and technology initiatives are funded on the basis of a technology’s risk/reward profile and its alignment with the strategic drivers. These initiatives are managed by technology practitioners within ETC, ensuring that the technologies that are developed and the lessons learned coincident with early deployment are easily shared throughout the enterprise. Business units are allocated their fair share of the cost to develop each technology, and most development projects managed within the focus area process contribute to the common good (or at least the good of a significant sector) of the corporation.

Geological and Geochemical Evidence for Vertical Migration of Upper cretaceous Sourced Oils Into Tertiary Reservoirs: Winn and Grant Parishes, Louisiana: ABSTRACT

ABSTRACT Analyses of three Wilcox oils taken from the Colgrade Field (Carrizo sand reservoir), Bulger Creek Field (middle Wilcox sand reservoir), both in Winn Parish, and the Blue Lick Field (middle Wilcox sand reservoir) Grant Parish, Louisiana, correlate with other Gulf Coast oils sourced from the Upper Cretaceous (probably the Austin Chalk or Eagle Ford. All three samples are mature and highly biodegraded. The oils from Blue Lick and Bulger Fields contain bisnorhopane (BNH), a Wilcox and younger biomarker in central Louisiana and southwest Mississippi. BNH was identified previously by the authors in Chalk oil from Clark Creek Field, Wilkinson Co., Mississippi. Previous studies project northeast-southwest wrench faulting (Boeuf River Fault) into the oil sample area. This faulting, and associated extensional fracture/fault and salt tectonism cause the conduits for vertical migration which emplaced the sampled oils into Wilcox reservoirs. The oils probably migrated from both the Austin Chalk and Eagle Ford source beds. The oils provide additional evidence that Wilcox and younger oil reservoirs of central Louisiana and southwest Mississippi were filled by vertical migration from Mesozoic source beds in contrast to long range lateral migration proposed by earlier workers. The Central Louisiana Fracture Zone (CLFZ) is described as an extensional fracture zone generated by wrench faulting. The trend of the zone coincides closely with that of the LaSalle Arch and is important in concentrating hydrocarbons along the arch. Exploration targets arise in all traps above the source beds in the area.

Assessment of Reserves in the WX-4 Wilcox Deltaic Sandstones in the Rio Grande Embayment

An estimate is given of expected total gas reserves in place in the WX-4 Deltaic Sandstones of the Wilcox Formation in the Rio Grande Embayment based upon open-domain information taking into account detailed production figures from Wilcox reservoirs along the shelf trend. The overall estimate would suggest that a total amount of gas in place is roughly between 5 to 23 TCF (at STP) with a likely value of 14 TCF. Since production statistics indicate 6 TCF already produced with an average depletion of 83%, for a total expected ultimate recoverable in known reservoirs of around 7.2 TCF, the implication is that a maximum of between 0 to 15 TCF remain to be discovered, with a most likely discoverable amount of 6-7 TCF.

Lower Wilcox Reservoir Characteristics: Evidence for Bypassed and Subjacent Hydrocarbon Potential, East Central Louisiana

Lower Wilcox Reservoir Characteristics: Evidence for Bypassed and Subjacent Hydrocarbon Potential, East Central Louisiana

Depositional Environments of the Wilcox Group, Texas Gulf Coast: Stratigraphic and Early Diagenetic Signatures: ABSTRACT

ABSTRACT Deposition of the late Paleocene-early Eocene Wilcox Group is controversial. Are Wilcox reservoirs entirely of shallow-marine origin, or are basinal turbidites also present? We analyzed over 5000 feet of core from 15 wells along the Texas Gulf Coast to constrain the depositional environments. We attribute all cores examined to date to 12 subenvironments of delta-plain through continental-shelf settings. These include distributary channel, lake, marine bay, crevasse-splay delta, shoreface, lagoon, tidal flat, tidal channel, distributary-mouth bar, distal bar, prodelta, and shelf. Criteria for facies delineation in core include grain-size variations, physical sedimentary structures, trace fossils, mineralogy, bedding styles, and vertical sequences, all resulting from the interplay of specific physical, biological, and chemical processes operative in each subenvironment. We did not identify any submarine-fan deposits. We also attempted to determine the importance of depositional facies and provenance on diagenetic trends. Early diagenetic patterns appear to be related to factors such as sediment texture, detrital composition, organic content, and original water chemistry, which were, in turn, controlled directly or indirectly by depositional environment. Rapid lateral and vertical changes in depositional environments produced markedly different early diagenetic patterns in sand units only a few feet or even inches apart. Thus, diagenetic facies defined on the basis of texture, composition, and cements can be used to complement, and test, our interpretations of depositional environments based solely on traditional sedimentologic and genetic-sequence criteria.

Source and Thermal History of Oils from Lockhart Crossing, Livingston Parish, Louisiana: ABSTRACT

ABSTRACT In 1982, Lower Tuscaloosa production at the Lockhart Crossing Field was supplemented with a major discovery of significant petroleum reserves in the Wilcox. Whole-oil and biomarker source parameters definitively prove that the oils found in Wilcox reservoir rocks constitute one single oil family. Oils produced from the Tuscaloosa Formation comprise a separate oil family unrelated to the oils in the Wiilcox Formation. Within each formation, the oils become progressively more mature with depth. This is believed to be due to thermal cracking which as taken place after the oil charged with the reservoirs. The chemistry of the oils produced from Wilcox reservoirs shows that these oils were generated from clay-rich shales with a significant input of bacterial organic matter. Eukaryotic algae and higher plants also contributed organic matter to the source rocks. Comparisons with cuttings from nearby wells prove that Wilcox shales are the source facies for these oils. Biomarker and other maturity parameters indicate that the Wilcox oils were generated from source rocks that were within the thermal regime associated with early oil generation. Tuscaloosa reservoir fluids are significantly more thermally mature than the petroleum in the Wilcox. The Tuscaloosa oils are presently in the thermal conditions associated with late-stage oil/gas condensate generation. Because of this advanced degree of thermal stress, correlation of the Tuscaloosa oils to their source sediments is difficult. Cuttings from wells updip from Lockhart Crossing indicate that the Lower Marine Tuscaloosa shales are viable source rocks. Equivalent downdip shales are the likely source for the Lockhart Crossing Tuscaloosa gas condensates. The study proves that future Wilcox discoveries in the area need not be associated with deeper Tuscaloosa production.

Origin of Crude Oil in the Wilcox Trend of Louisiana and Mississippi: Evidence of Long-Range Migration: ABSTRACT

ABSTRACT Geochemical characterization of crude oils from Wilcox reservoirs in central Louisiana and southwest Mississippi suggests that they represent a single crude oil family that is distinct when compared to crude oils in deeper Tuscaloosa and Smackover reservoirs. This observation is consistent with geologic constraints that suggest an origin of crude oil from within the Wilcox Group itself. Although shales of the shallow Wilcox Group in central Louisiana and southwest Mississippi contain gas-prone kerogen and are thermally immature, a more oil-prone source facies is present in marine shales of the deep Wilcox Group in southcentral Louisiana. Thermal maturity measurements based on pyrolysis suggest a broad area of effective Wilcox source rock in southcentral Louisiana. Migration distances from source to reservoir rocks of the downdip Wilcox Trend of southcentral Louisiana appear to be relatively short. However, long-range updip migration (sometimes greater than 100 km) from deeply buried Wilcox source facies provides the best explanation for emplacement of crude oil in the shallow Wilcox Trend of central Louisiana and southwest Mississippi.

New Ulm Field: An Example of Cretaceous Shelf-Slope Instability in East Texas: ABSTRACT

The New Ulm field in Austin County, Texas, is an example of the structural and stratigraphic complexity above the Cretaceous Edwards shelf margin of east Texas. Deep wells and improved seismic data provide documentation of structural patterns and deepwater facies not previously considered in Gulf Coast reservoir play modeling. Study of the data implies the Late Cretaceous to Eocene section was deposited along a shelf-slope break. Late Cretaceous, pre-Midway sedimentation was affected by structurally induced slope instability, and consequent gravity faulting and slumping resulted in an irregular sea-floor surface. Paleocene Midway sands were carried onto this surface by storm-generated density currents where the uneven topography caused deposition in constructional channels. Continued deposition of the fluvio-deltaic Wilcox on this surface caused faulting and folding by differential compaction. The folds are minor and the faults small and steep, not like the typical large growth faults of the Gulf Coast. Upper Wilcox sediments were progressively less disturbed as the region stabilized. New Ulm field production includes gas from the Midway Formation and oil and gas from the Wilcox Group. Midway reservoirs are stratigraphic, consisting of turbidite channel sandstones; Wilcox reservoirs are structural, consisting of fluvio-deltaic sandstones within faulted anticlines. This study adds evidence to data describing shelf-slope geology along the Edwards margin. The setting can be a new type of hydrocarbon play in the Gulf Coast. End_of_Article - Last_Page 516------------

Unique Enhanced Oil and Gas Recovery for Very High-Pressure Wilcox Sands Uses Cryogenic Nitrogen and Methane Mixture

Summary Primary recovery is low for the volatile oil and retrograde condensate reservoirs in the hot, high-pressured, multilayered Wilcox sands in the Fordoche field, Point Coupee Parish, LA. Recovery from oil reservoirs by depletion is predicted by numerous model studies to be 26 to 36% of the OOIP. Condensate recovery by depletion is predicted to be 19% of the original condensate in place and 25% of original separator gas in place. The injection of dry natural gas at high pressures will result in a miscible displacement of reservoir fluids. The immiscible displacement of reservoir fluids. The injection of a mixture of nitrogen and dry gas is predicted to be as effective as injecting dry natural gas. Model studies of gas injection in volatile oil reservoirs predict recoveries from 47 to 54% of the OOIP, and in the retrograde condensate reservoir recoveries are predicted to be 30 and 46% of the original condensate and gas in place. Oil recovery studies at 6,955 psig indicate that gas injection will displace 89% at breakthrough and 93% at blowdown at 100% sweep efficiency. A well stimulation program has been developed that results in a 2.5-fold increase in production rates. Introduction The Fordoche field was discovered by Sun Oil Co. in 1966. The location is shown in Fig. 1. The field was developed fully on 160-acre well spacing by 1970. A total of 36 wells was drilled during the short 4-year development period. Well depths ranged from 11,800 to 16,500 ft (See Fig. 2, a typical log for the Fordoche field.) Seven reservoirs encountered between depths of 11,300 to 13,900 ft had initial bottomhole pressures (BHP's) ranging from 8,372 to 11,018 psig and bottomhole temperatures (BHT's) ranging from 226 to 278°F. The Sparta sands are undersaturated oil reservoirs. The Wilcox 4 and 5 (W-4 and W-5) sands are gas-condensate reservoirs. The W-8, W-12, and W-15 sands are undersaturated volatile oil reservoirs. All of the Wilcox reservoirs experienced rapid rates of reservoir pressure depletion. Productivity of all wells declined severely. After evaluating water injection and gas injection programs, high-pressure gas injection was selected for the two major oil reservoirs, W-8A and W-12A, and for the largest retrograde reservoir, W-5A. (See Figs. 3, 4, and 5). A very high-pressure miscible gas injection project was instituted to maintain pressure and well productivity and to enhance ultimate recovery. Initially, extraneous gas was purchased for makeup and injected with the processed natural gas produced in the field. Because of the increasing cost of natural gas and the restricted oil price of $5.35 per barrel, economics dictated that the project be changed to a partial pressure maintenance program with a lower ultimate recovery or find a substitute for natural as used for makeup.

Characteristics of Lower Wilcox Reservoirs, Valentine Field, Lavaca County, Texas: ABSTRACT

In the Valentine field, Lavaca County, Texas, sandstones of the lowermost Wilcox Group produce oil at depths of about 9,100 ft (2,776 m) in a stratigraphic trap from two sandstones locally called the and zones. Full-diameter cores from the Technik zone show that it consists of thin-bedded turbidites. The Technik reservoir is 25 ft (8 m) thick in a core from the Harkins 1 Mikulenka well. The upper part is composed of thicker beds on the order of 2 to 4 ft (0.6 to 1.2 m), and each displays sequences of massive or massive-to-laminated bedding. These sandstones represent turbidite sequences of the AE and ABE types and were probably End_Page 1595------------------------------ channel deposits. The lower part is composed of thinner beds about 1 ft (0.3 m) thick of more complete sequences which include ripple laminae. These sandstones represent turbidites of the ABCE type and were probably overbank deposits. Some adjacent sandy shales are moderately bioturbated, generally on a fine scale. The Technik nonreservoir facies is 31 ft (9.5 m) thick in a core from the Harkin-Five Resources 1 Cyrus Paul well. The section consists of thinly interbedded shales and turbidite sandstones which are typically incomplete sequences of the AE, BE, and CE types. The shales are not bioturbated. The nonreservoir facies may be characterized as distal overbank deposits. The nonreservoir facies of the overlying Kubena zone is similar. The reservoir sandstones are fine grained (0.17 mm) and contain 59% quartz, 12% other mineral grains, 14% matrix, and 15% kerogenlike organic material. Silica overgrowths and calcite cements comprise an average 13% of bulk volume. Composition results in a relatively low average permeability of 4 md and porosity of 18%. The Technik reservoir sandstone appears to represent the fill of outer-shelf channels along which sands were transported to the shelf margin and into the deeper basin beyond. The nonreservoir facies represents overbank deposits adjacent to channels, but the relation between channel and overbank deposits is not clear. The overbank deposits could have been either contemporaneous, levee sediments adjacent to channel-fill sandstones, or they may represent deposits into which later channels were eroded and then filled. End_of_Article - Last_Page 1596------------

Exploration Methods of Discovery and Development of Lower Wilcox Reservoirs in Valentine and Menking Fields, Lavaca County, Texas: ABSTRACT

ABSTRACT In 1972 regional computer-aided stratigraphic studies of 48 wells in a 185 sq mi area (479 sq km) resulted in the broad definition and ultimate drilling of the Mixon Creek prospect, leading to the discovery of Valentine field, Lavaca County. The Wilcox Group here is 4000 ft (1219 m) thick. Structural tops, interval sand counts, and isopachous data were measured in six deltas correlated on an electric log, jam correlation cross section network. Computer printouts showed the trends of successive delta fronts or barrier islands. In Valentine field a northeast-striking barrier bar depositional model was used to pick essentially offset-development locations in producing lower Wilcox Technik sand. However, subsurface data from 11 oil completions and five dry holes exposed two shale-filled erosional channels, one dip-and one strike-oriented, which are partly responsible for the stratigraphic accumulation. Menking field resulted from the accidental discovery of the oil in the Kubena sand, 100 ft (30.5 m) above the Technik sand, while drilling for the southwest projection of the Technik barrier across a tidal channel. Three oil wells and five dry holes there delineate a distributary channel sand truncated by erosion along the edge of a shale-filled channel. Reserves in Valentine field are estimated at 975,000 barrels of oil and in Menking field at 310,000 barrels.