Ram Powell 1998, Significant Challenges Met, Significant Challenges Ahead
Abstract:
Ram Powell is one of the major TLP developments in the eastern deepwater Gulf of Mexico. Discovery was in 1985 with first production in September 1997. Three main turbidite reservoirs are currently under development, the J, L, and N Sands.
The J Sand, an unconfined fan-lobe sheet-like turbidite, is an oil-rimmed gas reservoir. Current production is from two open-hole, gravel-packed, horizontal wells with horizontal reaches of 2328 and 2607 feet. One of these, Well A-3, claimed the GOM rate record of 41,000 BEPD. Analysis of pressure information suggests that the reservoir has proven connectivity of at least 8000 feet with predicted connectivity being much larger. The key success in the J Sand is the exceptional production rates. The key challenges for the future are total reservoir connectivity and timing of water influx, given an unknown aquifer strength.
The L Sand is a laminated levee oil-rimmed gas reservoir. Average lamination thickness is slightly less than one inch, and core plug permeabilities range from 10 md to 1000 md. The L Sand is being produced by a Well A-1, a single open-hole, gravel-packed, horizontal well with a 2255-foot reach and peak production rates over 100,000,000 CF and 9,000 BC per day. Pressure information suggests that the well is draining as many as 4000 acres and that connected volume has been increasing as a function of time and production. This increase has been attributed to breaking down of intra-reservoir barriers which manifests itself as small pressure increases of four to seven psi, followed by a slight flattening in the pressure decline profile. The main successes for the L Sand lie in the apparent reservoir connectivity and production rates obtained from laminated pay zones. The main risk is breakdown of the apparent barrier between the laminated hydrocarbon-filled reservoir and the adjacent water-filled channel sand.
The N Sand is an amalgamated channel oil reservoir which has been difficult to develop. Unexpected and unexplained intra-reservoir water levels have been penetrated and others may exist. Connectivity is unknown, and unexplainable reservoir pressure data exists. Seismic data has not fully identified reservoir barriers or adequately predicted water-filled sands. The reservoir is currently being produced by two wells, the A-2ST2 and the A-5ST2. The A-2ST2 is a high-angle cased-hole, gravel-packed, conventional well that has peak rates as high as 22,000 BOPD. Pressure information suggests a large, connected, in-place volume of 30 million barrels oil. However, due to low reservoir energy, the reservoir is below the bubble point and water injection is required for adequate recovery. Injector placement is quite a challenge in view of the poor seismic resolution and unknown reservoir barriers. The second N-Sand well is A-5ST2, an open-hole, gravel-packed, horizontal producer 2380-foot reach that has just been completed. Based on initial pressure information, it appears to be in communication with the A-2ST2 well, which further substantiates the need for water injection. Poor seismic resolution has hindered the mapping of reservoir barriers. With unknown reservoir connectivity, injector placement is a significant challenge.
Overall, the Ram Powell development has been a technical and an economic success. From the perspective of well design and well placement, significant challenges have been met in obtaining high production rates. Large drainage areas in the J and L Sands have been confirmed. The remaining challenge lies in planning the development of the N-Sand reservoir.
Biographical Sketch:
Ken Bramlett was the Shell Deepwater project geologist for the Ram Powell project from 1994 to 1998. His efforts focused on reservoir characterization and development planning. Currently he is assigned to the Turbidite Systems Group where he attempts to provide solutions to issues related to turbidite reservoirs. Since joining Shell in 1980, he held various technical and managerial positions in the Rocky Mountains, Permian Basin, and the Gulf of Mexico. He holds a B.S. in geology from Clemson University, an M.S. in geology from the University of South Carolina, and a Master of Divinity from the New Orleans Baptist Theological Seminary.
Petroleum Systems of the Coastal Kwanza and Benguela Basins, Angola (*)
Exhibitors:
Sonangol; TDI
Brooks/Geomark Poster Exhibit: Geochemical Exploration Surveys in Deepwater Angola
Western Geophysical Exhibit: Seismic Lines in the Benguela Basin, Angola
Poster Sessions:
Lower Cretaceous Stratigraphy and Source Rock Distribution in Pre
Salt Basins of the South Atlantic: Comparison of Angola and Southern Brazil by
M.A. Pasley (Kerr McGee), E.N. Wilson (Amoco), V.S. Abreu (Unocal), M.G.P.
Brandao (Sonangol) and A.S. Telles (Petrobras)
Petroleum Geology of Block 2, Offshore Congo Basin, Angola by Tako Koning,
Texaco Angola Inc., & Odette De Deus, Sonangol, Luanda, Angola
Parametric Paleoclimate Simulations of Depositional Environments with an
Emphasis on Source Rocks and Reservoirs by Malcolm I. Ross, Director,
PALEOMAP Foundation.
*Original paper presented at the Hedberg AAPG/ABGP Joint Research Symposium
"Petroleum Systems of the South Atlantic Margin" November 16
19, 1997, Rio de Janeiro, Brazil.
Al Danforth, Texaco Inc., Bellaire, Texas, USA
Tako Koning, Texaco Angola Inc., Luanda, Angola
Odette de Deus, Sonangol, Luanda, Angola
Abstract:
The Kwanza and Benguela basins of coastal and offshore central Angola (Figure 1) are under explored but have significant exploration potential. The basins are part of the greater Aptian salt basin of West Africa and Brazil that formed during the opening of the South Atlantic. Recent discoveries in deepwater blocks awarded in the early 1990s in the Congo basin, offshore northern Angola, have generated a lot of industry interest. New blocks recently awarded in the Kwanza and Benguela basins will be the next frontier to be drilled. Our paper focuses on the regional geologic framework in this exciting area.
The Benguela Basin is undrilled, but oil accumulations are known in the Kwanza Basin in Albian carbonates (Catumbela Fm.), Tertiary sandstones and the pre salt Cuvo Fm. Based on analyses of oils from seeps, and petroleum and bitumen extracts from outcrops and wells, there are at least two source rock intervals generating oil in the basins. One is an anoxic lacustrine sequence in the pre salt section, similar to the Bucomazi source rocks of Cabinda, and the second is a marine carbonate inferred to be the basin facies of Albian shelf carbonates (downdip equivalent of the Tuenza Fm. of the Kwanza basin or Pinda of the Lower Congo Basin). Both units are penetrated by wells in Block 9 in the southern, offshore Kwanza Basin. Basin micrites of Albian age also occurred in DSDP site 364 at the seaward margin of the Benguela Basin, where the source richness was much greater than that observed in the wells. Analysis of biomarker data from site 364 helped constrain the interpretation of the origin of oils found in offshore seeps and wells.
Both basins were affected by pronounced uplift of the continental margin in the Neogene. Uplift and seaward tilting amplified deformation of the salt beyond that observed throughout the Aptian salt basin of West Africa. Depositional loading by clastics shed from the raised areas enhanced rafting of slabs of the post salt section downdip along the base of salt decollement, creating salt ridges, diapirs, and allochthonous sheets in offshore areas. In the southern Kwanza Basin, deformation was further modified by buttressing of the mobile salt against a volcanic chain. The chain of seamounts, presumed to be of early to mid Cretaceous age, separates the Kwanza and Benguela basins. Elsewhere, the pattern of salt ridges and diapirs proceeds seaward to where salt nappes appear to have overridden the abyssal plain and presumed oceanic crust of the South Atlantic.
Considering Tertiary isopachs, sediment rafts that moved progressively seaward on the salt decollement controlled the distribution of sediment. Grabens formed at the updip margin of each raft captured thick sections of clastics in which sandstones and shales as young as Miocene rest directly on presalt sediments. Lateral boundaries between sediment rafts, where extensional, may have provided avenues for basinward transport of sands, allowing bypass of parts of the shelf and upper slope. Other boundaries between rafts had local strike slip movement, as demonstrated by compressional or transpressional features where adjacent rafts moved at different times or rates. An asphalt impregnated, overturned fold at Cabo Ledo, along the shoreline in the Kwanza Basin, is interpreted to have formed in this manner rather than along a transform fault associated with sea floor spreading, as has been previously proposed. Orientation of the lateral boundaries between salt rafts (same direction as the dip of the base of salt decollement) is similar to the orientation of the seafloor transforms, or perpendicular to the continental margin at the time of spreading. Rafting of the post salt section has transported large volumes of shelf sediments as much as 20 kilometers basinward. Restoration of rafted terrain facilitates paleogeographic mapping of the Albian carbonate facies.
Salt tectonics also affected patterns of petroleum migration. Much of the salt is concentrated into ridges, diapirs or allochthonous bodies, with the remainder being isolated salt prisms trapped as the salt sheet evacuated the area in its basinward movement. In areas of greatest sediment loading, salt welds allowed oil from pre salt sources to move into younger reservoirs. Numerous seafloor oil seeps occur in downdip areas of the southern Kwanza Basin, where salt diapirs are abundant. Vertical movement of the salt, which has carried rocks as old as Campanian up to the sea floor, also provided conduits for oil migration.
Tertiary sandstone petrology in the offshore Kwanza and Benguela basins is expected to be different, since the provenance of the sands is different. In the Kwanza Basin, as much as two kilometers of uplifted Cretaceous and Paleogene sediments were removed during the Neogene from the onshore and redeposited in deepwater offshore. In the Benguela Basin, adjacent basement areas were uplifted as much as three kilometers, creating a steep gradient that facilitated delivery of first cycle siliciclastics from a mixed granite and metamorphic terrain into the deep basin during the Neogene.
A volcanic chain separating the two basins offshore extends onshore as a series of syenite and carbonatite intrusives. Basalts and minor rhyolites occur where the chain crosses the boundary fault at the edge of the basement outcrop. Locally, a basalt (basanite) dated as Cenomanian fills in karstified Albian carbonates, implying local post Albian, pre Cenomanian doming associated with one of the volcanic centers. Volcanics have been observed onshore and in southern Block 9 offshore, however the linear extent of a chain of seamounts trending WNW for a great distance offshore was only recently recognized through the use of satellite altimetry derived gravity data. The age of volcanic activity is not well documented.
Streams discharging from the volcanic area should have deposited a mixture of volcanic and intrusive igneous debris locally in the northern part of the Benguela Basin. The influence of the Tertiary sandstones on reservoir quality is thought to be localized, since volcanic lithologies or problematic mineralogy are not seen in either DSDP site 364, 50 kilometers south of the chain or in the Tertiary section penetrated by the Mucua # 1 well, 40 kilometers north of the chain.
The structural history of the area has generated many styles of traps, most of which are undrilled. Objectives range from presalt to Albian shelf carbonates to Tertiary deepwater fans. Numerous traps with anomalous seismic amplitudes in the Tertiary occur on anticlines and on the flanks of salt structures. Pre salt sources have been in the oil window since the early Tertiary. Post salt sources are modeled to have locally generated and expelled petroleum coincident with late Tertiary sediment loading.
The principal exploration risks in the deepwater areas of the Kwanza and Benguela basins are petroleum charge and reservoir quality. The efficiency of charging the traps with commercial volumes of oil is uncertain. It is also difficult to predict if the Tertiary sandstones will ultimately yield reserves and flow rates that can support commercial levels of production. Drilling that will follow the current leasing activity in the area should resolve these questions.
Biographical Sketch
Al Danforth is a senior explorationist at Texaco's international exploration department, in Bellaire, Texas. His 26 year career in the oil business includes experience in the regional geology in many of the major frontiers and producing basins of the world in the course of pathfinding, new venture evaluation and acquisition for Texaco, Chevron and their affiliate, Amoseas Indonesia.
his article was prepared and presented jointly by Texaco and Sonangol for the Hedberg Research Symposium on "Petroleum Systems of the South Atlantic" jointly sponsored by AAPG and ABGP in Rio de Janeiro, November 1997. The author especially expresses his thanks to Sonangol for granting permission to present the results of this work to the Houston Geological Society.
"The Psychology of Indoor Air Quality" - History of Air quality study and a discussion of what we know.
Abstract:
The types of problems seen in indoor environmental quality investigations today are not new. Similar complaints have been reported in the past. The investigatory process usually involves many factors such as air quality measurements to diagnose the cause of the IAQ (Indoor Air Quality) complaint. We have found that the complaints are caused by many factors including psychological. In the lecture, we will discuss the history and evolution of IAQ complaints from tarantism through mass hysteria and relate diagnoses to various strategies.
Biographical Sketch
Mr. Smahlik is a Certified Industrial Hygienist for 3D/ International. He has his B.S. and M.S. degrees in Industrial Hygiene from Texas A&M and has been consulting in the environmental field for over twenty years. With over thirty publications and presentations, he is an expert in the fields of fire safety, indoor air quality and airborne contaminants.
The Outboard Trend of the Cotton Valley Limestone Pinnacle Reef Play, East Texas Basin
Abstract:
The Upper Jurassic Cotton Valley Limestone Pinnacle Reef trend has been a rapidly expanding gas exploration play in the East Texas Basin since the 1993 Marathon #1 Poth discovery in Leon County, Texas. Although the play has been expanding in all directions, the majority of exploration activity has been in a fairway along the western margin of the East Texas Basin in Freestone, Limestone, Leon, and Robertson Counties. Amoco and its partners, Spirit 76 and Kaiser Francis, are exploring a new Cotton Valley Limestone Pinnacle Reef Outboard Trend, which is located down dip of the established production fairway. New data collected from the Amoco #1 J.W. Vanderbeek discovery and other recently drilled wells confirm that porous, productive, deep and shallow water, carbonate buildup facies are present in the Outboard Trend.
As interpreted from 3D seismic data, the Outboard Trend carbonate buildups typically form isolated paleogeographic highs along an outer distally steepened ramp and ramp margin. Overall, the buildups are aggradational, and internal buildup seismic reflectors show stacking with minor progradational and retrogradational offstepping. Each depositional package is usually characterized by an initial transgressive sequence, followed by a shallowing upward sequence. Most of the Outboard Trend is capped by a gradual drowning sequence in which upper Cotton Valley massive mudstone wackestones grade upward through transitional marly limestone into Bossier Shale or occasionally change abruptly and directly into Bossier Shale.
Many Outboard Trend buildups are cored by micrite rich sponge microbial mounds that are thought to have been initiated during transgressive events at relatively deep water subphotic depths. Commonly associated biota consist of bryozoans, serpulid worm tubes, echinoderm ossicles, and tiny thin walled pelecypods. Mudmound flank beds contain mound lithoclasts and biota that sometimes occur in debris flow beds, and adjacent intermound areas consist mainly of dark gray lime mudstone and fine grained wackestone. As the mounds grew upward into the photic zone, coral sponge microbial boundstones developed, with small branching corals often being the dominant component, and sparse chaetetid sclerosponges and possibly solenoporid red algae. Cement filled skeletal molds and shelter cavities are common in this phase of the buildups. The associated biota is similar, but with the addition of larger thick walled pelecypods, occasional small gastropods, and rare tiny dasycladacean algae. Flank and inter-reef limestones at this paleobathymetric level are typically outer shelf skeletal wackestones and packstones dominated by mollusc debris, and with rare nodosariid foraminifera. The shallowest water facies in the trend consist of peloidal skeletal to skeletal packstone and grainstone, sometimes with sparse ooids, which indicate periods of above wavebase, moderate to high energy depositional conditions.
Four general limestone facies are predominant in the Cotton Valley Limestone Outboard Trend:
An additional reservoir facies type recently discovered in the Amoco #1 J.W. Vanderbeek well consists of skeletal grainstone containing coarse grained, well abraded, and partially micritized corals, red algae and molluscs deposited in a high energy, shallow water shoal. Porosity ranges between 6 and 22 %, and consists of large, cement reduced intergranular, intragranular and skelmoldic macropores, along with micropores found within the micritized portions of skeletal grains. Microporosity ranges between 65 and 80 % of the pore system, and is the result of intense meteoric dissolution. Marine, meteoric, and deep burial cements are minor, and no evidence of deep burial dissolution or fracturing exists in this reservoir facies type.
Further work that will provide greater exploration predictability is in progress on the stratigraphic/biostratigraphic and diagenetic features of the Outboard Trend.
Norpblet Geology and 3-D Geophysics of Fairway Field, Mobile Bay, Alabama
Abstract:
The Upper Jurassic Norphlet system in the Mobile Bay area has been the subject of considerable exploration intrigue during the last 20 years. Fairway Field, which came on production in December 1991, lies in the restricted access area of the main Mobile Bay shipping fairway leading to the city of Mobile, Alabama and is comprised of state blocks 113 and 132.
The exploration and exploitation of the area south of Dauphin Island has been based primarily on the geophysical evaluation of a high quality 3-D seismic survey shot by an industry consortium in 1986 to image the eolian Norphlet unit at depths between 21,000 ft. and 22,000 ft. An analog bay cable coupled with a 1920 cubic inch sleeve-gun array was used to record a total of 7000 line miles over an area of about 250 sq. miles. Approximately 253,000 trace bins of 60 fold data in a 164 ft. by 164 ft. configuration were recorded over all or parts of 49 state and federal offshore blocks.
The enhancement to the geometric resolution of the lenticular Norphlet dune trends in this area with 3-D imaging is significantly better than with 2-D data. This imaging has led to a much better regional understanding of the Norphlet and consequently a much improved interpretation of the Shell/Amoco Fairway field. The Norphlet isopach has been mapped with confidence in areas where the lenses are thick. This has led to the interpretation of a series of northwest-southeast trending longitudinal (linear) dune forms across the survey area. Post 3-D exploration methodology has targeted these thick, paleogeomorphic features where they have been enhanced by subjacent salt structure.
Fortunately Fairway Field has performed volumetrically. Reservoir decline has averaged about 9% per year starting from an initial production rate of about 200 mmcf per day. However, some of the wells have begun to demonstrate production characteristics which may be associated with dune sand heterogeneity and/or water coning. The ultimate recoverability for Fairway Field is projected to be between 50 and 60 percent with low abandonment pressures due to the uniformity and high mechanical strength of the dune marix.
Biographical Sketch
Chip Story holds a B.S. degree in geological engineering from the South Dakota School of Mines and an M.S. degree in geophysics from the Colorado School of Mines. His career began with Amoco in 1977 with the early efforts in the Wyoming Thrust Belt. Subsequent projects included work in the Paradox Basin and Williston Basin. Project assignments starting in 1983 involved the Gulf of Mexico, the onshore and offshore Norphlet Trend, the Tuscaloosa Trend, the Hackberry Trend, and the Santos Basin offshore Brazil. Chip is currently assigned to the International Energy Organization in Amoco's Houston office where he is working the Liuhua Field in the South China Sea. His professional interests involve 3-D seismic interpretation, visualization, and reservoir characterization technology.