E&P (exploration and production) activities in deep water (area with water depth more than 500m, today) have expanded greatly during the past 20 years, along with the innovation of offshore technology for drilling, development, and production. Water depth in exploration and production drillings reaches around 3,000m and 2,300m, respectively, and many fields in deep water have been discovered and developed in the Gulf of Mexico, Offshore Brazil, Offshore West Africa, etc. Today more extensive E&P activities in deep water are recognized throughout the world and exploration in deep water has become a valuable choice of the exploration strategy for oil companies. Reviewing previous works in deep water, two geological settings have highly contributed to hydrocarbon occurrence. One is deposition of sandstone in deep-water systems such as turbidite with high porosity and high permeability as reservoir. Nearly 90% of discovered reserves so far in deep water fields are from turbidite sandstones. The other is movement of mobile strata such as salt and over-pressured shale. These mobile strata have contributed to formation of traps and also have induced faults, through which hydrocarbon migrated from source to reservoir. Also deep-water projects are characterized by following aspects ; (1) Application of modern seismic technology such as Seismic Imaging and Direct Hydrocarbon Indicator (DHI), has increased geological and economical success ratio. (2) Productivity of reservoir is critical factor to justify huge investments, and a final decision for the investments is easier and faster for reservoirs with higher flow rate and higher ultimate recovery. Exploration potential in deep water is still high, and further E&P activities will be continued. For the success in deep water, synthetic study carried by integrated teams with geologist, geophysicist, and specialized offshore engineers (reservoir, drilling, production and facility) is essential.
Offshore oil and gas development activities began after World War II. For several decades jacket type production systems were widely used for shallow water oil and gas projects. In 1970s floating type systems (semi-sub and FPSO) appeared in deeper waters where the fixed type could not be technically or economically installed. The deepwater age began in the 1990s when technical break-throughs were realized in the floater design, mooring design, large crane barge capacity and subsea completion technology as their engineering and analytical capabilities had advanced. At present, those technologies enable us to drill in water depth of more than 3,000m and to produce hydrocarbons in water depth of 2,300m. We may envisage soon that crude will be recovered from under 3,000m water depths if high oil prices continue, especially in the Gulf of Mexico and/or offshore Brazil where advanced offshore technology has been created by industry. There are still some hurdles to overcome, such as floater capability expansion, subsea boosting and processing reliability enhancement, flow assurance and remotely operated vehicle (ROV) technology.
The term “turbidity current” was firstly proposed for the unknown subaqueous density current, weighted with sediments in water, which is proposed to explain the origin of submarine canyons (Daly, 1936 ; Johnson, 1938, 1939a, b). It was secondly introduced as the transportation medium of graded bedding on land and deep-sea sand in ocean (Kuenen and Migliorini, 1950 ; Natland and Kuenen, 1951). The term “turbidite” was coined to designate all deposits of turbidity current (Kuenen, 1957). After that, some researchers insisted on defining that “turbidity current” is nearly or completely restricted to the turbulence current where sediment particles are supported only by fluid turbulence, and “turbidite” is limited to the deposits of “turbulence current” (Sanders, 1965 ; Middleton and Hampton, 1973, 1976 ; Shanmugam, 1996, 1997, 2000 ; Mulder and Alexander, 2001 ; Gani, 2004). However, based on the historical facts, it is obvious that “turbidity current” was named to an unknown density current which is expected to exist actually in nature, therefore, it is very natural and reasonable to image that the supporting mechanism of sedimentary grains in “turbidity current”, the unknown gravity current in nature, is not restricted to a specific mechanism such as fluid turbulence, but includes various kinds of mechanisms (Kuenen in Sanders, 1965 ; Mutti et al., 1999 ; Kneller and Beckee, 2000). Therefore, the recent definition or discussion that “turbidity current” is equal or nearly equal to “turbulence current” makes the fundamental mistakes and causes the endless confusions. To avoid the confusion, the author proposed to redefine these terms in a broad sense according to the historical facts, and stressed the importance of objective description of the deposits apart from the interpretation such as supporting mechanisms or fluid rheology.
The Campos Basin, offshore Brazil, is a typical passive margin basin in the western South Atlantic, and the most prolific basin with about forty producing fields including deep-water giant fields. The Campos Basin is currently responsible for more than 80% of Brazilian oil production. The hydrocarbon accumulations are distributed throughout the stratigraphic column of the basin from Neocomian to Miocene. The most important oil accumulations in the basin are associated with deep-water fans distributed in the stratigraphic column from Cenomanian to Miocene. Almost all the hydrocarbon accumulations discovered to date are sourced mainly from Barremian to early Aptian lacustrine shales of the Lagoa Feia Formation in the pre-salt sequence. The oil pooled in the post-salt sequence migrated through a system associated with pre-salt normal faults, “salt windows” in the Aptian evaporite, listric faults and regional unconformities. The play fairway map was made based on considering the basement and the salt development, the fault distributions and the kitchen area. This map presented that the Campos Basin was divided into five structural zones. These zones could be closely related to the hydrocarbon potential. It was evaluated that the eastern part of Zone I and Zone IIa along the present day shelf edge provided more favorable condition for the hydrocarbon accumulation than other zones. The oil of Marlim Sul field is trapped in the blanket turbidites that pinch out toward the northwest landward. The thick mud deposits derived from the muddy turbidites was considered to be the important factor for establishing the stratigraphic trap.
Deep water offshore West Africa is the most prolific petroleum exploration and production area in the last decade. “Golden Triangle” consists of US Gulf of Mexico, Brazil Campos and West Africa and is well known as three world class most prolific and promising deep water E&P areas. Especially, deep offshore Niger delta and Congo fan are the most prolific amongst them. 3D seismic data associated with advanced interpretation and visualization technique supported by recent powerful computer capability as well as sequence stratigraphy concept have contributed very efficiently to deep water success in West Africa. An approach utilizing seismic multi-attribute is the essential element for reservoir delineation and risk minimization because turbidite sand is significantly heterogeneous and thus development well spacing/positioning should be optimized by integrated reservoir study. A seismic-well log study example in deep water offshore Gabon is briefly introduced in this paper.
This study discusses a burial history and diagenesis of the Jurassic sandstone reservoir that was deposited in a coastal to shallow-water environment and buried deeply in the recent deep water area. The study example is the sandstone reservoir of the Plover Formation in the Abadi gas-field in the West Arafura Sea, Indonesia. The results of this study are summarized as follows : (1) The Plover Formation is of the Middle Jurassic (partly the lower-most Upper Jurassic), based mainly on Dinoflagellata chrono-biostratigraphy. The Plover Formation is subdivided into the upper unit and the lower one by the Bathonian muddy layer (MFS). The sandstone of the upper unit is the main reservoir in the Abadi gas-field. (2) The burial history of the Plover Formation has two remarkable, rapid deepening events in the Late Cretaceous (deposition of a thick, muddy deltaic succession) and the Pleistocene (deepening of the Timor Trough). (3) The diagenetic processes are represented by (a) shallow burial stage : siderite- or kaolinite-precipitation, (b) shallow-to-intermediate burial stage : replacement of detrital feldspars by kaolinite, (c) intermediate burial stage : quartz-overgrowths or Fe-calcite, (d) compaction associated with increase of overburden and cementation, and (e) hydrocarbon-charge to the gas-field and its related formation-fluid movement that controlled the diagenetic processes. The texture of the sandstone and the process of its compaction are affected by the precipitation and dissolution of these cements and by the condition of grain contact. The rapid subsidence is a probable cause of formation of microstylolites in the sandstone. (4) Three types of pores are observed in the sandstone reservoir ; such as intergranular pores, micro-pores, and dissolution-pores. Diversity of sedimentary and diagenetic facies controls the difference in relative abundance of the three types of pores in the sandstone. It is also a controlling factor for the diversity of diagenetic facies whether the sandstone is hydrocarbon-bearing or not.
METI “Sado Nanseioki” wells were drilled in the deep water southwest offshore of the Sado Island in the Japan Sea to explore the Awabi Structure after the MITI “Sadooki Nansei” seismic survey. Along with the presence of Direct Hydrocarbon Indicators around the crest of the structure, methane hydrate and oil seepage were recovered during the site survey prior to the drilling, which indicate an existence of the active petroleum system. METI “Sado Nanseioki” wells proved a distribution of the thick Neogene sediments in the deep water and discovered a 15 meter-thick oil column in the lower part of the Shiiya Formation. Detailed paleontological, geochemical and fluid inclusion analyses were carried out, and resulted in a reliable correlation to the Niigata standard stratigraphy and understanding of hydrocarbon history of the structure. A severe truncation surface revealed by the seismic survey was identified within the upper part of the Lower Teradomari Formation at about 8.5 Ma. Structural configuration of the Awabi Structure varies greatly between above and below the truncation surface. Above it, the structure is an asymmetrical anticlinal structure accompanied by a reverse fault on the western flank. Below it, the structure is an N-S trending nose structure. Structural growth commenced in the southern part during the time of the Shiiya Formation, and culminated after 1.3 Ma with growth center shifting north- and northeast-ward. A close genetic relationship was proved between oil, hydrocarbon shows, methane hydrate and oil seepage at sea bottom. Hydrocarbon generation in the Lower Teradomari or Nanatani Formation, temporal trap in the Lower Teradomari Formation, migration into the Shiiya Formation and leakage to the sea bottom through many small normal faults at the crest was clearly interpreted. The MITI seismic survey and the METI wells provided important insight about the petroleum system of the deep-water part of the Japan Sea.
Hydrocarbon migration modeling through heterogeneous turbidite successions was carried out in the Iwafuneoki field, offshore Japan. The model, which uses 3D seismic data as an indicator of rock properties and employs the invasion percolation for simulation algorithm, enabled us to trace complicated migration pathways controlled by sand distribution patterns, sealing capacity of shale and hydrocarbon phase in pore spaces. It successfully predicted possible hydrocarbon distributions deductively, as well as reproducing known accumulations in much greater detail than conventional models do. It can therefore provide another practical measure to quantify the exploration risk of prospective locations, in addition to other inductive approaches like seismic attribute analyses.
Sadewa Gas Field, a deep-water field discovered in 2002 in East Kalimantan, is located on the current continental slope at water depths ranging from 1,000 to 2,800 ft, offshore Mahakam delta, north Kutei Basin. The Mahakam delta, initially developed in the Early Miocene, contains several giant oil and gas fields. Reservoirs of such fields were deposited in shallow-water, deltaic environments on the shelf. Sadewa, on the other hand, was located on the slope that linked shelf-edge deltas to the deep-water sediments on the basin floor during the Middle and Late Miocene. It is interpreted that small-scale deltas developed along the shelf edge during lowstands (lowstand deltas), fed slope channels and then the basin floor with the coarse sediments. Cores of the Sadewa reservoir rocks exhibit episodic turbiditic deposition of reworked delta sediments. Slope channel sandstone reservoirs of Sadewa field were detected as high-amplitude anomalies in 3D seismic data. Channel-like features on seismic amplitude maps were selected as exploratory drilling targets. The subsequent drilling of 8 exploratory wells resulted in encountering sandstone reservoirs as predicted. The following procedures were carried out to model channel sand-bodies. First, the three-dimensional distribution of the sand-body of each channel (reservoir framework) was created in Petrel software based on the combination of seismic and well data. Second, this channel framework was filled with two facies, i.e. channel and levee/overbank facies, and with the petrophysical parameters unique to each horizon and facies. Lastly, gas-liquid contacts of proved, probable and possible ranges were input based on the well results. The reservoir model thus created was subjected to the reservoir simulation to estimate recoverable gas volumes. Although located in the deep water, by taking advantage of the vicinity to the shelf, Sadewa field will be developed by extended reach wells from the shelf edge in 285ft of water.
The use of new technologies and cost reductions in prospecting and engineering are indispensable for deep water exploration, development and production of oil and natural gas. The objective exploration areas in the deep water spread out from the continental slope to the ocean floor, known as the continental passive margin basin fronting major oceans. The reservoir rocks expected to be encountered in deep water exploration are turbidite sandstones. The source rocks in deep water areas are expected to be not only lucastrine shale, but also biosphere in the deep water environment. In addition, hydrocarbons of inorganic origin may also contribute to one of the sources to a certain extent. Presently, development and production up to depths of 2,000m and exploration of depths up to 3000m are being conducted. It is assumed that deep water exploration will continue to see a high level of activity, but the success of such exploration will depend on innovative exploration concepts and improvements in technology.
The previous three papers show we can derive a S-function as long as the complex velocity potential is provided and S-function gives us a good approximation of pressure drops and derivatives and it was extended to the problem with arbitrary boundary shapes. In this paper, we introduce new methodology (S-methods) for pressure analysis with arbitrary boundary shapes. S-methods include following two steps ; (1) Derive S-function by matching pressure data with radial composite model. (2) Select model structures which reproduce the S-function. Two examples for S-methods are presented. The first is the field example for “Channel and fun” system. The second is “multiple fracture case”.