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4. Reservoir bitumen precipitates in pore systems from the alteration of trapped or migrating oil in carbonate and siliciclastic reservoirs. Reservoir bitumen is not readily identified on typical log suites, where it is read as open porosity, which has hampered its broad recognition as a reservoir-altering cement. When present as a solid, it can be as influential on reservoir quality as carbonate, silica, or authigenic clay cements and should therefore be evaluated as part of the diagenetic evolution of any pore system whenever encountered.

Five morphotypes of reservoir bitumen have been identified and named: droplets, carpets, peanut brittle, vesicular, and digitate. Data from east Texas, Gulf Coast, and west African examples indicate that reservoir bitumen can significantly reduce total effective porosity. Permeability can be significantly reduced by restricted or closed pore throats and by fines migration, even when bitumen occurs in only moderate amounts. The occurrence and distribution of bitumen on well, field, and regional scales can range from uniform and predictable to irregular and unpredictable but mappable through examination of core and cuttings. Within a trap, bitumen can cause heterogeneity and form permeability barriers not related to depositional facies or pre-bitumen diagenesis and reservoir quality. Its economic importance must be recognized when reservoir parameters are adversely affected, impacting reserves calculations, recovery factors, and secondary recovery programs. On a regional scale, predictive models can be developed to determine the areas of a trend or portions of a stratigraphic section that are most likely to be affected, and these models can be incorporated with other data for evaluating expected reservoirs quality in regional play assessments.

Numerous synonyms commonly used in the oil industry for solid reservoir bitumen include solid hydrocarbon, pyrobitumen, dead oil, black sands, asphaltic sands, tar mats, and solid bitumen. The name reservoir bitumen (Rogers et al., 1974) is preferred since it is descriptive, without genetic connotation, and avoids confusion with source rock bitumen and kerogen. From a reservoir evaluation perspective, reservoir bitumen is a precipitate that can line and fill pore space. It is derived from petroleum through natural or artificial alteration processes occurring in reservoirs and/or migration carrier beds. It is by and large not producible, ranging from highly viscous to solid at reservoir conditions, extractable to insoluble under laboratory conditions, and often enriched in nitrogen, sulpfur, and oxygen.

5. The eastern part of the Kopet-Dagh basin of northeastern Iran contains over 4000 m of Upper Jurassic through Tertiary strata deposited in a variety of shallow-marine and terrestrial environments. Geohistory diagrams from well and outcrop data provide a useful mechanism with which to relate the stratigraphic framework of this part of the basin to the tectonic history of the region. During some episodes of regional tectonic uplift (e.g., episodes

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occurring 99-95 Ma, 74-70 Ma, and 63-54 Ma), sediment accommodation space continued to be created in the basin due to sediment loading and compaction of increased amounts of fine-grained sediments, in some cases concomitant with eustatic sea level rises. Much of the post-Jurassic subsidence in this part of the Kopet-Dagh basin was caused by sediment loading rather than tectonism.

The effects of basin geohistory on petroleum reservoir properties were studied using the Lower Cretaceous (Neocomian) Shurijeh Formation as an example. Detailed petrologic, sedimentologic, and geohistory analyses done on this formation show that the petroleum reservoir properties of Shurijeh sandstones Were affected by their depositional settings and the subsequent subsidence of these units through meteoric and compactional hydrogeologic regimes in this part of the Kopet-Dagh basin. These rocks consist mostly of sublitharenitic red beds deposited during a regressive phase of sedimentation dominated by rapid siliciclastic sediment supply. The lower and middle parts of the interval studied were deposited in low-sinuosity braided fluvial systems, and the upper part was deposited in high-sinuosity meandering systems. By relating the paragenetic sequence of the Shurijeh sandstones to the geohistory of this formation, we determined the timing of both porosity-destroying and porosity-enhancing diagenetic processes and related these processes to the timing of petroleum generation.

6. Stratigraphic analysis of sparse seismic data in 1981 indicated the presence of a lower Miocene carbonate platform complex over the western part of the Dongsha Massif, 220 km (137 mi) southeast of Hong Kong. Two bankedge trends were recognized, and a large structural closure within the carbonate platform was mapped along the axis of the uplift. The study also predicted the presence of a widespread, thick basal sandstone below the carbonate complex that could serve as a conduit for long distance migration of hydrocarbons into the closure. Although the prospect was a high risk' play in deep water 38 km (24 mi) south of the edge of a Paleogene basin with possible oil source rocks, it was intriguing because of its size and similarity to the giant Bombay High oil field offshore India.

After drilling by other companies demonstrated that oil had migrated well out of the source basin (Huizhou sag), Amoco negotiated for Contract Area 29/04 and was awarded the area in November 1985. The first Amoco well, LH 11-1-1A, tested 2240 bbl/day of 21° API oil from a 75-m (246-ft) pay section in a carbonate platform sequence topped at 1197 m (3927 ft). A 401-m (13l6-ft) lower carbonate section and a 149-m (489-ft) sandstone unit resting on basement were water bearing. Additional drilling has confirmed a giant in-place oil accumulation, but commerciality is yet to be determined. The carbonate complex includes a leached limestone platform facies with a reefal southwestern margin, and has excellent porosity and permeability. The oil is

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less waxy and heavier than other Huizhou sag-sourced oils because of biodegradation after migration.

In January 1987, Amoco Orient Petroleum Company tested 2240 BOPD in its first People's Republic of China well 220 km (137 mi) offshore Hong Kong in the Pearl River Mouth basin. The location of Contract Area 29/04 and the discovery well for a giant in-place oil accumulation are shown on Figures 1 and 2. Although smaller oil accumulations in the basin had tested higher flow rates, Amoco's LH 11-1-1A was the first discovery from a large carbonate complex. Discovery wells and field areas in the eastern part of the basin are shown on Figure 2.

7. Cathodoluminescence reveals two kinds of dolomite in the upper Arbuckle Group at Saddle Mountain. Most dolomite is nonluminescent to dully luminescent, whereas some is brightly luminescent. Although both kinds of dolomite occur as massive replacement of former limestone beds, brightly luminescent dolomite also occurs as pore-filling cements within and overgrowths on nonluminescent to dully luminescent dolomite (Figure 5). This paragenetic relationship, also documented by Donovan and Ross (1991b) and R. D. Elmore (1990, personal communication), clearly indicates that brightly luminescent dolomite formed later than nonluminescent to dully luminescent dolomite.

Most nonluminescent to dully luminescent (early) dolomite displays medium to coarsely crystalline (0.06-1.0 mm), subhedral to anhedral textures, but finely crystalline (0.02-0.06 mm), euhedral to subhedral textures are also present. Many dolomite crystals exhibit intercrystalline pressure-solution features, and stylolites have been observed in thin sections. Nonluminescent to dully luminescent dolomite crystals are clear to cloudy under transmitted light. Patchy, and pore-filling and fracture-filling saddle dolomite is also nonluminescent to dully luminescent, and is intimately associated with finer grained nonluminescent to dully luminescent (early) dolomite.

Most brightly luminescent (late) dolomite has finely to medium crystalline, euhedral to subhedral textures, although coarsely crystalline, subhedral to anhedral textures also occur. Intercrystalline pressure solution was not observed between crystals of brightly luminescent dolomite. Under transmitted light, brightly luminescent dolomite is commonly cloudy. This is caused by abundant organic and fluid inclusions, which, unfortunately, are not large enough for fluid-inclusion analysis. Some inclusions fluoresce under ultraviolet light, indicating the presence of hydrocarbons (also documented by R. D. Elmore, 1990. personal communication).

The two distinct kinds of dolomite defined by luminescence display different fabrics under scanning electron microscopy when etched in the same dilute (0.6N) HC1 for the same time period. Nonluminescent to dully

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luminescent dolomite exhibits only slight dissolution, whereas brightly luminescent dolomite is relatively more soluble, resulting in a spongy fabric (Gao, 1990b).

8. Sequence stratigraphic concepts suggest that stratal geometries develop and are largely controlled by changes in relative sea level. On the shelf, lowstand deposits, which form during falls and subsequent stillstands of relative sea level, can be recognized by the presence of an unconformity at the base, the isolated and basinward position relative to the previous shoreline, and the abrupt seaward translation of shallow-water and shoreline facies into the basin across an unconformity surface. This seaward translation of facies and shoreline regression in response to relative sea level lowering is termed a "forced regression."

A forced regression is independent of variations of sediment flux and is in contrast -with "normal" regressions that occur in response to excess sediment flux relative to space available on the shelf (i.e., accommodation). Forced regressions commonly are associated with a zone of sedimentary bypass, subaerial exposure, and possible fluvial erosion between the newly formed and preceding shorelines. Certain shelf sands, previously interpreted as offshore or mid-shelf sand bodies, thus can be reinterpreted as stranded lowstand shorelines associated with forced regressions. This alternative interpretation has economic significance insofar as it suggests different subsurface correlations and reservoir geometries with the potential for development of new play types and enhanced recovery in older fields.

Examples of forced regression can be observed at a variety of scales and ages. Several such examples include the modern East Coulee fan delta and the Lower Cretaceous Viking Formation in Alberta, Canada, the Quaternary Rhone Delta, and the Quaternary Hudson Valley system.

For many years, geologists have routinely recognized and interpreted transgressive-regressive cycles in the sedimentary record. In a classic paper, Curray (1964) demonstrated the interplay between sedimentation rate and change in relative sea level as the most important controls causing a coast to become either transgressive or regressive. With recent advances in the development of sequence strati-graphic concepts (Posamentier et al., 1988), we believe it timely to reexamine the architecture of transgressions and regressions and assess them within a chronostratigraphic context. A transgression, or landward migration of a shoreline, is controlled largely by net sediment flux (either positive or negative) and by a relative sea level rise. A regression, or basinward migration of a shoreline, occurs on coasts where sediment supply exceeds new space added (accommodation), and on shorelines experiencing a drop in relative sea level.

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InterOil Corp. has discovered a new oil system in the eastern Papuan basin in Papua New Guinea (PNG). With a good quality reservoir sand and two sources of oil, the eastern Papuan basin is now proven to be prospective for oil, with the potential for world class oilfields comparable to Kutubu field (more than 300 million bbl) that has been producing since1992.

InterOil has been awarded a new license (PPL 230) that includes all the indentified Pale sandstone prospects and plans to drill four wells in 2002 and eight in 2003 to test large structures. This new play will revitalize exploration in PNG, which has averaged only two exploration wells per year in recent years.

PNG approach.

InterOil is a Canadian entity developing a niche integrated energy company focused initially on PNG. The cornerstone is the construction of a 32,500 b/d refinery in Port Moresby, PNG, designed to run light sweet crude such as the PNG production sold at Kutubu. The refinery will primarily supply PNG domestic demand, with the economics based on both the refinery crack spread and the avoided transport costs of exporting oil and importing products.

InterOil has been exploring for oil in PNG since 1999. The key to the business plan has been to find a way to cost-effectively explore an underexplored frontier area. The implementation of the plan has seen InterOil obtain licenses over areas with good logistics and access to the refinery, and then find tangible evidence of a working petroleum system and identify 30 leads and prospects.

Since the discovery of oil in the Toro sandstone at Kutubu, exploration has concentrated on the Toro sandstone fairway in the fold belt and foreland in western PNG. Kutubu field will produce more than 300 million bbl, and Hides field contains more than 5 tcf. However, a combination of factors including high costs of drilling in the fold belt has reduced exploration to drilling commitment wells.

The eastern Papuan basin had been explored sporadically since 1911. Petro-Canada drilled the last well, Au Tabua, in 1991. The Pale sandstone had been identified as a possible reservoir, but with only a few outcrop samples, the provenance, extent, and reservoir quality were unknown.

When InterOil began to look for exploration opportunities in 1998, the eastern Papuan basin was open acreage except for a few blocks around the Puri -1 oil discovery. InterOil considered the area to be underexplored (as the few wells drilled had not penetrated below the Miocene Aure beds) but with petroleum potential due to numerous oil and gas seeps and the Puri-1 well that flowed 1,610 bo/d.

InterOil in 1999 obtained licenses PPL 208 and 210, stretching from the existing oil pipeline to the refinery at Port Moresby. To balance the exploration

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portfolio, InterOil sought and obtained low entry cost interests in other permits in PNG. InterOil has interests in PPL 199, PPL 200, PRL 4, and PRL 5. PPL 199 is a fold belt license operated by Oil Search Ltd. near the Paua -1 oil discovery and not far from the Bakari-1 well ExxonMobil was drilling in February 2002. PPL 200 is an offshore block operated by Talisman Energy Inc., and PRL 4 and PRL 5 are gas-condensate fields operated by Santos Ltd. with potential access to the refinery via the Fly River.

The initial phase of exploration involved finding, reviewing, reprocessing, and interpreting original data (including gravity and seismic). Together with extensive field work, this has established a portfolio of prospects. This initial work and reports of other Pale sandstone outcrops indicated the Pale could be a regional play extending into open acreage, and InterOil applied for additional license areas.

InterOil in January 2002 was awarded PPL 230, which supersedes or "top-files" PPL 208. PPL 230 covers 4 million acres and contains all the Pale sandstone prospects identified by InterOil and other play types including the carbonate reservoirs demonstrated by the Puri oil discovery. InterOil has become the largest net onshore acreage holder in PNG and operator with 100 % of PPL 230, PPL 220, and 210, which together extend from Port Moresby to the existing oil export pipeline.

Cost - effective progress

InterOil has a core team that works closely together, covering geology, geophysics, engineering, and commercial aspects. This removes any "functional silos" allowing the traditional exploration process to be questioned and innovative concepts to be thought through.

For example, continuous coring of shallow wells provides rock samples that can give direct evidence of porosity, permeability, and hydrocarbons without the cost of casing, logging, or well testing. Industry experience suggests continuous coring is the most cost - effective drilling system for depths to at least 6,000 ft and potentially to 10,000 ft.

By keeping the cost of a well below $ 1 million, the need to spend time and money on seismic (with a minimum program cost in the order of $ 2 million) prior to drilling is questionable, especially in an area where the key risk issues are reservoir and charge. While acknowledging wells have been drilled in the wrong places, all of the oil fields in PNG have been found without seismic. Seismic will have a role to play on exploration of deeper structures and in appraisal and development. The InterOil acreage does not have the karst limestone at surface that makes seismic difficult and expensive in the PNG fold belt.

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Another way to reduce costs is a multiwell drilling program to gain economies of scale. This requires a portfolio of relatively independent prospects, a low well cost (or a large budget), and a commitment to fully explore a number of higher ranked possibilities rather than a single "roll of the dice" on the best looking prospect. InterOil has identified and plans to drill a range of play types that includes:

•Pale sandstone (cored at Subu-1 and 2).

•Miocene and Eocene carbonates, that flowed 1,610 bo/d at Puri-1 and gas at Kuru and Bwata.

•Miocene reefs such as Pasca and Pandora -1 that flowed SO MMcfd.

•Miocene Chiria conglomeratesclastics that flowed gas at Oroi-1.

•Miocene Talama volcaniclastics that flowed 8,000 bo/d at Iokea-1.

•Pliocene sands that flowed gas at Tovala - 1.

InterOil was attracted to areas with logistical advantages of moderate terrain and barge access to infrastructure including the InterOil refinery being constructed in Port Moresby. This will allow early production, lower cost development, and access to a market for oil production. The InterOil coastal acreage has good road and/or river access, allowing lower operating and capital costs for exploration and development. For example, the economic field size for an oilfield near Port Moresby is estimated to be 10 million bbl, compared with 100 million bbl in the fold belt.

9) Технология бурения и освоения скважин

Field-scale simulation of horizontal wells

A technique for the efficient modeling of horizontal wells in reservoir simulation treats the horizontal well as a second "porosity" as in the dualporosity approach for naturally fractured reservoirs. The well "permeability" and "relative permeability" are adjusted to yield the pressure drop and phase slip predicted from multiphase flow correlations. Because the wellbore flow equations are cast into the same form as the reservoir flow equations, efficient techniques that have been developed for reservoir simulation can readily be applied.

Examples illustrating the application of this method are given for the prediction of the performance of a horizontal well in a reservoir where water and gas coning are important. A validation of the model is provided by comparing oil rates and cumulative oil produced with results obtained from a line source-sink representation of the wellbore and comparing pressure drop and slip with results from a two-phase flow correlation for a case where the wellbore pressure drop is relatively small.

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Recent interest in horizontal wells has been rapidly accelerating because of improved drilling technology, and the increased efficiency and economy of oil recovery operations. A recent report by Karisson and Bittot1 indicated that since the early 1980s, there have been more than 700 horizontal wells drilled with approximately 200 of those in 1988.

The improvement in recovery and economics obtained with a horizontal well results from the extensive contact with the reservoir. This results in lower fluid velocities around the wellbore, while providing total flow rates that are economic. Typical applications of a horizontal well include:

• Reservoirs where conventional wells have low productivity; the use of horizontal drilling can be viewed as a method for well stimulation.

•Reservoirs where recovery is limited by water coning or gas cusping. This occurs usually when a thin oil column is sandwiched between a gas cap and an aquifer. The use of horizontal wells in this case lowers the pressure gradient near the wellbore and therefore reduces the water coning and gas cusping tendencies while allowing an economical production rate.

•Reservoirs with vertical fractures. Horizontal drilling allows the intersection of many vertical fractures that form the main flow paths in the reservoir2.

•Heavy-oil and tar-sands reservoirs where steam-assisted gravity drainage (SAGD) is practical. The process consists of injecting steam into an upper well and using a lower horizontal well as a producer to collect the draining oil and condensate from the steam chamber.

Because the drilling costs of horizontal wells are 1.4 to 4 times more than those of vertical wells, it is imperative to conduct a reservoir engineering study of the recovery economics of horizontal wells before drilling. A reservoir simulator with horizontal-well capabilities can provide guidance into the design of well lengths, locations, optimal flow rates to prevent water coning or gas cusping and can predict the increase in recovery over that of conventional wells.

One approach to the development of horizontal well capabilities in a reservoir simulator is to solve simultaneously the equations of conservation of mass, momentum and energy in the horizontal wellbore together with the reservoir equations. This is needed when detailed flow in the wellbore and its vicinity is important for accurate predictions. Because of the comprehensive treatment of the wellbore, the computing cost of this approach is high and therefore may become prohibitive in large field-scale simulations. Furthermore, in large field-scale simulations, it may not be necessary to model the detailed flow phenomena in the horizontal wellbore. A good approximation of the pressure drop and saturation and composition distribution in the wellbore usually suffices.

This paper proposes an efficient technique for field-scale simulation of horizontal wells. The horizontal well is treated as a second porosity in the

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reservoir. The "porosity" of the wellbore gives the correct wellbore volume. The "permeability" and "relative permeability" of the wellbore are adjusted to yield the pressure drop and phase slip from multiphase flow correlations. Because the wellbore flow equations are cast into the same form as the reservoir flow equations, efficient numerical techniques that have been developed for reservoir simulation can be readily used. This dual-porosity representation of horizontal wells is developed for a black-oil simulator.

Simulation runs with the technique developed are carried out to study the effect of wellbore length and rate on the oil recovery in a thin reservoir under bottom-water drive.

Keywords: Horizontal well. Reservoir simulation, Pressure drop. Phase slip. Multi-phase flow.

Plant design allows drillers to reuse and recycle OBM (oil-based mud)

Oil-based mud plants, designed to treat used OBM from offshore rigs, will reduce the environmental impact by allowing drillers to reuse and recycle drilling fluids.

This conclusion of a two-part series provides specifications for an OBM facility and describes the chemical make up of OBM constituents.

The mud-handling facility is intended to receive, process, store and mix mud on a batch basis. More specifically, the plant will:

1.Receive and store used OBM transported by workboats

2.Remove solids from the used mud and provide storage for the solids and the liquid fractions

3.Mix new mud from diesel or low-toxicity oil, brine, and reclaimed mud and chemicals

4.Store diesel or low-toxicity oil, brine, and treated/reconditioned OBM.

Workboats transporting the used mud from the offshore drilling rigs will dock at the pier. Each workboat will then transport a load of about 2,000 bbl of used mud. The used mud will then be pumped from the workboats`s mud tanks to the used-mud receiving tank with the workboat`s pump.

The offloading pump capacity for a typical workboat is 350 gpm, or 500 bbl/hr. The used-mud storage tanks will have a capacity of 1,000 bbl, allowing for 30 min retention time. The used-mud receiving tank and its agitation equipment will be located close to dock edge.

This equipment is to be contained in a dike or walled area to prevent spillage in the marine environment. The used mud will then be pumped to the used-mud storage tanks. The used-mud storage tanks will be designed to store a minimum of the workboat shipment of 2,000 bbl.

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Comprehensive Simulation of Horizontal-Well Performance

Summary. The simulation of the performance of a horizontal well has generated certain new and important challenges. These include the partial penetration of the well in the horizontal direction within the allocated drainage area, the positioning of the well between the vertical boundaries, the distance from the parallel horizontal boundaries, and the permeability anisotropy. In addition, there are special problems in the simulation of the response of fractures (natural and induced) in regard to their contact with the well (longitudinal or transverse), their conductivity, and the conductivity distribution along the fracture.

Various works have shown that the PI ratio between a horizontal well and a vertical well (of a given length) is higher if the horizontal/vertical permeability anisotropy and the reservoir thickness are both small. The latter, of course, implies that a plausible thickness for the vertical-well completion be used for comparison.

Horizontal-well stimulation, both to remove near-wellbore damage (matrix stimulation) and to identify hydraulic fracturing, is an obvious new concern. Needless to say, it is inappropriate to compare the production of unstimulated horizontal wells with that of fully stimulated vertical wells.

Economides et al.16 proposed a method for the matrix stimulation of horizontal wells, and Renard and Dupuy17 studied the influence of formation damage on the flow of horizontal wells. Fracturing of horizontal wells, the resulting production behavior, and the comparison of fractured vertical and horizontal wells have received considerable attention. In fracturing horizontal wells, two production scenarios are interesting: either the well is drilled in the expected fracture direction so that it will accept a longitudinal fracture or it is drilled in the orthogonal direction. In the orthogonal case, multiple fractures can be executed with proper zonal isolation. The two scenarios are mutually exclusive, with the longitudinal fracture favoring horizontal wells that can accept low-conductivity fractures and the orthogonal configuration favoring reservoirs that can accept high-conductivity fractures. These are the cases for highand low-permeability reservoirs, respectively. While the above two configurations can be construed as ideal, if the entry point from the well into the formation is long, the fracture first will initiate longitudinally, regardless of the well direction in relation to the far-field stresses. The fracture will then turn normal to the minimum stress.

Horizontal-Well Simulation

We used a numerical reservoir simulator to examine the performance of a horizontal well. Important features of the simulator include a flexible grid