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Angola
Abstract Formation damage may be caused by in-situ emulsions, changes in wettability and by deposition of asphaltenes, wax and scales. It is widely recognized that these damage mechanisms may be removed by using microemulsion technology, resulting in enhanced productivity of oil and gas wells. It is also known that microemulsion systems are composed of surfactants, oil, brine and optional co-surfactants and acids. These systems can be very complex, due to the number of variables that influence formulation behavior, including temperature, type of oil, type and concentration of salt, surfactant, co-surfactant, and acid. The development of microemulsions for specific oilfield applications requires a systematic study of phase behavior as a tool to select a treatment composition that satisfies specific parameters defined by the application. Phase behavior studies are necessary in order to identify microemulsion phase boundaries. Phase behavior diagrams of microemulsion systems developed for wellbore damage remediation considered the following variables: temperature, type and concentration of co-surfactants, type and concentration of brine, oils, surfactants and acids. Laboratory studies of surfactant-oil-brine systems used successfully in the field confirm that they undergo phase transitions from Winsor I (oil-in-water with excess oil), to Winsor III (microemulsion), to Winsor II (water-in-oil with excess water). This paper presents formulations positioned in an area of the phase diagram that correspond to maximum detergency and optimum interfacial properties required for field applications. The relationship between phase diagrams, interfacial properties (interfacial tension and contact angle) and well productivity are discussed.
Abstract Prevention of inorganic scale damage in the formation around production wells is usually achieved by batch squeezing the productions wells at risk.However, in Western Siberia protection of production wells is sometimes achieved by application of scale inhibitors in the supporting water injection wells.This technique relies on the effective displacement of the inhibitor across the reservoir from injector to producer.This is not generally considered a viable scale management option due to the extent of chemical retardation that is a necessary result of inhibitor retention on the rock matrix.However, for short inter-well distances, such as may occur in onshore developments, and where fracture conductivity is high enough that inhibitor contact with the matrix rock is minimal, then this technique can provide adequate protection against scale induced formation damage in production wells. This paper explores the range of reservoir scenarios under which this technique may be applicable, considering inter-well distances, the extent of fracture vs matrix flow, and the potential range of inhibitor retention on various rock substrates that may be encountered in fractured reservoirs.The approach is to use numerical modelling techniques to investigate the range of conditions under which this scale management approach may be applicable.This data may then be used identify when scale control may be adequately achieved using this technique, thereby reducing the need to shut in production wells for treatments, and when this approach would not provide adequate protection in actual field systems.Comparison is made of the potential for performing batch treatments in the injections wells, compared to continuous injection of scale inhibitor in these wells. Introduction After a brief overview of the causes of oilfield scale and how it may be managed, this paper discusses the issue of where scale forms in the reservoir system, and the possibilities for treating injection water to protect production wells.Calculations are presented that illustrate when this may be an option, concentrating on dual porosity systems where natural fractures provide an effective conductivity between injectors and producers while minimising the surface area of rock that the injected chemicals will encounter on their journey as they are displaced from injection to production wells. Oilfield Scale Oilfield scales are inorganic crystalline deposits that form as a result of the precipitation of solids from brines present in the reservoir and production flow system.The precipitation of these solids occurs as the result of changes in the ionic composition, pH, pressure and temperature of the brine.There are three principal mechanisms by which scales form in both offshore and onshore oilfield systems:Decrease in pressure and/or increase in temperature of a brine, leading to a reduction in the solubility of the salt (most commonly these lead to precipitation of carbonate scales, such as CaCO[3]); Mixing of two incompatible brines (most commonly formation water rich in cations such as barium, calcium and/or strontium, mixing with sulphate rich seawater, leading to the precipitation of sulphate scales, such as BaSO[4]);Brine evaporation, resulting in the salt concentration increasing above the solubility limit and leading to salt precipitation (as may occur in HP/HT gas wells where a dry gas stream may mix with a low rate brine stream resulting in dehydration and most commonly the precipitation of NaCl).
- Europe (1.00)
- North America > United States > Texas (0.88)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract This paper highlights the concept of complex well through various advanced or emerging technologies involved during the well life process. The current state of the art states that drilling technology is more mature than production and treatment technologies. The well life process is divided into four phases : pre-project, conception, realisation and exploitation. Each phase is studied in terms of productivity on one side, cost on the other. New concepts such as limitation of well oversizing or anticipation of field maturity are regarded through actual examples. It is finally concluded that this technical revolution can only be a success if culture and human organisation evolve at the same rythm. Well being the most transverse object of the E&P chain, it represents a fantastic opportunity for all disciplines to work in close collaboration within integrated teams and not anymore through conventional isolated petroleum professions. Introduction It is recognised that during the last twenty years, well engineers have met a technological revolution. Remember the past! To properly develop an oil field, numerous vertical wells were required (Fig. 1) devoted either to exploration, appraisal or development. With proliferation of deviated and horizontal wells followed by the more recent breakthrough of multi-lateral and re-entry technologolies, the technical environment has completely changed. Today, extended reach wells are drilled with departures between 5 km and 10 km. Drilling off-shore reservoirs from on-shore facilities is now a reality. LWD (Logging While Drilling) allows a single horizontal drain to be drilled through several lenticular reservoirs. Other emerging technologies such as CTD (Coiled Tubing Drilling), TTD (Through Tubing Drilling), Casing Drilling or Expandable Tubulars will allow in a near future to put further and further the drilling limits. This technological revolution has been widely applied within the TotalFinaElf Group through several exceptional realisations (Fig. 2) among which three world records have to be mentioned : lateral D05 of the Dunbar field (North Sea), record in UDW on the Astrid field - 2800 m of water- (Gabon) and of course world record for an ERD with a departure of 10500 m (Terra del Fuego - Argentina). More globally, Girassol (Angola - 1400 m of water) and Elgin Franklin (UK - 1100 bar of vrigin pore pressure, 200°C) have been recognised by the oil profession as world first class achievements. The sharp upturn in the crude prices in 1973 was certainly a major driving force which has motivated operating and service companies to industrially launch the complex well concept. With a barrel above 10$, development of large off shore fields discovered in the North Sea and in the GOM a few years earlier became economically profitable providing reservoir being drained from a same "tie in point". This revolution was made possible thanks to three major and simultaneous technological breakthroughs : directional drilling, Measurement While Drilling and computer technology. What is a complex well ? A complex well has to be considered at two levels : its smart geometry (deviation, length, departure, 2D or 3D shape) on one hand, the complexity of the natural constraints (pressure, water thickness, depth, temperature, in-situ stresses, complex and heterogeneous geology, depleted reservoir) on the other. Referring once more to the various projects mentionned above, the CS1 world record can be considered as "complex" according to the length of the well but "easy" if regarding the natural constraints (normal pressure, shallow depth). By contrast, Girassol and Elgin Franklin are "complex" referring to the natural constraints (water depth, HP/HT conditions) but "easy" with respect to their well geometry. As pointed out in the diagram Departure/ Depth of Fig. 3 (ERD envelopes from the beginning of the nineties) the trend clearly shows that long departure (complexity according to geometry) does not accomodate with deep natural conditions (difficulty according to natural constraints).
- Europe > Netherlands (0.87)
- North America > United States > West Virginia > Kanawha County (0.34)
- Europe > United Kingdom > North Sea > Northern North Sea (0.34)
- Asia > Middle East > Qatar > Arabian Gulf (0.24)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/9b > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/8a > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/14a > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- (8 more...)
Abstract The Libwa 4 well offshore the Democratic Republic of Congo was stimulated in November 1999 using an enzyme-based process that generated acid in-situ. The results to date have been excellent. Well tests as high as 759 BOPD have been recorded after the treatment compared to less than 100 BOPD before the treatment. Introduction The Libwa field is located off the coast of the Democratic Republic of Congo (formerly Zaire) West Africa. The field was discovered in June 1981 and declared commercial in 1983. Development was initiated soon after, but was deferred due to the subsequent discovery at the Lukami field. The Libwa field was put on production in January 1990. The Libwa field was formed in response to growth-faulting. The structure is a fault block anticline plunging northwest-southeast. The faults bounding Libwa field in the Aptian to Albian age section formed in response to movement of the underlying salt. They extend upward into the lower Kinkasi, and are believed to extend downward into the underlying Loeme salt layer. Structural dip within the Libwa Upper Pinda reservoir averages about 14°. The depositional environment of the Libwa field is that of a shallow carbonate shelf, adjacent to a clastic-dominated coastline with the terrigenous material periodically supplied by the river systems of deltas, as observed in other nearby Upper Pinda fields. The Libwa field is characterized as a low permeability (2 millidarcy) limestone with about 240 feet of oil column overlain by about 310 feet of gas cap. The oil leg is laterally continuous through the field and the gas zone is very thin at the downdip portions of the field that thickens towards the crest of the structure. Core samples indicated that there is virtually no vertical permeability and minimal natural fracturing. All of the Libwa wells currently on production required acid stimulation in order to establish economic production rates. The Libwa Upper Pinda reservoir is a saturated oil system with a large gas cap. Original oil in place is estimated to be 350 MMSTB and the original gas in place in the gas cap is estimated to be 114 BCF. PVT analysis indicated a solution gas-oil ratio of approximately 470 scf/STB at a bubble point pressure of 2540 psia. Cumulative oil recovery from the field through year 2000 is 5.2 MMSTB or only 1.5% of the original oil in place. Libwa 4 is a horizontal well that was drilled in 1990 into the low permeability (2 md) limestone of the Libwa field [Figure 1].
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.45)
- Africa > Democratic Republic of the Congo > South Atlantic Ocean > Lower Congo Basin > Offshore D.R. Congo Block > Lukami Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Area B > Block 0 > Greater Vanza Longui Area (GVLA) Field > Pinda Formation (0.98)
This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.
- Europe (0.68)
- North America > United States > Texas (0.68)
- Africa > Angola > Cabinda > South Atlantic Ocean (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Area A > Block 0 > Takula Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Area A > Block 0 > Numbi Field (0.99)