Emeraude Vapeur: A Steam Pilot in an Offshore Environment
- Bernard M. Couderc (Elf Aquitaine) | J.F. Verpeaux (Elf Aquitaine) | Dominique Monfrin (Elf Aquitaine) | Usette H. Quettler (Elf Aquitaine)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1990
- Document Type
- Journal Paper
- 508 - 516
- 1990. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 5.2.1 Phase Behavior and PVT Measurements, 5.4.6 Thermal Methods, 2 Well completion, 4.1.2 Separation and Treating, 1.14 Casing and Cementing, 6.5.5 Oil and Chemical Spills, 5.4.10 Microbial Methods, 5.5 Reservoir Simulation, 2.4.5 Gravel pack design & evaluation, 5.4.1 Waterflooding, 1.6 Drilling Operations, 5.2 Reservoir Fluid Dynamics, 5.3.4 Integration of geomechanics in models, 2.2.2 Perforating, 6.5.2 Water use, produced water discharge and disposal, 5.1.2 Faults and Fracture Characterisation, 4.1.5 Processing Equipment, 2.7.1 Completion Fluids
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Summary. Adverse conditions prevail in the Emeraude field offshore Congo on the West African coast, including shallow (200 to 500 m), very heterogeneous reservoirs and 100-mPa - s oil at reservoir conditions. In 1983, a steamdrive pilot was begun in two superposed and independent reservoirs to estimate recovery rate and oil/steam ratio (OSR). The shallow reservoirs required tilted conductor pipes, a tilted rig, and adapted pumping units on one platform, while steam production equipment had to be located on a second platform because of the distance to shore. After 3 years of steam injection, the incremental recovery rate was promising and the OSR was 0.30 vol/vol in the pilot area. Some wells outside the five-spot pilot also showed oil-rate increases. Numerical simulations of the pilot behavior were made with a thermal pseudocompositional simulator.
The Emeraude field is estimated to contain several hundred million tonnes of viscous (100-mPa.s) original oil in place (OOIP). After 14 years of production (1972 to 1986), only 22 million tonnes had been recovered, about 3 % OOIP, and the reservoir was severely depleted. To produce the remaining reserves by primary recovery in 15 to 20 years, several additional platforms would be needed, and the final recovery would still be only 5 to 10% OOIP.
Various EOR methods were considered to meet the challenge of this large amount of oil associated with this poor recovery rate. Water injection was implemented in 1972 in a five-spot pattern, assuming that imbibition would be active. The results were disappointing, with water breaking through almost immediately. In-situ combustion tests under laboratory conditions showed that most of the oil would be burnt in the fracture network. Results of alkaline water experiments under laboratory conditions caused this method to be discarded because of the incompatibility between alkaline and formation water. Promising results, however, were obtained from steam-injection tests under laboratory conditions. A steamflood pilot was implemented, with the following goals.
1. To prove the technological feasibility of such a project in adverse conditions: drilling with a tilt rig, drilling through and cementing depleted and fractured zones, pumping tilted wells, and producing steam from seawater.
2. To evaluate reservoir responses to steam injection, steam injectivity, steam breakthrough time, recovery rate, and OSR.
Geologic, Reservoir, and Fluid Characteristics
The Emeraude field lies 20 km offshore, 30 km south of Pointe-Noire (Fig. 1). The structure is an anticline with a northwest/southeast axis crossed by a curved fault (Fig.. 2). Reservoirs are shallow (200 to 500 m below mean sea level) and can be described as a silt/limestone series in the Senonian (Fig. 3) and a limestone dolomite series in the Turonian.
The pilot included the two upper reservoirs of the Senonian (R1 and R2), which contain most of the oil in place and are 50 and 48 m thick, respectively. The lithology is a rapid succession of siltstones and compact limestones. The siltstones range from unconsolidated, even loose, clean silts to argillaceous cemented limestone with permeability variations from 0.1 to 50 md. The limestones have virtually no permeability and are not impregnated; however, they may be highly fractured. The typical fracture width is 10 - 3 m, leading to fracture permeabilities far above I darcy. The average thickness of the compact beds is 0.2 m, while that of the siltstone beds ranges from 0.2 to 3 m.
This highly heterogeneous vertical organization contrasts with the good horizontal continuity shown by excellent correlations between wells. The exact extent of the compact, fractured limestone beds, however, is difficult to ascertain. The continuous beds of shaly siltstones, on the other hand, make efficient permeability barriers and divide the Senonian into a number of layers (Fig. 3).
Reservoir Ri includes Layers A through K. Here, the silty matrix is generally rather shaly and the permeability is between 0. I and 5 md. In addition, the fractured limestones, located mainly in Layers C and G, are thought to have a very large extension, which enables lateral drainage of oil.
Reservoir R2 consists of Layers L, M, and 0. The permeability barrier is very efficient between Layers 0 and M but less efficient between Layers M and L. Within Layers L and 0, the density of limestone beds is very high, so these layers can be considered highly permeable even if the individual limestone bed correlations between wells are not guaranteed. Layer M is the thickest in the reservoir (25 m) and has the highest matrix permeability (up to 50 md) and the lowest density of limestone streaks. These limestone beds do not necessarily correlate between wells, and fractures appear to be randomly connected. The fractures therefore can ensure sufficient injectivity and productivity without jeopardizing oil displacement from the matrix by acting as a bypass between wells.
This stratigraphic description has been refined to minute details within the pilot area through comprehensive coring and the use of multipad microresistivity correlations on every well, calibrated on core descriptions (Fig. 4). Table 1 gives the fluid characteristics.
Hot-Water Flood and Steam Laboratory Experiments
The basic idea in the Emeraude steam project was to circulate steam in the fractured limestone beds and, under the combined effects of vaporization, thermal expansion, and oil viscosity reduction, to expel oil from the silts. This idea was successfully tested on the Lacq Superieur pilot.
The first experiment showed that very good results could be reached simply by heating silt cores saturated under reservoir conditions up to 180 degrees C and 2.2 MPa. About 50% OOIP was expelled by thermal expansion and vaporization (Fig. 5).
After this experiment, dynamic isothermal hot-water displacements were conducted on a compacted silt core at 31 (initial reservoir temperature), 100, 170, and 240 degrees C. These experiments provided laboratory oil/water relative permeability curves and showed the temperature influence on the endpoints of these curves (Table 2). The final recovery rate ranged from 42.5 to 49.7 % OOIP, increasing with temperature.
A steamflood experiment was then performed on the same porous medium at adiabatic conditions. Steam temperature was 237 degrees C at a constant injection pressure of 3.1 MPa, field conditions for the shallow, depleted reservoirs. The final recovery rate with steam reached 84.5 % OOIP, which represents an increment of 34.8 % relative to the hot-water flood results at the same temperature.
Good agreement between observed and computed oil recovery was reached with a numerical interpretation by use of the MEPHISTO thermal simulator (Fig. 6). The match was obtained by trial and error by adjusting three-phase oil relative permeability curves.
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