Design Concepts of a Heavy-Oil Recovery Process by an Immiscible CO2 Application
Authors: Kantar K. , Karaoguz D. , Issever K. , Varana L. 
Published: December 2007

Summary
Bati Raman oil field, in southeast Turkey, represents Turkey's biggest single oil reserve.
The rapid production decline of the field and increases in the price of crude oil has led Turkish Petroleum Corp. (TPAO) to consider intervening with EOR techniques. Since 1967, various recovery schemes have been attempted, including steam and water injection. Extensive laboratory, modeling, and comparative engineering studies of various immiscible CO2 application techniques resulted.
This paper presents the reservoir engineering aspects of immiscible CO2 application as applied to Bati Raman oil field.

Introduction
Bati Raman Oil Field. Bati Raman field, discovered in 1961 in southeast Turkey (Fig. 1), contains low-pressure, low-gravity (12 deg. API [0.986-g/cm3]) oil at an average depth of 4,300 ft [1310 m]. It is the largest oil field in Turkey, with an estimated initial reserve of about 1.85×10–9 STB [300×10–6 stock-tank m3].
The producing formation is Garzan limestone, a long, partly asymmetric anticline oriented in the east-west partly asymmetric anticline oriented in the east-west direction. The field is 10.5 miles [17 km] long with a width of 2.5 miles [4 km]. The reservoir is limited by an oil/water contact (OWC) at 1,970 ft [600 m] subsea in the north and west, by a fault system in the southwest and south, and by a permeability pinchout in the southern and southeastern part of the field (Fig. 2). The formation has a gross thickness of 210 ft [64 m]. The oil column from the top of the structure to the OWC is about 690 ft [210 m].
The Garzan limestone is of Cretaceous age, has a reefal origin, and exhibits rather pronounced heterogeneities both areally and vertically. The reservoir rock is a fractured vuggy limestone in the western and central parts, but is chalky and tighter to the east. Average porosity is 18% and mainly vugular and fissured in type. The typical matrix permeability by core analysis is 10 to 100 md; however, well tests show effective permeabilities in the range of 200 to 500 md, confirming the contribution of secondary porosity (fractures, vugs, and connecting cracks). In the central and western parts of the field, a well-developed system of secondary porosity and copyright 1985 Society of Petroleum Engineers permeability is believed to exist. In these areas, a permeability is believed to exist. In these areas, a secondary vugular porosity interconnected by fissures appears to be superimposed over a low primary porosity matrix.
The main production mechanism is rock and fluid expansion. Water drive appears to be insignificant, except for a very weak aquifer influence at the central north-flank wells. The solution GOR is 18 scf/bbl [3.24 std m3/m3], resulting in a low bubblepoint pressure of 160 psi [1100 kPa]. There is practically no solution gas drive below the bubblepoint. The reservoir oil is just above the bubble-point pressure with a viscosity range of 450 to 1,000 cp [0.45 to 1.00 Pa s]. The original reservoir pressure was about 1,800 psi [12.4 MPa] at a datum of 1,970 ft [600 m] subsea. The average reservoir pressure has now declined to 400 psi [2758 kPa], after a cumulative production of 30 million STB [4.8 × 106 stock-tank m3] oil production of 30 million STB [4.8 × 106 stock-tank m3] oil (Fig. 3).
The field was developed on 62 acres [251 000 m2] per well spacing. There are 103 active producers. All are on pump with a total oil production of 2,600 B/D [413 pump with a total oil production of 2,600 B/D [413 m3/d], compared with a peak rate of about 9,000 B/D [1431 m3/d] in 1969. Initial well producing rates ranged up to 400 B/D [64 m3/d] but now are averaging about 25 B/D [4 m3/d]. Reservoir and fluid characteristics are summarized in Table 1.
Because of the unfavorable oil properties (such as low gravity, low solution gas, and high viscosity), low reservoir energy, and the type of driving mechanism, primary recovery prospects are very low. It is estimated that ultimately 1.5 % of initial oil in place (IOIP) can be produced from Bati Raman field through primary production. produced from Bati Raman field through primary production. The current trend in primary recovery and the rapid decline in reservoir pressure suggest the need for a suitable EOR method to produce a significant fraction of the vast reserve. In the past, we carried out laboratory and engineering studies as well as some field tests to enhance recovery, including water injection, steam cycling, steamdrive, and air injection (for in-situ combustion). Most of these studies, however, were empirical, exploratory in nature, and of limited scope. Of these, only the five-spot waterflood project proved conclusive. About 3.2 million bbl [500 000 m3] water were injected in the central area of the field between 1971 and 1978.
JPT
P. 275