Bati Raman Field Immiscible CO2 Application: Status Quo and Future Plans

Abstract

The Bati Raman field is the largest oil field in Turkey and contains some 1.85 billion barrels of oil initially in place. The oil is heavy (12 oAPI) with high viscosity and low solution gas. Primary recovery has been inefficient, less than 2% of OOIP. Over the period of primary recovery, from 1961 to 1986, the reservoir underwent extensive pressure depletion from 1,800 psig to as low as 400 psig in some regions, with a related production decline from a peak of approximately 9,000 Bbls/day to 1600 Bbls/day. In March 1986, a CO2 injection pilot scheme in a 1200 acre area containing 33 wells was initiated in the west portion of the field. The gas injection was initially cyclic; "huff and puff" method was applied. Later, in 1988, the gas injection scheme was converted to a CO2 flood process. Later, the process was widespread to cover the whole field. A peak daily production rate 13000 STB/d was achieved in 1993 in comparison to what would have been less than 1600 STB/d without CO2 application. However, since 1995, the field has undergone a progressive production decline to recent levels at approximately 5,500 Bbls/day. Polymer gel treatments were carried out to increase the CO2 sweep efficiency and arrest the decline. Multilateral and horizontal well technology was also applied on pilot scale to reach the bypassed oil. WAG is applied widespread now. Current production is 7000 Bbls/day. This paper documents TPAO's 25+ years of experience on the design and operation of full field immiscible CO2 injection recovery project conducted in the B.Raman heavy oil field, in Turkey. The objective is to give an up-to-date status of the performance of the application; reservoir/field problems that TPAO had, unexpected occurrences and results and just a general idea of how successful the project has been. Introduction The Bati Raman field, which is the known highest oil accumulation in Turkey, contains very viscous and low gravity oil in a very challenging geological environment. Due to the fact that the recovery factor by primary recovery was limited, several EOR techniques had been proposed and tested in pilot level in the 70s and 80s. Based on the success in the lab tests and vast amount of CO2 available in a neighboring field which is just 55 miles away from the Bati Raman field, field scale huff-and puff injection was started in the early 80s. Due to the early breakthrough of CO2 in offset wells in a short period of time, the project was converted to field scale random pattern continuous injection. Over more than 20 years of injection, the recovery peaked at ∼13,000 bbls and began to decline reaching today's ∼7,000 bbl value. In the case of Bati Raman, at this mature state of the process, the injected agent is increasingly bypassing the remaining oil and production is curtailed by excessive high gas oil ratios (GOR). The naturally fractured characteristics of the reservoir rock has been a challenge for establishing a successful 3D conformance from the beginning and its impact is even more pronounced in the later stages of the process. Because of that reason, the subject field requires modification on the reservoir management scheme to improve recovery factors as well as improving productivity of the current wells. BATI RAMAN FIELD Bati Raman was discovered in 1961 in Southeastern Turkey with the completion of BR-1 (Fig-l). The producing formation is the Garzan Limestone, a very heterogeneous carbonate of Cretaceous age. The reservoir fluid is a very heavy crude oil, having an API gravity ranging from 9.7 to 15.1 and a viscosity ranging from 450 to 1000 centipoises at reservoir conditions. The structural trap is a long; partly asymmetric anticline oriented in the east-west direction which measures about 17 km. long and 2 to 4 km. wide. It is limited by an oil/water contact at 600 meters subsea in the north and west, by a fault system in the southwest and south, and by a permeability barrier in the southern and southeastern part of the field. Formation has a gross thickness of 210 ft (64m). The oil column from the top of structure to the OWC is about 690 ft.

Experimental Determination of Equilibrium Interfacial Tension for Nitrogen-Crude Oil during the Gas Injection Process: The Role of Temperature, Pressure, and Composition

“…11 Other problems include corrosion, wellbore annular freezing, low injectivity, and pump problems. 14 From the economic point of view, oil price, capital investment, and operating cost are the chief factors that need to be taken into account. 15 But above all economic and technical issues, the CO 2 source must be available, plentiful, accessible, and reliable.…”

“…From a technical perspective, asphaltene precipitation during CO 2 injection can nullify the success of this method and cause severe problems such as formation damage, wettability alternation, relative permeability reduction, and flow interruption in the reservoir as well as surface facilities. − Therefore, in several oil fields the use of CO 2 is ruled out because of potential asphaltane precipitation . Other problems include corrosion, wellbore annular freezing, low injectivity, and pump problems . From the economic point of view, oil price, capital investment, and operating cost are the chief factors that need to be taken into account .…”

A novel method of bidirectional displacement with artificial nitrogen gas cap and edge water for enhanced oil recovery: Experimental and simulation approaches

“…CO 2 flooding has been used for decades as an acceptable tertiary recovery method in the petroleum industry (Green and Willhite, 1998;Lake, 1989;Moritis, 2004;Orr and Taber, 1982), where water flooding is largely unsuccessful (Sahin et al, 2007(Sahin et al, , 2012. Depending on the characteristics of the reservoir fluid, the oil displacement process by carbon dioxide injection is classified in two ways.…”

“…CO 2 dissolution and stronger adsorption capacity lead to oil swelling, solution gas drive, and oil extraction (Liu et al, 2017;Sun et al, 2013Sun et al, , 2017. On the other hand, immiscible displacement occurs below the MMP, in which there are less components interchange or mixing zones between the injected gas and the reservoir fluids (Sahin et al, 2007). But the low viscosity and density of carbon dioxide result in gravity override and unbeneficial mobility ratio (Wang et al, 2017).…”

Determination of Three-Phase Boundaries of Solvent(s)–CO2–Heavy Oil Systems under Reservoir Conditions

“…CO 2 is found to be effective for recovering heavy oil or bitumen resources where other recovery techniques are not applicable. , The alkane solvents (e.g., C 3 H 8 and n -C 4 H 10 ) are proven to be efficient for the VAPEX process because of their high solubility in heavy oil . The increased solubility of the solvent(s)–CO 2 mixture in heavy oil leads to an enhanced swelling effect and a viscosity reduction of heavy oil, as well as a reduced interfacial tension between the gas mixture and heavy oil .…”