Oil Recovery From Tarmat Reservoirs Using Hot Water And Solvent Flooding

Abstract

The existence of tar accumulations (tarmat) beneath the oil zone in some reservoirs creates productivity problems through restricted aquifer support during the primary recovery stage. It also affects the performance of peripheral water injection when the tar/oil boundary is irregular. The objective of this study was to investigate and evaluate combined solvent and hot water injection beneath the tarmat to improve aquifer support by displacing and dispersing the tar. Displacement runs were conducted in one-foot long Berea sandstone composite cores, simulating a tar zone and an oil zone in series, at injection rates of 1 ml/min. and higher. The results show that although the oil recovery from hot water displacement is lower than cold water displacement in the absence of tar, the gain in recovery for hot water over cold water is substantial in the presence of tarmat. Driving a slug of solvent with hot water to displace tar increases the hydrocarbon recovery even further. However, for each of the two solvents studied, there is an optimum slug size with which the hydrocarbon recovery is maximum. Moreover, the recovery was found to increase further when the optimal slug is divided into portions separated by small slugs of hot water. The injection rate had a profound effect on the recovery for all hot-water flooding schemes. The results showed consistently that the recovery increased at lower injection rates. Introduction Many oil reservoirs are characterized by the presence of a highly viscous hydrocarbon layer (tarmat) at the oil/water contact. Such tarmats are found in many major oil reservoirs in the world and, particularly, in the Middle East. They are reported in the literature to vary widely, ranging from highly viscous hydrocarbon fluids to near solid materials(1). The thickness of the tarmat varies from place to place in the same reservoir and sometimes reaches few hundred feet; while their extent can reach several kilometres. In Ghawar field, for example, the tar zone extends more than 25 km and reaches up to 150 m in thickness(2). Several geochemical studies presented by various authors attribute tarmat formation to gravity segregation which leads to a compositional grading with depth(3–5). Depending on reservoir conditions and tar viscosity, field experience shows that some of these tarmats can become mobile under conditions of moderate differential pressure(2). The presence of tar deposits at the oil/water contact in a tarmat reservoir can have serious adverse effects on the effectiveness of natural water drive as well as secondary recovery projects. When the tarmat completely surrounds the oil zone, the oil reservoir behaves like a finite lens where the pressure decreases rapidly as soon as the first well starts producing. This leads to an alarming increase in gas/oil ratio during the primary stage of depletion which has been the case with Minagish reservoir in Kuwait(2). Another such example is El Bundug reservoir in Qatar(6).

Discussion of thermal experiments’ capability to screen the feasibility of air injection

“…On the other hand, after adding additives such as clay minerals or metallic additives which have a catalytic effect on crude oil combustion reactions, the activation energies will generally decrease around 30%~70% in the HTO stage, while no obvious effects on the LTO stage were observed. Fig 7 below shows the activation energy distribution of crude oil with the presence of additives which includes 25 cases [6,10,15,18,33,34,35,[48][49][50][51][52][53][54].…”

Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir

“…Particularly, thermal EOR implemented in many projects such as steam stimulation, or cyclic steam flooding, also known as steam flooding, Steam Assisted Gravity Drainage (SAGD) and hot water injection (Teodoriu et al 2007;Alajmi et al, 2009). Many authors in both laboratory experiments and numerical simulation have shown that the oil viscosity and mobility ratio can be reduced by hot water injection, ultimately resulting in improved oil recovery (Teodoriu et al, 2007;Taber, 1998;Milton et al, 2003;Prats, 1982;Goodyear et al, 1996;Bousaid, 1991;Jabbour et al, 1996;Okasha et al, 1998;Alajmi et al, 2009). Martin et al (1968) reported a case study that the hot water flooding yield oil recovery increasing for a pilot test in the Loco field in southern Oklahoma.…”

An Experimental Study for Enhancing the Recovery Factor of Tar Barrier Heterogeneous Reservoirs

“…These optimum sizes for reformate and naphtha were 9.45 and 10.93% total hydrocarbon pore volume (THPV), respectively. Solvent slugs that are larger or smaller than this optimum size are less effective [12]. Another study was conducted by Harouaka and Asar [13] on tar properties and methods for improving injectivity in tarmats using naphtha and steam.…”