The Caracara Sur Field (Llanos Basin, Colombia) consists of multilayered compartmentalized fluviodeltaic reservoirs. Sands have Darcy-level permeability, contain a medium-quality oil (21° API), and are subject to very strong aquifer support. The reservoirs are produced with artificial lift, either selectively or commingled. After six years of development, oil production is expected to decline. Ongoing efforts to maintain the production plateau include infill and horizontal attic oil drilling and selective completions. However, there is a limit to what can be achieved considering the strong aquifer drive and unfavourable mobility ratio. This encouraged the investigation of enhanced/increased oil recovery (EOR/IOR) methods which has resulted in screening a number of EOR processes and the planning of a pilot project in the field. EOR/IOR screening evaluation identified chemical EOR processes as the most suitable techniques for the field. Polymer, alkaline-polymer (AP), Alkaline-Surfactant-Polymer (ASP) and surfactant-polymer (SP) are the technologies under consideration. A careful and complete project plan has been developed, customized for the field’s most challenging characteristics: fresh formation water, in-situ oil viscosity of 12 cP, relatively high reservoir temperature (above 175 °F), the need to inject and produce commingled, (up to six stacked reservoirs) and most importantly the strong and drifting aquifer, which is expected to influence sweep efficiency. The plan includes laboratory studies, multi-scale high-resolution reservoir simulation, single-layer single-well tests of injectivity and residual oil saturation, and a multi-layer inter-well pilot prior to full-field deployment. Tracer technology has been developed in-house to support the project. Back flow tracer tests and single-well tracer tests will be conducted in the field to evaluate aquifer drift and to determine the remaining oil saturation. Comprehensive evaluation will permit the design of an efficient vertical injection profile, appropriate injectivity and chemicals displacement in a multi-reservoir field. The planning stage of the Caracara Sur EOR strategy, including the screening evaluation and the first project results, provides guidelines and solutions that can be used on other EOR projects in similar fields and facing similar challenges, not only within the Caracara Block itself, but within the Llanos Basin and elsewhere: A ‘fast-track’ program, whereby screening and field studies are done partly in parallel targetting shortened elapsed time for the pilot evaluation. If results are technically successful this will allow profitable full-field EOR implementation. Use of an in-house project team supported by integrated laboratory expertise (leveraging CEPSA’s petrochemicals experience) is proving to be efficient and successful in delivering a high quality technical solution.

To ensure a technically and economically viable chemical Enhanced Oil Recovery (cEOR) project in the Caracara Sur Field (Llanos Basin Colombia), several challenges were faced. One of the challenges described in a previous work (Cubillos et al. 2013), is the design of an efficient chemical formulation stable at reservoir conditions. Comprehensive laboratory work has been undertaken, resulting in an Alcali Surfactant Polymer (ASP) formulation containing hydrolysed polyacrylamide (HPAM) as a mobility control agent. HPAM is the most used polymer in the oil industry thanks to its low cost and availability in high quantities. However, initially it was not clear that HPAM efficiently worked for Caracara Sur, because HPAM properties limits its efficient application to low temperatures (<80 °C) and low-to-moderate salinity reservoirs. In this paper, we present the laboratory work that lead to find an innovative solution founded on the synergy between the formation water properties (low salinity) and high temperature environment in the Caracara Sur Field. The study focused on the polymer screening process, rheological properties of HPAM with the low salinity brine of Caracara Sur, the HPAM performance in porous media and chemicals to enhance its thermal stability. This work is only focused on the polymer selection and the synergy between low salinity brine and polymer flooding. The main results show that the developed formulation for the Caracara Sur reservoirs is a viable cEOR alternative. By injecting low salinity brine and HPAM with the right mix of other chemical components, it is possible to drastically reduce the cost of cEOR, whilst maintaining the same efficiency even at higher reservoir temperature. As a final product, an optimal ASP formulation has been developed and successfully tested both at laboratory and field conditions.

Chemical Enhanced Oil Recovery (CEOR) in a multi-layered reservoir environment with moderate to strong natural water-drive is a complex process with associated risks and uncertainties. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities aimed to a cost-effective CEOR process implementation. Key to the success of a reliable reservoir simulation is the application of a de-risking process and the acquisition of important calibration data, such as laboratory core-flood data and field-scale pilot experiments.A CEOR pilot is currently undertaken in the Caracara Sur (CCS) field (Llanos Basin, Colombia) which has an unfavorable mobility ratio and very low water salinity. However challenges exist, such as strong water drive (no water injection experience), high temperature and a complex geological nature (up to 15 reservoir layers that made up of multiple isolated distributary channels). A detailed reservoir simulation model was built to study full field implementation of CEOR in Caracara Sur. The model was calibrated with laboratory tests data, residual oil saturations from Single Well CEOR ASP Well Tracer Test Pilots, injectivity tests and breakthrough times from inter-well tracer tests.The paper discusses the approaches taken for full field modeling of Caracara Sur using commercial software and describes how the data collected from alkaline/surfactant/polymer (ASP) core flooding were up scaled and used in pilot sector modeling and for designing tracer back flow tests (TBFT) and single well tracer tests (SWTT) before and after ASP flooding. The TBFT and SWTT results in a pilot injection well, in the middle of three producers, confirmed the absence of aquifer drift, which was also predicted by pilot sector modeling. The paper explains how the obtained results from the tracer tests (residual oil saturations, breakthrough times) and well injectivity were used to calibrate the full field numerical model for reliable prediction of the effectiveness of the ASP flooding.

SPE Members Abstract In one of the main producing reservoirs of an offshore Abu Dhabi field oil is produced by means of a strong bottom waterdrive. The reservoir is in its final stage of its primary development and gas injection is planned in the invaded part of the reservoir to boost total recovery. Before embarking on a full field gas injection development, two pilot gas injectors were drilled in different parts of the reservoir and wet gas is injected below the miscibility pressure. According to a PVT-study, gas injection swells the oil by some 16% at the current reservoir pressure. This paper summarises the various monitoring techniques, applied to these two pilots and discusses the further implications of some of the measurements. A split-up of the observed oil gains due to changes in oil mobility and flowing bottomhole pressure is also given. Introduction Location and Geology The field is located offshore Abu Dhabi and comprises reservoirs in the lower Cretaceous THAMAMA sequence and in the UPPER JURASSIC ARAB sequence. The main oil-bearing reservoir in the ABU AL BUKHOOSH Field is contained in the ARAB D2. This reservoir consists of variable alternances of limestone and dolomite layers, with a 7-10 m thick anhydrite caprock, separating the ARAB D2 from the ARAB D1 reservoirs. The ARAB D2 can be subdivided into broadly correlatable units from D2a to D2h (Figure-1). These main units can in turn be subdivided into several sub-units, which are more difficult to correlate. The particular interest to this study is the uppermost D2a unit, which can be subdivided into 7 sub-units from D2a1 to D2a7 (Figure-2). The D2a1 and D2a7 have a mainly dolomite nature and can be correlated fieldwide. The other sub-units contain various degrees of limestone and are more difficult to correlate. Porosities and absolute air permeabilities in the ARAB D2a subunits are listed in Table I. P. 319

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