Miscible gas flood in a CEPSA-operated oil field has matured and, over the years, oil has been produced at an increasing gasoil ratio (GOR). Even though the gas displacement mechanism is miscible, or close to miscible, the poor mobility ratio between injected gas and displaced oil has led to inefficient sweep of the reservoir.The use of foam for gas mobility control is a proven IOR technology that can greatly improve gas injection conformance and hence improve volumetric sweep efficiency in secondary or tertiary recovery processes. This paper presents the results of comprehensive laboratory studies undertaken to define a foam system that will reduce gas mobility and preclude any risk of affecting formation injectivity.We evaluated four surfactants to establish the Foaminess, Mobility Reduction Factor (MRF) and impact of hardness, oil presence and surfactant concentration on foam strength: AOS C12-14 and AOS C14-16, LAS and Fluorobetaine. We found AOS C12-14 and AOS C14-16 to be the best foamers under screening conditions (60 bar, 90 ºC): both significantly reduced mobility. AOS was not brine-sensitive but in the presence of oil, the foam performance was reduced. Optimum concentration regarding cost and effectiveness was found to be 5000 ppm. We demonstrated that strong foam can be formed under reservoir conditions (200 bar, 96 ºC), using the Surfactant-Alternating-Gas injection technique.We have submitted a request for approval of a field pilot test which will be the first application of foam as an IOR technology in this field. If success is demonstrated in the field, the proposed approach should be helpful for field operators facing similar production optimization challenges or, for example, Foam-Assisted Water Alternating Gas (FAWAG) projects.

SPE Members Abstract Geostatistical techniques generate fine-scale reservoir description that can integrate a variety of data such as cores, logs, and seismic traces. However, predicting dynamic behavior of fluid flow through multiple fine-scale realizations has still remained an illusive goal. Typically an upscaling algorithm is applied to obtain a coarse scale heterogeneity model. Most of the upscaling algorithms are based on single phase pressure solution and are thus questionable at best for multiphase flow applications. Pseudo-relative permeabilities have often been used as a tool for multiphase flow upscaling But such approaches are highly process dependent and thus, have limited applicability. We describe a powerful, versatile, multiphase three dimensional streamline simulator for integrating fine-scale reservoir descriptions with dynamic performance predictions. Unlike conventional streamtube models, the proposed approach relies on the observation that in a velocity field derived by finite difference, streamlines can be approximated by piece-wise hyperbolas within grid blocks. Thus, the method can be easily applied in 3-D and incorporated into conventional finite-difference simulators. Once streamlines are generated in three dimensions, a variety of one dimensional problems can be solved analytically along the streamlines. The power and utility of the streamline simulator is demonstrated through application to a detailed characterization and waterflood performance of the La Cira field, Colombia, South America. We illustrate the advantage of the streamline simulator through comparisons with a commercial simulator for a waterflood pattern. The streamline simulator is shown to be orders of magnitude faster than traditional numerical simulators and does not suffer from numerical dispersion or instability. We illustrate the use of this simulator for evaluation of multiple, fine-scale realizations of heterogeneity models and quantification of uncertainty in predicting dynamic behavior of fluid flow. Introduction A geostatistical approach is commonly used to reproduce reservoir heterogeneities1. The objective is to generate a few "typical descriptions incorporating heterogeneity elements that are difficult to include by conventional methods. Conditional simulation is used for creating property (permeability, porosity, etc.) distribution with a prescribed spatial correlation structure that honors measured data at well locations. Stochastic reservoir modeling provides multiple equiprobable, reservoir models, all data intensive, rather than a single, smooth usually data poor deterministic model. Experience has shown that these data intensive, stochastic reservoir models yield a better history match of production data, yet provide a measure of uncertainty in prediction of future performance. Fine-scale realizations are the most detailed representation of the heterogeneities that exist in the petroleum reservoir. The ideal flow simulation process would be to input this fine-scale data in its entirety. However conventional numerical simulators do not allow this readily. Reservoir models built for conventional simulators using the fine-scale data are huge and unmanageable. The flow simulation process thus becomes very tedious, slow and expensive. This is in addition to any hardware limitations that may exist. Typically an upscaling algorithm is applied to obtain a coarse-scale heterogeneity model. This coarse-scale model is then input into the conventional simulators. However, most of the upscaling algorithms are based on single phase pressure solution and are thus questionable at best for multiphase flow applications. Pseudo-relative permeabilities have often been used as a tool for multiphase flow upscaling But such approaches are highly process dependent and have limited applicability. There is a definite need for a fast and powerful simulator that allows the easy use of fine-scale realizations as such without the need for any upscaling. In this paper we describe a new, fully three-dimensional, multiphase, streamline simulator for modeling waterflood performance. P. 195

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.

It is well known in the petroleum industry that tracer data can provide valuable information on reservoir characteristics and fluid flow performance. However, a prerequisite for obtaining reliable information is careful planning, design, and field implementation. The application of gas tracer technology for improving the reservoir description and optimizing the RKF Field miscible gas injection project was presented earlier. The current paper compliments the earlier work by discussing issues related to design and field implementation of the tracer program, including definition of the objectives, determination of tracer types and amounts, and evaluation of sampling and detection techniques. In this paper we document the lessons learned and propose best practices based on our experience with tracers in the RKF Field, Algeria. A critical element is integration of the field operator and Research Centre personnel with the subsurface team during all phases of the tracer program. This integration has been very important in obtaining good quality data in the RKF project. We also review common mistakes and bad practices that could occur in the absence of a robust tracer design program. The importance of analytical calculations, simulation, sampling frequency and the recycling of tracers are also among the design topics that are addressed. The proposed best practices can be applied by field operators in the design of future tracer projects and can also be used to identify the causes of tracer monitoring problems in existing projects. We hope that this paper will be of use to those managing or planning tracer projects. Introduction The Rhourde El Khrouf (RKF) Field is located in Block 406A of the Berkine Basin, 300-km southeast of Hassi Messaoud1. The field has been producing under partial pressure maintenance by miscible gas injection from the TAGI (Trias Argilo-Gréseux Inférieur) since 1996. Deeper volatile oil and retrograde gas condensate reservoirs provide makeup gas for the project. Tracer technology has been successfully applied in RKF. It is demonstrated that reliable tracer data can be obtained through careful planning, design, implementation, and monitoring. A key element of success is integration of the project team to include the disciplines of reservoir engineering, geosciences, field operations, and tracer specialists. This paper will discuss the integrated workflow and lessons learned, and will propose best practices based on the successful gas tracer project implemented in RKF field2. Background Tracer technology has been used for hydrocarbon reservoir characterization for more than 50 years3. Tracers can render information that is almost impossible to obtain with other methods, such as identifying flow paths, breakthrough times from injector to producers and estimations of the interwell oil saturation. Tracer technology is also used in the subsurface in single-well applications for mass balance calculations and saturation measurements. At the surface, tracers have been used in separator efficiency tests, and in transport lines and refinery surveys4,5. Tracer can provide very reliable information on fluid flow characteristics in secondary or tertiary recovery processes. Tracers reflect the reservoir dynamics and can be injected any time at the start of the injection or later to obtain the fluid flow paths and velocities in the reservoir. The type of tracer information acquired depends on the objectives for the application. Some objectives could include:detecting and documenting breakthrough times;mapping flow paths and performing analytical calculations; andmore advanced analyses using reservoir simulation to improve reservoir description and optimize reservoir management. Recent developments in tracer technology, especially in the areas of sampling and laboratory analysis techniques, have made it easier and less expensive to undertake a tracer project. This does not mean that it is not a complex procedure. On the contrary, based on our experience, a successful tracer project implies special technical, cost, and environmental considerations.

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.