For some years SITEP and Eni have started to evaluate certain tertiary methods of enhaced oil recovery for El Borma, a mature tunisian field. A pilot project based on the application of a commercial chemical product called "BRIGHT WATER®" (BW), a trademark of Tiorco-Nalco, was chosen to verify on a real case its applicability and efficiency. The technology aims at the improvement of the oil recovery and at the reduction of the water production. This methodology is applied for oil mature fields, that are subjected to the water injection and that are presenting a heterogeneous reservoir with contrast of permeability. This paper describes the work performed to design a field test of such a technique in El Borma, with the twofold purpose to achieve the highest probability of success and gather as much information as possible to use in future applications. The project went through four phases: 1. Selection of one injector well and one producer; 2. Program of monitoring to verify the connection between the injector and the producer (injection of a tracer to determine the arrival time and simulation on a numerical model); 3. Injection of the polymerics and monitoring; 4. Application on the other zones of the field, in case of the success of the method. The first three phases were completed at the beginning of 2010. This work also describes the workflow which will be established to follow the improvements of the oil production.

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El Borma is a mature oil field located onshore in the Northern Sahara Desert, Tunisia. Oil production commenced in 1966 and is currently supported by water injection; the high water cut (96%) and permeability contrast in the main reservoir (Level "A") indicated thief zones with less than optimum sweep efficiency prompting the evaluation of a tertiary method for improved oil recovery. In January of 2010 a pilot project (injector-producer) was implemented to evaluate a thermally activated particle (TAP) system as a strategy to improve the sweep efficiency of ongoing water injection program. This paper will summarize TAP pilot implementation and will describe methodology and results of project monitoring and injection-production performance. The evident good results of this TAP application (decrease in water cut with consequent increase in oil recovery up to 55%) in the last fourteen months justified a larger scale application in the field. The field scale application design was performed in two different steps: 1) Comprehensive production-injection data analysis of injectors based on the number of connected (offset) producers and channel volume estimations and; 2) The numerical simulation studies of most promising patterns calibrated with information generated during the first TAP pilot. Screening of patterns candidates and simulation approach of TAP will be also presented. El Borma pilot results validate the potential of TAP as an in-depth conformance strategy that can improve sweep efficiency of mature waterfloods. El Borma workflow to screen and rank patterns candidates combined with pilot project implementation, monitoring and evaluation can be used as a reference to evaluate the benefits of TAP technology in waterflooded oil reservoirs.

Permeability estimation in carbonate reservoirs is challenging and it generally consists of core-calibrated algorithms applied on open-hole logs. Moreover, due to inherent multi-scale heterogeneities, apparent permeability from production logging tool (PLT) is usually necessary to let the static log-based prediction honor dynamic data. The correspondence between dynamic corrections and carbonate rock types is a long-standing problem and an elegant solution is presented by integrating advanced nuclear magnetic resonance (NMR) log modeling with multi-rate PLT interpretation. The methodology, discussed on an oil-bearing carbonate reservoir, starts with a rigorous mapping between NMR responses and pore-size distribution, mainly determined by special core analyses (SCAL). Hence, a robust porosity partition template and a physically-based permeability formula are established downhole relying on the quantitative integration of SCAL and advanced NMR modeling. Multi-rate PLT and well test data are then analyzed to evaluate the boost needed for log permeability to match the dynamic behavior of the wells. Finally, porosity partition outcomes are used as pointwise predictors of dynamic permeability enhancement by means of a probabilistic approach. In details, a system built upon mercury injection capillary pressure measurements, representative of the entire reservoir, shows a well-defined pore structure consisting of micropores, mesopores and macropores. At the same time, a quantitative link is established between NMR transverse relaxation time and pore-size distributions through an effective surface relaxivity parameter, both at laboratory and reservoir conditions. This allows discriminating micro, meso and macro-porosity downhole. Effective surface relaxivity also plays a critical role in the subsequent NMR permeability estimation based on a capillary tube model of the porous media and exploiting the full NMR/pore-size distributions. Although the match with core data proves the reliability of the comprehensive rock characterization, log permeability values underestimate the actual dynamic performances from well test. Therefore, the standard apparent permeability method from multi-rate PLT interpretation provides the necessary correction from the dynamic standpoint. Macro-porosity content is demonstrated to be the driver for a quantitative estimation of the excess in matrix permeability and an additional term complements the original NMR permeability predictor in order to honor the dynamic evidences. The approach makes use of a probabilistic framework aimed at considering the uncertainties in the a-priori simultaneous static and dynamic characterization. The presented innovative methodology addresses the well-known issue of quantitatively incorporating dynamic log modeling into a purely static workflow, thus leading to a more accurate permeability estimation. This is fundamental for production optimization and reservoir modeling purposes in highly heterogeneous carbonate environments.

A WAG injection project is foreseen in a North-African field, which was first brought on stream in 2004 with production coming from two separate hydrocarbon columns within the Upper and Middle TAG-I Triassic sandstone reservoirs. The crude oil is light (44°API) and develops multi-contact miscibility with its own solution gas. The current development strategy centers on gas injection as well as water injection for pressure maintenance. Recently, the maximum gas separation capacity was reached, and because the operator respects a zero-flaring policy, a key element of the development strategy involves active gas management which may influence a number of smaller satellite fields that also tie in to the same production facilities. This paper describes efforts to further increase oil recovery in the considered field by means of miscible hydrocarbon gas injection implemented as a tapered WAG. We describe our monitoring plan which involves, among other things, systematic use of diagnostic plots to constrain and assist history matching of the field performance. Some gas breakthrough data indicate arrival of a methane bank ahead of the main gas front, which suggests that the multi-contact miscibility may not be entirely preserved due to dispersion effects. The pattern performance analysis is inspired by earlier gas injection projects and its main purpose is to enable the operator to benchmark patterns and make efficient use of the available injectant. Current gas utilization ratio is around 25-30 Mscf/stb for continuous gas flooding. It is estimated that full-field implementation of a tapered, miscible hydrocarbon WAG will lower the gas utilization ratio further and push the recovery factor towards 60%.