Low-resistivity pay (LRP) has been a challenging problem in formation evaluation for many years. This is because conventional petrophysical interpretations are unable to identify pay intervals in low-resistivity reservoirs. This paper lays out a robust workflow for identifying LRP in thinly laminated sands with silty and/or shaly layers.The workflow is essentially a two-step process which integrates data from gas while drilling (GWD), conventional logs and nuclear magnetic resonance (NMR) logs which identify potential pay intervals for further examination using wireline formation tester (WFT). This approach allows one not only to identify pay intervals but also their phase and their flow characteristics without the need of a conventional drill-stem-test (DST).It is common for LRP to have high water saturation (60-70%) computed by conventional petrophysical interpretation while producing sustained water-free oil for few years. A petrophysical study was undertaken to integrate core data analyses including conventional, NMR and mercury injection capillary pressure (MICP). Data from over 100 sidewall cores (SWC) were examined. This novel approach for estimating irreducible water saturation (S wi ) was developed based on 1. A good relationship was recognized between S wi from capillary pressure data as compared to that estimated from NMR de-saturated core. 2. A correlation was established between S wi of de-saturated core and T 2, LM . 3. A validation was performed for zones producing water-free oil to link between NMR-MICP core analysis and NMR logs, using the following two methods for estimating S wi from a. capillary pressure data that is computed with knowledge of the height above free water level (FWL), b. T 2, LM of NMR logs using the correlation developed in Step 2. The benefits of this methodology are that it improves decision in well completion, predicts well performance accurately and reduces uncertainty in reserve estimation. In addition, it allows the user not only to identify zones of pay that would have been missed using conventional analysis, but also to estimate FWL elevations with higher accuracy from a saturation height model (SHM). Saturation profiles derived by this approach and those ones modeled from saturation height equations based on MICP capillary pressure data can be fitted better due to substantial reduction in uncertainties of log derived saturation data. Consequently the initialization of in-place volumes for hydrocarbons will be enhanced.

Carbonate reservoirs account for 60% of today's hydrocarbon production. Several giant carbonate fields in the Middle East are expected to be the dominant source of hydrocarbon production through the current century. Therefore, understanding carbonate reservoirs and producing them efficiently have become industry priorities and are likely to remain so. In order to assess a possible hydrocarbon reservoir, hydrocarbon saturation needs to be determined with good accuracy. In 1942 Archie published a formula to estimate water saturation in reservoirs. In case of carbonates, the saturations computed by the formula are not always correct. The factors complicating the role of the formula are known as Archie Exponents, namely, porosity exponent (m, also known as cementation factor) and saturation exponent (n). Both exponents tend to vary quite often in the carbonate reservoirs. With the exception of cores, no reliable and well established techniques exist today that can give a good estimate of these exponents. Estimating cementation exponent (m, porosity exponent) from the well logs is the main objective of this paper. The technique addressed in it is based on the assumption that the amount and pattern of cementation, caused by diagenesis, in carbonates is one of the factors controlling the value of m. Therefore in order to estimate it for carbonates, the cementation in them should be quantified. It was achieved through integration of electrical borehole images and petrophysical logs with the cores. The data on cementation was then used to estimate 'm' as a continuous curve for carbonate reservoirs. The technique provides a unique way, which incorporates textural part of carbonates, to estimate cementation factor (m) for carbonates. It has been applied to carbonates of the Middle East and Europe with good results, which were verified by the core data and production results.

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Summary A robust work flow is established to identify low-resistivity pay (LRP) in thinly laminated sands with silty and/or shaly layers. The work flow integrates data from gas-while-drilling, conventional logging, and nuclear-magnetic-resonance (NMR) logging for picking intervals for further examination with a wireline formation tester (WFT). A mini-drill-stem test (DST) is performed by means of a WFT equipped with either a single probe (SP) or a dual packer (DP) to determine the fluid type and productivity of each individual level. Two field examples are presented to compare well performance predicted by the microscale mini-DSTs with macroscale production tests. In both cases, the traditional DST is eliminated from the drilling/completion program. The final verification consists of comparing contributions of individual levels derived from the mini-DSTs with production logs. In the first case, mini-DSTs are able to provide the fluid type and individual-level transmissibility (kh/μ) for eight out of 13 distinct levels. A cost-effective approach of running mini-DSTs by means of a WFT equipped with a single probe is demonstrated to investigate multiple levels in the thin-hydrocarbon reservoir sequence. Guidelines are provided as to when a WFT with a DP is to be deployed to perform a mini-DST in a laminated formation. In the second case, the same work flow was applied to derive the fluid type and transmissibility for two wells consisting of more than 30 distinct levels in the same field. After integrating mini-DST results from the two wells 750 m apart, a framework is constructed to establish both vertical and lateral heterogeneities of thinly laminated reservoirs. The integration helps visualize the multiple-layer reservoir. Our examples confirm that mini-DSTs effectively define individual-layer producibilities in multiple-layered reservoirs. The benefits are illustrated through case histories that demonstrate our ability to manage expectations of well performance in thin hydrocarbon-reservoir sequences.

The Jenein Sud area is located in the south of Tunisia about 350 km from the Mediterranean Sea. Five successful wells have been drilled in the area and proved that structures containing various fluids are present and can be produced at economic rates. In this paper, the main challenges encountered in the area and how they were tackled is described. Pethrophysical parameters: Owing to diagenetic processes such as chloritisation, siderite cementation and quartz overgrowth, the porosity to permeability relationship is diffuse and cannot be consider for permeability estimation. Therefore, all available petrophysical datasets were integrated and clustered by using an appropriate rock typing concept, reflecting the influence of pore geometries on flow and storage. Sand distribution: Sand layers could not be correlated laterally due to the prograding environment encountered and the large distance between the drilled wells. To capture the uncertainties, a multitude of geological models was created, integrating available seismic data, outcrop studies and trends apparent from regional geology. Fluids: The individual structures consist of a large number of stacked sands. The fluids in the sands vary from dry gas to volatile oil. All the sands have individual hydrocarbon/water contacts. To determine the fluid composition of the layers and overall performance, MDT samples were taken from the sands and several production tests were performed. An overall Equation Of State model was used to describe the comingling of individual sand layers and to optimise the surface facility design. Small scale structures: To appraise the area, wells have been drilled in individual structures rather than appraisal wells into selected structures. The wells are used to prove sufficient hydrocarbons and the composition of the hydrocarbons. This information was used to select an appropriate surface facility design capable of handling the fluids and to optimise the production strategy of the area.