Summary
This work presents a new methodology to identify fluid in formation layers and estimate individual reservoir parameters using openhole formation testing techniques. Real-time pressure and fluid identification data are obtained from a new wireline formation testing tool. The tool's dual packer module is needed to isolate individual zones. Field cases from wells located in the San Jorge Gulf basin and in the Neuquen basin illustrate the validity of testing methodology. The reservoir permeability (vertical and horizontal) and formation damage are calculated from pressure transient analysis of buildup and interference pressure data taken from several wells. The results obtained using this technique is consistent with those obtained from testing after well completion (cased hole drillstem test). Evaluation results can be used to decide whether to complete or abandon the tested zone. Fluid type is identified in real time using an optical fluid analyzer. Evaluation of anisotropy on a productive zone scale from the vertical interference test is presented.
Introduction
The main objective of formation evaluation at openhole conditions is the identification and description of hydrocarbon reserves with the best degree of resolution possible to assist in deciding whether to abandon or complete the tested interval. Equally important is obtaining the reservoir pressure and reservoir parameters to compute formation permeability and transmissibility. These are usually measured using well logging and testing techniques both at open- and cased-hole conditions. However, success in identifying the correct fluid rarely exceeds 60% for reservoirs such as the one in the San Jorge Gulf basin, located in the central Patagonia region in southern Argentina, although in many cases a complete set of logs is used. This leads to completing, perforating, and testing all prospective intervals, which has proven to be an expensive evaluation and completion process.
The main reason for the unpredictable results is the multilayer nature of the gross prospective producing interval. The interval thickness of interest in a typical well is between 800 and 1200 m, with approximately 40 lenticular reservoirs ranging from 1 to 10 m thick. As shown in the San Jorge Gulf basin stratigraphic sequence in Fig. 1, the upper intervals are laminated sands with a high clay content. The bottom layers are tuffaceous sands of a variable, complex lithology. The sands are highly laminated, with a variable, high water saturation. In addition, the layers are laterally discontinuous (1 to 3 km wide) and heterogeneous. The initial oil production rate is about 30 m3/d (usually obtained by fracturing) and most of the wells are produced by rod pumping.
The major challenges in the San Jorge Gulf basin for the past 60 years have been to identify the potential oil layers in a multilayer system and to determine the expected production rate, reservoir permeability, and formation damage (mainly for fracture design) for each potential layer prior to completing the well or zone. Early reservoir evaluation is necessary to provide these answers and because wells are put on rod pumping, which limits the subsequent use of direct evaluation methods.
Our research over the past 2 years in formation evaluation and testing techniques has focused on determining the applicability of new methods that may optimize current evaluation practices. As a result, a methodology based on application of the new-generation wireline modular formation dynamics tester (MDT) tool for evaluating layer productivity before well completion was implemented. In this paper, we present several field cases showing the independent evaluation of a given layer in a multilayer system. In these examples, formation fluid identification (besides mud and filtrate) is accomplished in real time, which assists in pressure-volume-temperature (PVT) analysis. Layer anisotropy is obtained and validated for the layer thickness scale. The values of permeability and formation damage are determined from pressure transient analysis of drawdown and buildup data obtained by isolating the layer using the tool's dual packer module. Testing time per layer is less than 1 h. Evaluation is done in real time, hence, the decision whether to abandon or complete the particular layer can be made at the wellsite. Even though the methodology presented here was applied mainly to the San Jorge Gulf Basin reservoirs, it is not limited to this basin, but it is valid for any laminated, multilayer, thick reservoir. A field case of a well completed in multilayer reservoir located in the Neuquen basin, Neuquen province, Argentina is presented to illustrate the validity of the method in a completely different formation geological environment.
Formation Evaluation and Testing
A typical formation evaluation and testing program in the San Jorge Gulf basin consists of running an appropriate suite of logs (usually including a conventional formation tester) to identify the layer's reserves. Openhole drillstem tests (DSTs) are also run as necessary. Completion of the well is based on the evaluation results. Casing is set, and all the prospective intervals are shot separately. Following a pressure buildup test of about 8 to 10 h duration [(TST) test], swabbing is conducted for 6 to 8 h in selected layers. The main objectives are to obtain fluid type, production rates, reservoir permeability, and formation damage (skin). These parameters are important for fracture design and equally important to define candidate zones for fracture treatments. Layer point pressures obtained with the conventional formation tester are an important measurement but limited in the case of a heterogeneous layer, such as a naturally fractured layer. The number of layers present in a well (up to 40) limits an exhaustive evaluation for economic reasons. For example, it would require a long time (days) to perform a cased hole DST for each layer present in a well. A brief summary of formation and testing evaluation limitations, based on experience, is as follows.The heterogeneous nature of the lithology usually requires conducting conventional testing on a very small vertical scale (centimeters), which limits the application of openhole DSTs.Verification of fluid identification using log techniques is usually done after a well or particular interval is completed, that is, cemented and perforated.
UPPAAL in 1995
