Increased deepwater drilling today requires that expensive and risky drillstem testing operations be optimized by other technologies that provide dynamic information about the formations to be tested. Wireline-conveyed interval pressure transient tests (IPTTs) are becoming a common practise today for optimizing and designing these expensive tests. Typically, prior to an IPTT, there is only a limited amount of information available about the reservoir and fluids properties and it tends to be generally probabilistic. Therefore, the optimal design of IPTT tests is a necessary challenge for a successful and reliable test. IPTT is found to be dependent on the noise and on observable flow regimes associated with the pressure buildups. Success and reliability are not only a function of gauge metrology but also of the formation deliverability and geometry. This paper describes a new methodology for IPTT design that allows estimation of the reliability of these transient tests. A normally distributed random noise is superimposed on the analytical pressure profile computed for a given formation, fluid PVT properties, and gauge metrology. The success of an IPTT in a particular environment is estimated based on the theoretical pressure derivative and noise-superimposed pressure derivative. This approach is repeated for a range of rock, and fluid properties and practical limits to identify what is a successful. Two field examples are presented to validate this methodology.

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CNOOC is operating in YingGehai Basin and QiongSouthEast Basin of South China Sea. Formation testing has been routinely used by this operator in field exploration to confirm hydrocarbon presence, define the hydrocarbon type as well as getting PVT samples. Due to the high cost of DST operation in the offshore environment, formation testing is considered as the main testing method to test the small to medium size sand bodies. And the result is accepted to claim reserve of hydrocarbon. As the recent offshore exploration has focused more on deeper formation where the sand permeability is between low to ultra-low, the pressure pretest mobility is easily lower than 1md/cp. In some particular formation, the formation mobility is even lower than 0.1md/cp. For this type of permeability of sand, testing becomes very difficult and getting fluid sample to claim reserve becomes a huge challenge. If the formation tester fails to obtain the samples, very often the later DST operation would not achieve a success. A new probe module of formation tester has been introduced to the industry early 2013 and it has been designed to perform formation testing in low permeability environment. Especially it could apply a much higher drawdown than previous technology to move the tight hydrocarbon. In this paper, a few cases will be presented to demonstrate how this new probe work in Yinggehai and QiongSouthEast basins fluid sampling operation where we sampled successfully at formation with the mobility is less than 0.1md/cp. With this result, great amount of reserve can be claimed and this new probe has been considered as the unique solution of testing these formation as well as predicting the possible production capability..

With increasing focus on exploration in tight and low-permeability environs, formation evaluation today has become more challenging. Integrating all measurements and understanding and evaluating uncertainties are critical for an effective evaluation workflow. Such a workflow should deliver the productivity and completion strategy for an effective exploitation of reserves. The field under study is an exploratory field located in the East China Sea, and the play is an anticline along a north-south axis. The main zone of interest is in a giant sandstone formation with very low porosity. Since this is a potentially large accumulation, it was necessary to produce gas to surface to confirm the discovery and book reserves. In this study, an effective Reservoir Quality (RQ), Completion Quality (CQ) workflow is developed and executed to address the formation evaluation objectives in challenging environments. Integrating core measurements with petrophysical evaluation leads to an effective estimate of the petro physical properties and a quantitative estimate of the uncertainties involved. These uncertainties are then taken forward into a reservoir model to estimate the productivity from these sands. Geomechanical analysis is done to evaluate various completion options including hydraulic fracturing and an estimate of the post-fracturing productivity is evaluated for various fracturing scenarios. With this evaluation, an informed decision on the best way to exploit reserves was made. We present this study as an example of how various formation evaluation measurements can be integrated into a well deliverability workflow in a tight gas reservoir. Introduction The East China shelf basin offshore China is shown in Fig. 1. Although exploration has been ongoing in this basin since the early 1980s with some discoveries, mainly in the Chunxiao and Longjing structures (Jia and Ma 2000), given the size and complexity of the basin, exploration in this basin is still ongoing.

In recent years, low-porosity and -permeability gas reservoirs have become an important exploration target for the industry in general, and the China National Oil Company (CNOOC), Shanghai branch, in particular. Formation evaluation of these resources is inherently challenging, and the application of formation testers has become an integral part of the evaluation workflow to address these challenges. The XiHu basin, located offshore China in the East China Sea, is a frontier exploration area for CNOOC Shanghai branch. Drilling safety in the XiHu basin is a concern owing to the intermediate high-pressure sands and overlying coals. Drilling with high overbalance and long openhole sections to mitigate these challenges has in turn caused problems for the formation testing program that are manifested as elevated pressures and long sampling times. The optimization of formation testing began with the statistical analysis of historical data to identify trends in pressure measurement and sampling. This analysis clearly indicated that continuous filtrate invasion and water slumping processes contributed significantly to the long sampling times and apparent elevated pressures observed. Therefore, these mechanisms were studied by modeling the invasion process quantitatively using a finite-difference simulator. After matching the simulated pressures with measured pressures in a candidate well, the effect of these invasion mechanisms on the formation testing program and ways to mitigate them was investigated. Our study shows that the invasion profile in these reservoirs is different from the classic invasion profile. The classic model shows minimal invasion at the top of the sand, but we observed the longest cleanup times were generally at the top of the reservoir. Using realistic physical and drilling parameters, we demonstrate that invasion effects are often more complicated than the classic model. Optimized tool selection and testing processes have been proposed to mitigate the effects of the invasion processes. The applicability of new technology in these challenging environments was also studied and demonstrated through case studies in which an overall efficiency improvement in the formation testing program was observed.