Many sedimentary features of gas fields are multilayered, deltaic, thinly laminated shaly sandstones consisting of channel and bar sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations among nearby wells proved to be inconclusive in identifying gas reservoirs owing to their thin beds, high shale content, and variable formation water resistivity. Missing gas-bearing formations translates into lost productivity, while perforating water zones can have detrimental effects on well performance. Moreover, the limited lateral extent of these relatively tight gas sands leads to extremely depleted reservoirs alternating with layers with virgin zone pressures. As a consequence, the depleted layers face a significant overbalance while drilling with an oil-base mud system. Given these complexities, fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. The main challenges faced during formation testing in the reservoirs studied have been a) laminated, low mobility and thin formations with varying water salinity, b) high depletion, resulting in extreme overbalance for some layers in new wells, c) possible formation damage while drilling, d) cable creep while station logging. Several different approaches have been recently launched to increase the success ratio of wireline formation testers (WFT's) in getting reliable pressures and fluid analysis, including real-time monitoring of each survey by reservoir engineers. This paper describes the development path and results from the new techniques:extra-large diameter probe,elliptical probe,the openhole driller,cable creep correction andextra-extra high displacement pump unit. We will present each project and its impact on the improvement of WFT tester success ratio in such challenging environments. Introduction The predominant sedimentary features in the reservoirs we focus are very thinly laminated shaly sands composed of 70–80% quartz plus feldspar and clays (kaolinite and illite), in which gas sands are not in pressure communication. Figure 1 shows an image log of a 4-meter section where very fine layering is evident. Vertical heterogeneity on various scales lead to multiple gas/water contacts with extremely depleted and virgin zones in the same well, thus resulting in very high over-balance; commonly in excess of 6000 psi and occasionally up to 10000 psi differential pressure. The shale quantity and thin-beds very often results in conventional logs giving wrong fluid determination, therefore fluid analysis using wireline formation testers is a very important step during the open hole evaluation stage. As noted, these conditions are quite challenging for formation testing. Some of these challenges, particularly near wellbore formation alteration have been studied using a multi-probe wireline formation tester (Ayan et al., 2007). In this study, the authors used dipole radial profiling and Interval Pressure Transient Tests (IPTT) and showed that possible formation damage does not necessarily increase with increasing overbalance. Some operational aspects of wireline formation testing have been discussed for such environments (Ferment et al. 2004), highlighting issues with high differentials, probe plugging, fine laminations and depth control. Over the past 20 years, in the formations we focus in this study, the operational success ratio of downhole formation pressure testing (valid test vs. total tests) has remained at an average of 30% despite technological innovations in both wireline and drilling. In Table 1, we summarize the main reasons causing low pretest success ratio. To increase the success ratio for pressure testing and downhole fluid identification, a multitude of solutions were proposed. In this study, we describe each of them and the results achieved following their introduction.

No abstract

This case study focuses on a Middle East giant carbonate oil field drilled with horizontal producers and water injection wells. In this particular field, formation pressure while drilling measurements are primarily used to characterize the mobility of the formation fluid, to ensure injectors are optimally placed in good injectivity intervals and producers in high productive zones. Acid stimulation is required to mitigate drilling induced reservoir damage. Owing to the length of the open hole sections and the high heterogeneity of the formation mobility, effective placement of acid is very challenging. Viscoelastic diverting acid is commonly used to assure good zonal coverage across each stimulation stage, but the length of the extended reach wells requires optimum diverter placement for cost effectiveness. An innovative methodology using distributed temperature surveys (DTS) with fiber optic enabled coiled tubing was introduced to compare pre-treatment injectivity with the mobility profile acquired while drilling before formation damage has occurred. The predicted injectivity/productivity profile computed from mobility measurements is used to establish the fluid placement strategy during the pre-job planning stage to decide on the required amount of acid and diverter. During the matrix stimulation operation, the temperature profiles after an injectivity test are compared with the baseline DTS temperature and mobility profile to identify thief zones and intervals with drilling damage. The availability of this information at the well site during the acid treatment allows the selective placement of diverter fluid across the thief zones, verification of the effectiveness of the diversion, its distribution along the wellbore, and accurate spotting of acid across damaged zones. By implementing this process, under stimulated intervals close to the heel section, which has longer exposure time to the drilling fluids, were identified. The current practice of pumping alternating stages of acid and diverter for certain lengths of wellbore segment has been revised and a new optimized approach was introduced. The new methodology has been applied to several wells and has allowed a better use of available treatment fluids to obtain more even injectivity/productivity profiles and maximize stimulation effectiveness.

Fluid identification is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer modules helped understand reservoir fluid characteristics, identify production zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. However, water zones and secondary gas cap formation in a few layers are also common. Nonetheless, unexpected fluid production, such as water or excessive gas is an undesirable outcome. A formation tester equipped with an extra large diameter probe and two downhole fluid analyzer modules was used to identify reservoir fluids in newly drilled wells. Two fluid analyzers were placed above and below the downhole pump module. The fluid analyzers monitored downhole oil based mud filtrate contamination, free gas presence, water or oil flow at selected depths. The surveys identified the downhole fluids and clarified oil, gas and water bearing zones. Some zones were identified to have gas and possible oil presence. Few stations, which were clearly identified as oil were perforated and produced oil/dry oil with natural flow. The survey helped optimize perforation zone selection, avoided unwanted fluid production and helped the operator to find and produce oil in a complex setup. Introduction In developed and aging fields, it is essential to understand the reservoir and fluid characteristics for optimum reservoir management. A common method is to integrate all existing information on reservoir rock, fluid and production data. These range from seismic, geological and petrophysical data, core analysis, well tests and production data. However in complex reservoirs, despite the number of wells drilled in a development scenario, correlating / integrating such data is not always enough to avoid unexpected results. Missing productive intervals in a new well, zones with unexpectedly low / high pressures, undesirable fluid production and presence of additional reserves or bypassed hydrocarbons are common occurrences in complex reservoirs. At a given location, layer or compartment, reservoir fluids may change with time; water encroachment, secondary gas cap formation/gas cap expansion, reservoir re-pressurization are some of the reasons of changing fluid characteristics. For certain fluids, pressure decline causes thermodynamic changes (such as solids precipitation or significant liquid dropout) which can significantly alter well productivity, ultimate recovery and project economics. In aging reservoirs, fluid movements are of constant focus and routine cased hole logs are common to track such changes. Location of news wells for bypassed/remaining oil is equally important. In certain environments, conventional open hole logs may not fully resolve the fluid content of stacked reservoirs. In Kalimantan, Indonesia, it is common to have low resistivity pay zones which can contain significant amount of hydrocarbons. Also, the well known density-neutron separation may not always result in water free hydrocarbon production. Coupled with reservoir and fluid complexities above, often zones with unwanted fluids are perforated. Selectively testing each producing layer to identify fluids using conventional surface test equipment is a viable approach but can be costly.

fax 01-972-952-9435. AbstractFluid identification is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer modules helped understand reservoir fluid characteristics, identify production zones and optimize perforation zone selection.