First Field Applications of Downhole CO2 Measurement in Asia Pacific

Asia Pacific Oil and Gas Conference &Amp; Exhibition

et al. 2009

Reservoir fluid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. Gas condensate reservoir is well known for its complex behaviour due to the nature of a near critical fluid. The reservoir pressure and temperature in such reservoirs are very close to the critical point, and therefore, small changes in reservoir condition will result in a change of fluid properties considerably. As a result, there exists a broad spectrum of reservoir fluids in this reservoir condition. Identifying reservoir fluid in the zones of interest is extremely challenging, especially when it is associated with overpressured low porosity shaly sandstone reservoir. It becomes difficult and at times impossible to definitively identify different types of formation fluids from the well logs alone. This paper presents challenges of fluid identification process during the exploration/appraisal campaign in such reservoirs, offshore Malaysia, where the operator needs to gather as much information and as quickly as possible to make immediate operation decisions and Field Development Plans (FDP). First part of this paper demonstrates an integration of available data including mud logs, gas chromatography, gas wetness ratio, well logs, formation pressure and DST in order to determine fluid types in a well where an expected reservoir fluid is oil. The result from a systematic integrated reservoir characterization performed later, however, has found that the reservoir fluid is gas condensate. The second part shows an extensive application of Downhole Fluid Analyzer (DFA) in the Wireline Formation Tester (WFT) tool to conclusively identify reservoir fluid types and their properties in-situ and in real time in the second well drilled in a different fault block. In this case, the use of WFT together with DFA has allowed identification and PVT property determination of a full range of downhole fluids including gas, retrograde gas, volatile oil and black oil. This suggests a number of compartments in such complex reservoirs. Introduction Reservoir fluid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. In thick, porous and clean reservoirs, the process of fluid identification is straight forward. Initially, the bulk density and neutron porosity logs are used in combination with resistivity logs to identify reservoir fluid type. In clean reservoir, density porosity log will overlay neutron porosity log in water zone. In hydrocarbon bearing zone, density and neutron porosity logs will start crossing over each other. A very large density and neutron porosity log crossover together with high value of resistivity suggests that the formation is gas bearing. Normally, formation pressure gradients obtained from wireline formation tester (WFT) tools greatly help in identifying fluid types.

Fluid Identification Challenges in the Near Critical Fluids: Case Studies in Malaysia

Kyi

Yahaya

Asia Pacific Oil and Gas Conference &Amp; Exhibition

et al. 2009

Success Story of Downhole Fluid Sampling in a Very Challenging Environment in the Gulf of Thailand

Kanjanavasoontara

SPE Asia Pacific Oil and Gas Conference and Exhibition

Yimyam

et al. 2010

Traditionally, the Gulf of Thailand (GoT) has been known for high temperature, small borehole size, variable CO2, and highly compartmentalized reservoirs. In particular, it is a very challenging environment for Wireline Formation Testers (WFT). Owing to cost constraints, since the start of exploration and development campaigns in this area, usage of newer technologies has been highly selective. However, this has been changed significantly in the past few years where the right WFT technology has been applied to the right environment. This paper is the first to present a work process to derive clean fluid sampling in the very challenging environment of the GoT. Time per station used to collect downhole fluid samples using WFT has been a major concern for a costly offshore operation. In addition, borehole stability is also another factor limiting WFT time. Given the time constraint, collected fluid samples usually have high drilling mud filtrate contaminations, in the ranges of 25 to 85wt%, and have not been suitable for further laboratory analysis and field development purpose. Balancing between the time used for fluid sampling and the quality of the collected fluid samples is not a simple task to manage. This paper shares a successful story of downhole fluid sampling in exploration wells for one of the operators in the GoT. Instead of using a conventional probe with one Downhole Fluid Analyzer (DFA), the concentric shaped probe with two synchronized pump-out modules and two DFAs are used in this case. However, this is not as simple as other fields already presented in the literature because an unconsolidated sand character introduced complications into this sampling technique. Several attempts have been developed to make focused sampling work in these challenging environments. At the end, "Less than 5% OBM contaminated samples in oil reservoirs are successfully achieved in a timely manner." The average time used per each sampling station is approximately 30 minutes. This paper will also discuss the advantages and disadvantages for each technique applied and the final results. In addition, more improvements have been suggested to enhance this focused sample technology in more complex fluids, such as gas condensate reservoirs to make sure that less contaminated fluid sample can be collected in the limited time per station

Is There A Better Way to Determine The Viscosity in Waxy Crudes?

SPE Asia Pacific Oil and Gas Conference and Exhibition

Fujisawa

Chokthanyawat

et al. 2012

Accurate viscosity measurement is difficult even under the best of conditions and the lengthy time required to send and receive results from a lab prohibit basing important decisions on the viscosity of the reservoir fluid. Those challenges increase for reservoirs with complex fluids such as the highly viscous, waxy crudes found in many of the oil fields in South East Asia. While correlations have been developed to determine the viscosity of waxy crudes, the accuracy can be limited under certain conditions. The objective of the paper is to review visc sity correlations for waxy crude and examine their applications to the actual field data. Limitations on the use and accuracy of these correlations will then be discussed. This paper also discusses the viscosity obtained in real-time from the suite of Downhole Fluid Analysis (DFA) measurements, and the result is then compared to standard PVT analysis over a wide range of viscosities, temperatures, and pressures. Results of the DFA viscosity measurements in several fields in South East Asia are discussed together with other fluid properties such as GOR, density, and fluid compositions. The viscosity is then examined at the field scale to help understand the reservoir complexity in terms of compartmentalization in these waxy oil environments. The technical contribution from this paper is that it presents the variation of the viscosity in waxy oil reservoirs and its impact on real time decision making, especially for purposes of pressure transient analysis. This paper covers the evolution of the DFA viscosity measurement including a description of the hardware, discusses the limitation of the DFA measurement for certain conditions, and summarizes the accuracy of the DFA viscosity measurement for different fluids and the ongoing development for covering more fluids in the lower end of the viscosity spectrum.