Moving into electronic age, completion tool and accessories are getting advanced. For the past 10 years, permanent downhole gauge (PDG) technology has been supported with tremendous investment in its research and development. This pacing technology is no longer new to the industry oil and gas operators. Some operators have made it as standard practice but however, some operators are still performing financial model analysis to justify for PDG installation. Is it a real need to install PDG or it is just another fancy luxury that give limited financial returns to the project? How much data is required by petroleum and reservoir engineer to understand the reservoir? This paper presents in detailed about the financial model analysis and demonstrates the tangible and intangible benefit of the PDG and the added value to full field life cycle.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractDownhole sampling in gas condensate reservoir is well known to be challenging due to the nature of near critical fluids. Reservoir fluid properties can change dramatically with slight changes in reservoir pressure and temperature. As a result, accurate and representative PVT data are essential for reservoir fluid modeling and field development planning but difficult to obtain using conventional sampling techniques. This paper presents the first successful downhole gas condensate sampling in a high pressure gas condensate field, offshore East Malaysia. Samples collected from the previous surface tests showed large variation in Condensate Gas Ratio (CGR) from 50 to 200 stb/mmscf. This resulted in large uncertainty in the dew point pressure, condensate yield, well productivity, and reservoir fluid type. There was strong need to acquire high quality downhole samples to reduce these uncertainties, which can potentially affect the entire field development plan. Through the use of new technology and an integrated team approach, it was possible to take representative single phase fluid sample using controlled drawdown and real time fluid analysis of downhole sample.There were several key challenges in this operation. The team had to take single phase gas sample, with minimum contamination in a High pressure High temperature (HPHT) well drilled with Oil Based Mud (OBM), station time had to be as short as possible to avoid tool getting stuck, and have an initial estimate of dew point pressure and Gas Oil ratio (GOR) from downhole measurements. This was achieved using real time data monitoring and control of the entire wellsite operation from PETRONAS Carigali office. The latest downhole fluid identification tool was used along with focused sampling to minimize OBM contamination. This paper will highlight the effective use of various elements of new technology and team work.Fluid density measurement was found useful in answering some of the questions. It allowed comparison with optical fluid analyzer to provide an improved fluid identification. It also allowed to optimize the number of pretests and hence reduce the rig time and cost. By measuring the change in fluid density during clean up, the in-situ density tool also complemented other spectrometer based optical analyzers in determining the contamination level during sampling process.In this complex gas reservoir, there were potential reservoir compartments of different gas composition. Fluid samples from different zones confirmed the presence of such compartmentalization. The deeper zones showed much leaner gas composition compared to the shallower intervals. The knowledge of in-situ dew point pressure from downhole fluid analyzer was used to ensure a single phase gas sample during wireline sampling. This information was later used to design a well test to keep flowing bottom hole pressure above dew point pressure and thus obtain representative surface fluid samples. This paper demonstrates how a proper job planning, r...

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The loss of functionality of the surface controlled subsurface safety valve (SCSSV) due to blockage of, or damage to, the hydraulic control line can present a major problem to Operators. The subsequent loss of hydraulic pressure to the valve means the valve will close resulting in loss of production and hence alternative methods for re-establishing control of the SCSSV are required. Performing a full scale work-over to replace the inoperable control line can require major expense and may not be justifiable in a mature well, while installation of a velocity or dome charged subsurface controlled safety valve may not meet well integrity or production requirements. Hence the preferred alternative is to install a System to Restore Full Safety Valve Functionality that is cost effective, restores production, and maintains well integrity requirements. The Tubing Retrievable SCSSV on well C-02 in the Sabah water of East Malaysia lost its functionality due to a leak in the control line. The SCSSV body was also found to be leaking from tubing to annulus which resulted in the failure to successfully lock open the SCSSV. Initially a major rig work-over had been anticipated to pull the tubing and replace the safety valve and control line. This operation would have required the use of a Hydraulic Work-over Unit (HWU) to perform the work which would have incurred a major expense. An alternative method was proposed that would allow replacement of the safety valve and control line, and to straddle the leak in the SCSSV body without pulling the production tubing or making changes to the wellhead configuration. This alternative method was a unique concept not previously attempted by any operator in Asia Pacific. This innovative approach would involve four elements: Installation of a Lock Mandrel and Separation Sleeve to straddle the leak in the SCSSV body & hold open the SCSSV flapper. Installation of a Wireline Retrievable Subsurface controlled safety valve with wet connector to connect to a new control line installed through the tubing (WDCL Safety Valve) which is anchored and located in the Tubing above the Tubing Retrievable SCSSV by means of a packer system. A new control line and special control line connector installed from the wellhead to the WRSCSSV through the production tubing. A new penetration in the Wellhead Lower Master Valve for the injection of hydraulic power fluid to control the WRSCSSV. These 4 elements provided a unique solution and the installation was successfully completed under a severe deadline. This was achieved by a high level of cooperation and collaboration between all parties throughout all phases of the project including and not limited to the planning, design and installation. This paper will describe in detail the system components and the decision processes and evaluations that led to the selection of this alternative solution. The collaborative efforts between the operator and two major service providers will be examined and discussed and the installation procedure described in detail. The paper will describe why the successful completion of this project marks a significant milestone in the remediation of older producing wells.