PETRONAS Carigali Sdn. Bhd. (PCSB) operates a handful of small platforms at offshore Peninsular Malaysia, in the Malay Basin area, located in the South China Sea. Most of these platforms were designed with limited crane capacity of maximum 5 MT load and small deck space area that only suffice to accommodate slickline operations. After many years of production, the fields have started experiencing sand production, high water cut and a large skin factor. Thus, well interventions and treatments such as matrix stimulation, water shut off or sand clean out are required to sustain and enhance the production rate.Coil tubing (CT) well intervention is the most effective method to achieve these objectives. However, with limited platform facilities, it is a tremendous challenge to have big CT equipments catered on board. The solution to this is to have a minimal number of equipments on the main deck whilst the crane lifting will need to be done from the barge. CT operation with barge assistance was evaluated and finally opted for to execute the jobs at PCSB's small fields. Throughout the operation, only the coil tubing injector head, jacking frame and CT control cabin were erected on the platform whilst the remaining equipments were stationed on the barge.As this was the first CT barge assisted operation in the Malay Basin of South China Sea, two platforms were selected for the pilot campaign. The jobs objectives include water shut-off, wax and sand clean out that has a potential enhancement of 1000 bbl of crude. This paper describes the operational success stories, campaign preparation, proposed work programs, barge selection, jobs execution and project lessons learned.

Malong is part of an integrated marginal field developed in 1999 called MASA. Hydrocarbon is evacuated to a nearby Floating Production, Storage and Offloading (FPSO) facility for export. Its produced water system is currently being used up to its maximum design limit and hindering additional oil production. Malong main reservoir J2 contributes about 97% of the total production. Currently, 7 wells are producing at 7.7 kbopd with average water cut of 70 percent. 88 percent of 18 kbwpd comes from 5 deviated wells while the rest is from 2 horizontal wells. J2 is a water injected reservoir with moderate to strong aquifer. This high permeability sand is distributed fairly well across the field and is subdivided into upper and lower lobes. A comprehensive diagnostic of water flow entry mechanisms begins with compilation of critical information such as geological and reservoir data, production and injection data, cased hole data and well history. Subsequently, several analytical techniques such as material balance analysis, water control diagnostic plot, bubble maps and nodal analysis are applied. The water production mechanisms are primarily dynamic contact movement due to production and possibly accompanied by flow behind casing. In all the wells, the lower lobe is mostly flushed leaving some oil from upper lobe only. Screening of suitable water shut-off methods gets complex considering tubing integrity issue, i.e. multiple tubing leaks, poor cement bond and possible deep invasion due to high permeability formation. Detail evaluation is performed to weigh the pros and cons of mechanical type (cement squeeze) and chemical type (polymer gel). Finally, polymer gel is selected on the basis of less operational risk, controlled depth of invasion and easier removal. Additionally, coil tubing with packer is selected as the deployment method to ensure accurate placement of gel and to evade chemical loss through leaks. Introduction This paper is intended to outline the processes and challenges that were encountered in understanding the produced water problem and in designing the appropriate water shut-off methods considering the physical limitations of facilities as well as tubing integrity. The work has actually started since end of 2004 with downhole data gathering for some of the wells. More efforts were put into understanding the problem and coming up with practical solutions as more water are produced and putting higher constraints on the facilities. Understanding the Problems Without doubt, the first step would be to understand the problems in hand. Water has been produced together with oil since the beginning and the facilities on FPSO are designed to handle the produced water without jeopardizing the oil production. This is anticipated since Malong J2 reservoir driving mechanism is moderate to strong aquifer drive with water injection for pressure maintenance. However, the actual water produced has exceeded the design capacity and thus prompted effective water control measures to be in place. The reservoir water flow mechanism needs to be well understood to enable effective implementation of water control measures. In addition, the economics of selected measures are imperative so as not to erode the profitability of the operation.

This paper serves to share the findings and best practices of sustaining production for a mature field with high sand production with analysis from Acoustic Sand Monitoring (ASM) paired with Online Sand Sampling (OSS). Field B, located in the East Malaysia Region, is a high oil producer for over 40 years under a strong water drive mechanism. Water production has significantly increased over the past 5 years, which has led to significant sand production impacting surface facilities and well integrity. Hence, the need for a reliable and efficient sand management surveillance in field B. As the first application for oil fields in the region, ASM and OSS was conducted with the objective to determine the maximum sand free production rate from over 80 active strings in Field B over the span of 4 months to safeguard production rates of 10 kbopd. With ASM and OSS, a reduced data surveillance duration can be achieved within 2 hours compared to conventional well sand sampling per well which requires a minimum of 24 hours before sand production rate is determined. ASM sensors are clamped on the well flowline to detect and record the noise vibrations produced by the sand while OSS is conducted concurrently by diverting parts of the same flow from the flowline through a sand filter to have a quantitative representation of sand produced for a predetermined duration. During the campaign, choke sizing was manipulated to control reservoir drawdown. For most wells, a lower drawdown resulted in lower amplitude readings from ASM and less sand observed from OSS. However, there are several wells that had higher sand production at a smaller drawdown due to a change in flow regime (steady flow to intermittent flow) resulted from inefficient gas lift production (multi-pointing). As ASM provided the raw velocity signal which is heavily influenced by the liquid flow regime, gas oil ratio and sand production, OSS results (from physical sand produced and weight of sand particles) established a baseline for ASM signals which indicate a sand free production. Overall, ASM and OSS analysis provided a baseline for determining the optimum rate of production with minimum sand to avoid well integrity issues and protecting the surface facilities, thus allowing continuous field production of 10 kbopd. A presentation and discussion of the successful results, limitations, best practices, and lessons learnt of the ASM and OSS campaign aspires to be additive to the production surveillance sand management in the oil and gas industry by providing a fast and reliable means of identifying optimum sand free production rates for a high number of wells in a mature field.