Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. The major reservoir zones are Pereriv sandstone formations with 20-25% porosity, permeability 100-1000md, and oil column up-to 1000m. These formations are weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. Development began in 1997 and to date more than 70 high rate (up to 45mbd per well) OHGPs have been installed.Wellbore stability issues require OHGP screens to be run in Oil Base Mud (OBM). Despite excellent initial success a number of sand control failures began to occur in 2008. A detailed gravel pack evaluation using multiple wash pipe gauges have revealed that earlier installations experienced screen plugging on lower section during the installation process. This leads to an incomplete pack in the toe area and subsequent screen failure as depletion increases or once water breakthrough occurs. The ultimate risk is of lost production rather than well control or loss of containment.Analysis was done to understand the root causes of screen plugging and to develop solutions for each. The work resulted in five key changes being made to the OHGP completions. o Revised TD criteria for the open hole section. o Modified OBM conditioning procedures. o Modified wellbore-clean-out procedures. o A modified screen BHA design. o The use of Ultra-Fine-Grain Barite in the OBM to reduce barite sag and the amount of large solids in the fluid system.These changes have resulted in less screen plugging, and hence increasing pack efficiency across the productive interval. This has resulted in a step change in OHGP reliability in the last 3 years with zero sand control failures over the last 24 completions. The detailed understanding of the failure mechanism also facilitated a successful intervention campaign to remediate several failed OHGP wells pre 2008. These efforts have delivered ~60mbd reduction in production losses over the past 2 years.

A gas-bearing carbonate reservoir was found spread over the Offshore West Java (OWJ) field, Indonesia. A new area in the field, the APN area, has been successfully developed recently to recover gas from this reservoir. The APN reservoir is a shallow (~1500 ft), low pressure (~700 psig) carbonate reservoir with 70 ft net pay, comprised of foraminiferal grainstones and packstones, having excellent reservoir quality with average porosities of 38% and permeabilities of up to 1000 md. Unlike any other carbonate reservoir in OWJ, the carbonate reservoir in this area is very weak. An evaluation of solid production potential suggested that the well should be completed with solid control since the formation rock has failed and there is no allowable drawdown pressure. It would require compliant borehole support and a large inflow surface area to minimize drawdown. It also needed to be screened to mitigate solids production. A Horizontal Open Hole Gravel Packed (HZOHGP) was chosen as the optimal solution for particle size range, cost and long term integrity. Five horizontal wells were drilled and successfully completed with a 1,000 ft open hole section and 7-inch production tubing. The gravels were placed using circulating pack (alpha-beta wave) technique. All the wells were started-up smoothly and each well could deliver 40 MMCFD, which is quadruple conventional well production. No solid production was observed. This paper discusses the design phase, execution, start-up and results. It also shows how, through integrated multidiscipline team work, the previously marginal APN field could be developed with good economic results using the implementation of several new technologies. Background The APN field was discovered in 1968 with the A-1 well by ARCO. It is situated within the Offshore North West Java PSC (ONWJ) of which BP is the current operator. The APN Development was sanctioned in April 2004, thirty six years after the field was discovered. The field was previously categorized as economically marginal, but through multi-dicipline evaluations and applications of the right technologies, the field has been turned into a world class field with good economic margins. The APN consists of three separate gas fields (water depth 45m) in the northern area of the ONWJ PSC (Production Sharing Contract). It is a remote field located approximately 70 km north of Jakarta and 40–50 km north of the nearest infrastructure at Papa flowstation. Figure 1 - ONWJ Field Location This asset is strategically located to supply cost effective gas to PLN's (Indonesia's nationalized power generator) power plants in the Jakarta bay. ONWJ is in its late life and the strategy is to efficiently harvest the remaining oil reserves while sustaining gas production. Significant compression and export infrastructures exist that enable BP to produce the remaining gas reserves with quality margins. Five horizontal wells were drilled to develop the reserves from this field. The project achieved first gas on August 17, 2005 and is now successfully in production, delivering 40% of the gas production in West Java underpinning the assets and economic viability.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractSubsidence and reservoir compaction continues to be significant concern for the oil and gas industry. The decrease of pore pressure during hydrocarbon production (depletion) leads to compaction of the reservoir. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. The results of stimulation efforts to improve gas deliverability in carbonate reservoir experiencing subsidence in Offshore North West Java (ONWJ) field are presented here.The wells in this study were completed in the Parigi Formation, which is a thick carbonate buildup formation with large columns of gas about 250-300 feet thick underlain by aquifer. It has high porosities (32-45%) and good gas permeabilities up to several Darcies with the initial well production were around 20-30 MMSCFD. The continuous production of gas from this shallow, thick and low strength carbonate reservoir has resulted in reservoir compaction, surface subsidence, several well mechanical failures and a sharp production decline (from 15 MMCFD to 2 MMCF). The other impact of declining gas rate that is nearing its critical velocity is causing water condensation that cannot be lifted out of the well; it then accumulates in the wellbore and creates more back pressure on the reservoir. Treatment efforts, starting from nitrogen kick-off with CT to unload the condense water in the wellbore followed by reperforation and acidizing job, that were conducted in the first two well have resulted a significant production response. Gas production increases by 4-9 times after the treatment. The previous fear/perception that acidizing would perhaps even worsen the conditions of the reservoir and thus reduce production proved not to be true. These successful treatments have led to stimulation campaigns for other wells in the area. This paper will also discuss several surveillance projects to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction and wellbore damage in this area.

Subsidence and reservoir compaction continues to be significant concern for the oil and gas industry. The decrease of pore pressure during hydrocarbon production (depletion) leads to compaction of the reservoir. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. The results of stimulation efforts to improve gas deliverability in carbonate reservoir experiencing subsidence in Offshore North West Java (ONWJ) field are presented here. The wells in this study were completed in the Parigi Formation, which is a thick carbonate buildup formation with large columns of gas about 250–300 feet thick underlain by aquifer. It has high porosities (32–45%) and good gas permeabilities up to several Darcies with the initial well production were around 20–30 MMSCFD. The continuous production of gas from this shallow, thick and low strength carbonate reservoir has resulted in reservoir compaction, surface subsidence, several well mechanical failures and a sharp production decline (from 15 MMCFD to 2 MMCF). The other impact of declining gas rate that is nearing its critical velocity is causing water condensation that cannot be lifted out of the well; it then accumulates in the wellbore and creates more back pressure on the reservoir. Treatment efforts, starting from nitrogen kick-off with CT to unload the condense water in the wellbore followed by re-perforation and acidizing job, that were conducted in the first two well have resulted a significant production response. Gas production increases by 4–9 times after the treatment. The previous fear/perception that acidizing would perhaps even worsen the conditions of the reservoir and thus reduce production proved not to be true. These successful treatments have led to stimulation campaigns for other wells in the area. This paper will also discuss several surveillance projects to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction and wellbore damage in this area. Introduction The Offshore North West Java (ONWJ) contract area was the first of BP's (formerly ARCO) concession areas in Indonesia. The area covers 6.8 million acres Offshore Northwest Java Island with water depth up to 50 meters, see figure 1. Production started from this area in late 1971 and was the first Indonesia offshore production. Currently, the field is producing around 45,000 BOPD and 250 MMCFD of gas sales. Starting in 1980's, BP (formerly ARCO) discovered a lot of gas potential in this area while exploring for oil. Major gas discoveries in this area were from Pre-Parigi, Parigi, Talang Akar and Main-Massive formations, which contain potential reserves up to 2 TCF of natural gas. The reserves are spread over 20 fields. Two of the main gas contributing areas are the KLX field & the adjacent KLY field, both of which were developed in 1993. The fields were developed into four production platforms (KLXA, KLXB, KLYA, and KLYB platforms) and consist of a total of 10 wells. The wells are typically completed in 9- 5/8" casing with 7" and/or 5–1/2" production string. These fields have excellent deliverability and constitute the backbone of the ONWJ gas supply program. These fields produce from the Middle Miocene Parigi formation at a depth of about 1,900 feet. Large columns of gas (about 250–300 feet thick) underlain by aquifers characterize the KLX and KLY reservoirs. The KLX reservoir is underlain by a 200 ft thick aquifer, while the KLY reservoir is filled to the spill-point and the aquifer is only 40 feet thick in certain areas. The fraction of gas in the total carbonate reservoir column is about 0.5 for KLX and 0.9 for KLY (1). The continuous production of gas from this shallow, thick and low strength carbonate reservoir has resulted in reservoir compaction, surface subsidence, several well/facility failures, and sharp production decline. The other impact of declining gas rates that are nearing critical velocity are causing liquid/water condensation, which then accumulates in the wellbore. It could not be lifted out and created more back pressure on the reservoir. This condensation water could be lifted out continuously if the production rate were above its critical velocity, ±2 to 4 MMCFD (based on M. Li et al. 15).

Almost all the wells in the Offshore North West Java (ONWJ) field penetratemulti-layer reservoirs. To accommodate reservoir management issues, most ofthese wells were therefore completed in multiple packer completions (dual orsingle string with multiple packer). As the field is getting mature, more wellsare becoming wet and consequently more wells are dying due to waterencroachment. Therefore, remedial actions to revive dead wells play animportant role to maximize the revenue. To address this issue, thru-tubingcement squeeze and polymer squeeze using coiled tubing have proved to beefficient methods to reduce water production by isolating watered out zones inthe ONWJ field. However, the operation of this job can be more complicated when done inmultiple packer completion or in dual completion cases, especially when thetubing has leaks in order to avoid the cement or polymer from penetrating otherplaces or productive zones. In several cases, the condition of old tubing thathas experienced deformation (buckling/collapse) has made the task even morechallenging. Therefore, treatment strategies must be designed carefully forsuccessful cement/polymer placements into the target zone without affectingproduction from the other string or zones. From 1999 to 2003, a total of 36 thru-tubing zonal isolation & watershut-off jobs utilizing coiled tubing were done with a high degree of success, although in many cases the tubing had leaks and mechanical problems. Severalmethods were used and modified to ensure proper cement or polymer placement.Through the use of the innovative "cement packer" technique and inflatablepacker, the jobs were accomplished successfully. The coiled tubing has provento be an effective solution to deal with well conditions in the ONWJ field. This paper will also discuss three case histories, with each caserepresenting different operational challenges. Field History The Offshore North West Java Production Sharing Contract (ONWJ PSC) area islocated off of the North Coast of Java Island in Indonesia. The firstexploration well was drilled in 1,967 and production first started in 1971.Throughout its 30 years of production history, 13 flow stations, 150 productionplatforms, 700 wells with 1,013 production strings have been built in a seadepth of up to 40 meters. Currently, the field produces around 38,000 BOPD with300 MMCFD of gas. The continuous decline of crude production is a challenge tothe company's goal of being a low cost offshore operator. Initially, the ONWJ fields produced dry oil and gas. Now, the field producesas much as 50% water cut. Many gas and oil wells have been shut-in due to waterout problems. This condition has challenged the company to find better ways inmanaging downhole water production and maximizing oil and gas production.Therefore, shutting-off the watered out zones and finding more by-passedreserves are the primary targets in this mature field. To achieve them, thecoiled tubing is used and has been proven as one of cost effective solution todeal with challenging well conditions in the ONWJ field. Zonal Isolation and Water Shut-off Operations The very nature of the oil & gas industry leads to the unwantedproduction of water that can seriously affect the profitability of the wells.Some of the methods and practices currently in use today to help eliminate thisproblem include, but are not limited to: placement of cement across the zone, plugging back the zone with the aid of mechanical isolation devices, pullingthe completion and performing a complete work-over. In the ONWJ field, due to the well architecture (multiple packers withsliding sleeve doors), most of watered out zones can be easily isolated just byclosing the sliding sleeve or setting a tubing plug. However in some cases dueto multi zone production, location of the zone, and the mechanical conditionsof the well, more advanced and complicated technology is necessarilyrequired.