Sporadic but significant drilling downtime, potentially linked to field-scale pore pressure anomalies, has occurred during drilling to a deep carbonate reservoir in North Kuwait. Some wells experienced well-control situations while some others suffered severe mud losses. The field data show that pore pressure can vary between 9 ppg and 19 ppg before a well reaches its target depth of approximately 15,000 ft (TVD). These observations require the establishment of a good understanding of the subsurface pore pressure in order to optimize drilling operations, assess reservoir risks and provide input for better well completions. Geomechanical studies, utilizing pore pressure and temperature data from downhole measurements, openhole logs, drilling records and lithological information, were conducted to explain the overpressure mechanisms. Analyses indicate that overpressure above the reservoir appears to result mainly from hydrocarbon accumulations and subsequent gas generation during hydrocarbon maturation where pore pressure has been measured to be as high as 15 ppg. However, due to variable sealing conditions and field-scale faulting and fracturing, the pore pressure can vary within the same field. Pore pressure close to overburden stress (~20 ppg) observed while drilling through underlying salt and interbedded anhydrite layers is caused by trapping of water released during gypsum-anhydrite phase transformation. In the reservoir below salt, pore pressure varying between 16 ppg and 17 ppg can be attributed mainly to hydrocarbon generation and buoyancy effects. Towards the bottom of the reservoir, pore pressure is slightly low and varies between 14 ppg and 15 ppg. The severity of vertically and spatially varying borehole breakouts suggests that variations in tectonic stresses are present on the field scale, which may impact the generation of stress-related overpressure. Moreover, the intermittent presence of anhydrite layers and stiff intact limestone beds may act as localized seals generating overpressure. Geomechanical analyses were subsequently used to constrain the contemporary stress state and fracture gradient profile. These helped explain hole stability issues experienced during drilling and assisted in planning future drilling operations. In addition, the data provided better quantitative input for reservoir risk analysis and well planning for the field development campaign.

During the second quarter of 2002 Petronas Carigali, the State Oil Company of Malaysia, embarked on a campaign to utilize Expandable Sand Screen (ESS®) in unconsolidated multi-zonal sandstone completions in the Baram and Alab fields, offshore Malaysia. The primary objective of the application of ESS® technology was to control sand in conjunction with minimum skin damage without encountering operational problems/constraints which are inherently associated with gravel packing as a means of sand control. A total of five deviated cased holes were equipped with ESS® with mixed results which have been documented in details in a previous publication by the authors (SPE paper # 80449). Further investigation revealed that the wells completed with ESS® have achieved satisfactory improvement in productivity. ESS® technology has now proven to be one of the best available sand control techniques for the Baram field. This paper will focus on Petronas Carigali's experience in ESS® technology implemented in a deep horizontal open hole section of a sandy well which is to be equipped with a gravel pack assembly in the upper section inside the cased hole section, thereby providing an excellent source of comparison between the performance of gravel packing and expandable sand screen technology. Installation of ESS® in well BA-47, being the first deep horizontal open hole application in Malaysia, was an operational challenge with a few lessons learnt which may be shared by other operators. The primary objective of the well has been successfully realized as evidenced by better than expected sand free production. The execution of ESS® installation was successful with some problems encountered while initiating the expansion process. After some modifications on the expansion string and mud/brine system, the expansion process was carried out smoothly. The secondary objective of the ESS® application was to assess/evaluate the enhancement/impairment of productivity of the well using ESS®, in comparison with the technique of gravel packing. The well is presently in the process of being cleaned up. Preliminary data indicates higher than expected production. PI and PBU tests are planned for the well as soon the well has cleaned up and/or stabilized. Introduction The Baram field is located about 25km NNW of Lutong, Offshore Sarawak in Baram Delta, Malaysia (Fig 1& 2). The main Baram field was discovered in 1963. Baram reservoirs are composed of many sand layers which are of Miocene age consisting of alternating sequence of sand and shale beds. The drive mechanism of the reservoir is strong water drive. Well # BA-47 was the first ESS® application in a horizontal open hole completion located offshore Malaysia. The previous wells from Alab/Baram fields were multi-zonal cased hole ESS® applications which were successfully executed. The well profile, trajectory, well overview, seismic cross-section and well diagram are shown in Fig 3, 4, 5, 6 respectively. There are two main reservoirs completed in this well which are I4.0 and I6.0 sandstones. Both the formations consist of highly unconsolidated & friable sands requiring sand control to produce the wells. The formation has a uniformity co-efficient of +3 and a sonic transit time of 110 μsec/ft. The average porosity, permeability and water saturation for these reservoirs are 29%, 1000 mD and 37% respectively (Fig 7). In view of the success achieved and lessons learnt from the previous wells, deployment of ESS® was preferred over Open Hole Gravel Pack (OHGP).

The Baram and Alab fields located in offshore Sarawak and Sabah, Malaysia, are composed of highly unconsolidated and friable sandstone reservoirs having multiple pay zones. The primary objective of the application of ESS® was to combat sand control problems while reducing well costs and simplifying operations by replacing gravel packing. The secondary objective of the ESS® application was to maximize productivity by eliminating / reducing skin damage which is inherently associated with gravel packing. Additionally, ESS® maximizes the wellbore radius by the expansion of the screen, facilitating the process of future well interventions and the application of "intelligent" well completions. Three wells in the Baram field were completed using ESS® with mixed success. The lessons learned from the Baram field were later utilized to optimize the methodology of application of ESS® in the two subsequent wells in Alab field. Experiences gathered by other operating companies e.g. Shell Brunei, Shell Expro and BP in the North Sea were also taken into consideration as a step forward in the learning curve to ensure successful installation in the Alab field. Further testing results performed by the vendor were also incorporated in the design and operational aspects of the wells. Consequently, ESS® has been successfully installed and overall objectives were achieved in the Alab field. Since the ESS® hardware was manufactured and installed by a single vendor, the exchange of data and information between various companies was easy to obtain. Study and research findings from the facilities of Shell and the vendor in Aberdeen and Houston were also incorporated in the design aspects of the wells that were completed in the Alab field. Due to the presence of pressure differential between the zones and contrasting reservoir fluid and rock characteristics it was necessary to produce the wells selectively with annular zonal isolation. Attempts to isolate the pay zones in the first well (BA-102) using Expandable Isolation Sleeve (EIS®) were not successful. However, modifications in the design for the subsequent wells (substitution of EIS® by EXP packers) yielded much better results and achieved well objectives. The primary objective of the ESS® application, i.e. sand control, was successfully achieved, based on the analysis of surface fluid samples. The wells are flowing at the expected rates. Sufficient well test / production data is not available on hand to assess the effectiveness of the ESS® in terms of impairment / improvement of productivity. Pressure build up (PBU) tests are planned in order to determine the extent of skin damage caused by the ESS®. Shell Brunei experienced satisfactory productivity index (P.I.) after completing their wells in S.W. Ampa and Champion fields, offshore Brunei1. Innovations and modifications of the existing equipment and methodology of application of ESS® technology are also proposed. These modifications generate cost savings and simplified deployment for the operator. Introduction As an emerging technology in well completions the application of Expandable Sand Screen (ESS®) is being accepted in the oil industry as a simple and reliable method of sand control with the additional benefit of improved well productivity. Previously, the sandy reservoirs of Petronas Carigali were completed by either gravel packing or fracpacking.

The unique Kimmeridgian-Oxfordian complex of unconventional and fractured carbonates has been tested to be prolific producer of gas, condensate and light oil in different wells discovered in various North Kuwait fields. The challenge is to characterize the complex reservoir flow system where critical reservoir parameters such as reservoir type, porosity and permeability characteristics, and production and pressure data can vary substantially. The relationship between the natural fractures and the tight matrix in controlling effective system conductivity in reservoir flow units are the key features which dictate the nature of inflow mechanisms thus the production performance. The paper deals with developing an effective methodology which integrates the variations in critical reservoir properties of the low porosity yet naturally-fractured carbonate reservoir. The drill stem test (DST) results in some wells were successful without stimulation, while in other wells the DSTs were unsuccessful in spite of advance and repeated stimulations, thus categorizing these plays as geologically-complex, tight gas condensate reservoirs where out of ordinary stimulation techniques may be needed to activate the fractured matrix. Pressure transient analyses and flow regime interpretation of the successfully-tested wells confirm the dual porosity flow-system and the fractured nature of the reservoir. In this paper, the authors will discuss a new integrated approach for understanding the production and pressure behavior in light of the unique unconventional reservoir characteristics along with the fractured reservoir properties. Dual-layer and dual poro-perm models for pressure transient analysis have been applied extending the previous study of relationship developed between the productivity index (PI) and the total organic carbon (TOC). The proposed integrated methodology can significantly improve the current approach to production optimization, reservoir management strategy, completion, and stimulation design in fractured tight gas condensate reservoirs in Kuwait as well as in other regions.

The scope of the pilot project was to test fiber optic sensor technology in deep High Temperature (HT-HP) reservoirs and evaluate the best available sensors in the market for real time monitoring of down-hole pressure and temperature (P-T) in such an adverse environment. The task team had selected the optical P-T sensors conveyed on fiber optic cable from a qualified vendor after a thorough evaluation, considering the harsh environment of these reservoirs. After selecting the vendor, the fiber optic system was custom designed and installed down-hole in a selected deep HT-HP well in the Raudhatain field of North Kuwait. The system was installed and commissioned in mid February 2011 and has been successfully working to date, providing real-time pressure and temperature data from the reservoir section. In this project the P-T signals captured by the optical down-hole sensors are transmitted through the fiber optic cable to the Reservoir Monitoring System (RMS) unit at the surface that is connected to the SCADA system. The SCADA system sends the data through Wi-Max to the Digital Data Gathering Centre in the Field Development Gas (FDG) office. The sensors are continuously providing reservoir data at a time interval as frequent as 60 data points per minute. The technology provided by the vendor for this pilot is found to be robust and reliable. The pressure and temperature sensors employed in this pilot have shown impressive resolution and dynamic response capabilities. Based on the results it is concluded that the pilot is successful and the system is recommended for future implementation in deep HT-HP wells of North Kuwait fields. The project involved manufacturing, shipping and procuring the material from the Far-East and the USA. It also involved modification of well head to accept fiber optic cable entry into the well bore and use of specially designed low solid content packer fluid. The pilot was considered successfully completed after monitoring for 180 days in the month of August -2011. In Kuwait Oil Company (KOC) this first fiber optic sensor technology pilot was conducted by Research and Technology (R&T) and Field Development Gas (FDG) with the coordination of Deep Drilling and other groups, in a deep HT-HP well with the primary objective to monitor two key reservoir parameters; temperature and pressure. The reservoirs in North Kuwait are complex soil bodies that have a high potential for condensate and gas. The continuous, real time understanding of these reservoirs is vital in order to optimize their exploitation; hence KOC adopted a strategy of deploying fiber optic monitoring systems.