Majority of the oil and gas fields in the UAE are mature multi-layered carbonates reservoirs, which determines complex vertical heterogeneity and challenging development of those reservoirs. Conventional methodology to measure sublayer pressure is to utilizing different wireline formation testers for any new well or worked over well before commissioning for production. Once well is completed and put on production; usually the average reservoir pressure is measured at the depth of perforation using conventional pressure build up (PBU) or bottomhole closed-in pressure (BHCIP) methods. Using conventional approach it is always difficult to understand which layers are more depleted than others, as only average reservoir pressure is recorded in the wellbore. In case of the heterogeneous multi-layer reservoirs, pressure measured conventionally in the wellbore will be at most of the times, inadequate for sublayer pressure estimation. This paper will describe new methodology of formation pressure evaluation, as well as real case study done in one of the developed offshore carbonate field in the UAE. This method allows measuring each sublayer pressure for producing wells without interruption of the production and properly defining any differential pressure between sublayers. This will help when applying any gas shut-off or water shut-off techniques and prolong the life of producing wells, as well as to help future development of the field. The determined reservoir pressure for each layer has been compared with recent formation pressure tester measurements obtained for this well. The pressure measurement is in the range of 20 psi tolerance. Identification of sublayer reservoir pressure for each producing interval is vital for highly heterogeneous multi-layered reservoirs. This technique is important for gas and water production management when one or several sublayers become depleted. Appropriate action for gas/water shut-off technique can be applied in the right time which will help to manage reservoir efficiently, as well as reducing the cost for conventional pressure measurements and eliminating the loss of production due to shut in time for pressure stabilization during conventional BHCIP or PBU.
Managing mature fields effectively and efficiently requires monitoring changes in formation fluid saturations as well as production from individual wells. Reservoir saturation monitoring is usually performed using slim pulsed neutron logging (PNL) tools because they can be deployed through tubing and operate in different modes, thus providing a wealth of information. However, several environmental factors can complicate the analysis, including complex completions and unknown or variable borehole fluids (gas in particular), which affect the PNL raw measurements and computed outputs. Factors related to the nature of the reservoir, such as complex lithology and multiple fluid phases, further complicate the analysis, making accurate fluid saturation evaluation and reservoir fluid-front mapping very challenging. An innovative pulsed neutron technology, recently introduced in the UAE, can help in reducing the evaluation uncertainty. The new device is fitted with multiple detectors and is used with newly developed algorithms to provide self-compensated formation sigma and hydrogen index (HI) measurements, overcoming many of the limitations of previous devices in complex environments. Additionally, the new tool provides a new formation property sensitive to gas-filled porosity, called the fast neutron cross section (FNXS), which, in adequate conditions, can be used to complement the analysis or highlight gas in the absence of openhole logs. The new PNL tool was run for the first time in an offshore UAE mature field targeting Jurassic formations. The production in the field started in the 1960s, followed in the 1970s by down-flank injection of water with much lower salinity than the connate water, and in the 1990s by crestal gas injection. The Jurassic reservoir mineralogy is a complex mixture of calcite, dolomite, and anhydrite. Completions consist of multiple combinations of tubing, casing, and hole sizes along with packers and other hardware components; often the borehole is filled with gas across the zones of interest, which has proven an obstacle to PNL interpretation. The new PNL device was tested in several wells in which it operated in inelastic gas, sigma, and HI (GSH) mode and carbon/oxygen (C/O) mode. Integration of all the recorded information made possible to reliably track the three-phase fluid saturation changes even in the gas-filled wellbores with complex completions. An additional benefit with the new tool was that because the C/O data were recorded at a speed twice as fast as that of the previous-generation PNL tool, it was possible to acquire the logs in the limited allocated time to help resolve the oil saturation in reservoir zones with variable salinity. The saturation analysis was compared to production logs and well production data where available.
Pulsed neutron reservoir saturation monitoring logs are being acquired since the early stages of the subject offshore field life to monitor variations of saturation with time in addition to identifying pay zones for well intervention and reactivation operations. This is important given the increasing complexity of reservoir management due to water and miscible gas secondary and tertiary oil recovery schemes adopted by the operator. However, with the introduction of new pulsed neutron technologies and resource limitations, a benchmarking exercise was imperative to confirm data quality and identify any discrepancies in the recorded data. Two candidate wells were selected based on the maximum Jurassic reservoir units coverage, including a group of lithologies (limestone, dolomitic limestone, anhydrite etc.) and borehole environments (single to multiple casing/tubing, cement and borehole fluids) to establish different correction parameters. The study was conducted with back-to-back logs utilizing current and new pulsed neutron tools from different service providers. In addition to the comparing the changes of formation capture cross section (SIGMA), borehole salinity, sigma and porosity measurements against the logging environment and changing completion hardware, three-phase fluid interpretation products were compared. The results were validated via well performance and production logging data. The approach is trying to support the reservoir saturation monitoring end users within the asset units operating in mature carbonate fields to design their time-lapse analysis methodology and to minimize the fluid saturation interpretation uncertainties, and as a result improve confidence in fluid front mapping and infill well planning.
Reservoir Surveillance is made increasingly difficult in mature offshore oilfields that contain a large number of wells with all associated infrastructure. While logging requirements are increasing in order to sustain production from the field and maintain well integrity, the production requirement is increasing and the operational cost has to decrease. These challenges are additional to the existing constraints due to resource limitations in an offshore environment: winch boats for equipment movement, slickline units for downhole safety valve retrieval and tubing checks as well as offshore living accommodation limitations are major factors any of which can cause a halt of rigless logging campaigns. A new digital slickline unit was used to replace the conventional practice for rigless wireline logging operations in offshore fields (wellhead towers). The old method involved a slickline unit to perform the pre-job and post job work. That's in addition to the logging unit that performs the required production logging job. This process involved a lot of winch boat moves, personnel and shut in days resulting in loss of production between moves. This digital slickline unit combines the capabilities of a slickline unit and a logging unit. The type of slickline it uses allows sending commands to logging tools downhole and receiving data on the surface data acquisition system while logging. The new approach had multiple operational, financial and HSE&Q impacts. Operationally, performing production logging operations using this digital slickline unit minimized logistics compared to conventional production logging (4 lifting loads Vs. 14 lifting loads). It has also reduced the operation time and trips to and from wellhead towers which resulted in reducing production losses. It also helped achieving the increasing annual logging and slickline KPI's without compromising data QC. Furthermore, HSE&Q was addressed by providing a solution for some integrity concerns related to wells being left with no downhole safety valves between slickline and logging unit movements. Moreover, the probability of incidents caused by improper handling of equipment and tripping/slipping hazards was reduced and most importantly, the option of Medevac by chopper became available in emergency cases due to the reduction in the occupied tower area. This breakthrough in logging operations from offshore wellhead towers enhanced the operational quality and reduced cost. It represents a part of the continuous efforts to reshape the concept of production and reservoir surveillance (which includes well testing, pressure surveys, etc) by applying new technologies and following new approaches to allow fulfilling larger requirements without making compromises on HSE&Q, production requirement and cost efficiency.
Changing oil field development economics has pushed the trend towards developing multilateral wells to increase production and maximize oil recovery utilizing advanced well configurations. However, to focus on maximizing the value of multilateral wells by addressing reservoir and production challenges; efficient reservoir management has remained a challenge. Accessing multilaterals has not been possible with conventional Coiled Tubing logging techniques. Current available technologies for deploying Production Logging services in the multilaterals are of less success, due to hardware limitations. The challenge was to access slim hole laterals from the mother bore in order to perform reservoir surveillance activities namely production logging as well as acidizing operations in laterals previously inaccessible. The information gathered from this intervention would improve the overall understanding of the reservoir and well behavior thus enabling the operator to manage the multi-lateral wells’ individual drains, ensure production assurance and sustainability and revisit the development plan for the tight reservoirs based on proper reservoir evaluation. With the introduction of a new lateral intervention tool, the operator was able to successfully access a lower drain drilled from a window in the casing with efficiency and certainty. The smaller size tool used on this operation had an OD of 2 1/8", which is ideal for accessing laterals in wells with slim hole completion. The tool helped in accessing the lateral and provided the operator the opportunity to perform production logging operations. This had previously not been possible with conventional technology which was attempted numerous times without success. The need for mobilizing a rig was prevented in addition to the reduced foot print of the required equipment and personnel required reflect substantial reductions in time and cost for this intervention. This paper introduces the knowledge learned from the world’s first multi-lateral accessibility and production logging operation in the UAE by applying a new multi-lateral accessibility on Electric Coil Tubing through detecting the multilateral window and activating a powered arm for entry into the lateral section.
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