The objective of this paper is to communicate lessons learned, best practices and process enhancement initiatives identified during an actual implementation of Integral Wellhead Gas Compressor technology. The compressor installation was a technology trial test in a challenging high condensate sandstone environment in a conventional gas field. Several technical lessons learned were identified especially in the areas of liquid handling, produced solids management, as well as downhole well intervention requirements. The methodology was based on collecting and documenting operational challenges and their root causes and corresponding technical solutions as the project progressed. In addition, a benchmarking study was conducted to identify additional areas of improvement to address the root causes of these challenges. Addressing these challenges by implementing the lessons learned highlighted in this paper will ensure expedited project delivery at a reduced cost. Examples of such challenges include unexpected severe liquid slugging, high amounts of solids production, as well as corrosion resistant alloy (CRA) metallurgy requirements. The benchmarking study resulted in the identification of several areas of potential improvement and multiple engineering process enhancement initiatives were recommended. Examples of such initiatives include the utilization of integrated Liquid Handling System (LHS) to mitigate severe liquid slugging and reduce assembly lead-time. In addition, the utilization of surface cyclonic sand filter systems to mitigate solids production. In addition, conducting downhole tubing drift runs to ensure no restrictions are present that can reduce compressor performance along with several other relevant initiatives. In summary, the paper provides a deep dive into several technical operational challenges during the actual implementation of wellhead gas compressor technology in a challenging high condensate sandstone environment. Also, several new initiatives are proposed in this paper with the objective of achieving significant cost savings. It is intended for these initiatives to be adopted as best practices not only to yield cost savings but also to supplement the existing best practice literature in the areas of liquid handling, solid management systems, quality control and well intervention.

The objective of this paper is to communicate operational and engineering process enhancement and cost saving initiatives in advanced well completions. The initiatives were identified following a detailed review of industrywide advanced completion best practices standardized over the past decade. Several operational and engineering best practices involving inflow control valves (ICVs), inflow control devices (ICDs), zonal isolation (mechanical and swell packers), multistage fracturing (MSF) and sand control technologies were examined. In addition, downhole pressure relief requirements were also considered to introduce new ways of enhancing well integrity by preventing casing corrosion. A standard research and development methodology was utilized for this review. The methodology was based on collecting and documenting industrywide actual operational and engineering challenges in advanced well completion deployments for both oil and gas fields. These challenges resulted in either lost time at the rig site, necessitated workovers, or rigless operations. Examples of such challenges include extreme frictional forces during ICD deployments, repetitive solids removal practices prior to running ICVs, coiled tubing milling requirements for MSF, wash pipe deployments for downhole sand screen circulation, and calcium carbonate scale deposition in sand screens. The research also encompass a literature review for identifying further advanced completion challenges across the industry. The review resulted in identifying several areas of potential improvement. As a result, multiple engineering and operational process enhancement initiatives were recommended. This includes the utilization of centralizers to reduce frictional forces in ICD deployments. Also, the application of isolation valves to eliminate wash pipe requirements in screens or ICDs. Moreover, running downhole annular relief check valves to preserve tubular integrity by eliminating casing-to-casing annular (CCA) pressure communication and utilization of mono-bore ball seat technology to eliminate milling in MSF. Finally, the utilization of sacrificial completion accessories to improve ICV cleanup practices and save rig time in addition to several other relevant initiatives across the industry. In summary, the paper provides a deep dive into several technical advanced completion challenges across the industry. Also, several new initiatives are proposed with the objective of achieving significant cost savings. It is intended for these initiatives to be adopted as new advanced completion best practices. Not only to yield significant cost savings, but also to supplement the existing best practices body of literature in the areas of ICVs, ICDs, zonal isolation, MSF, well integrity and sand control technology.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA lab study was conducted to evaluate the performance and optimize different sand screen sizes currently being run in Saudi Aramco Gas Fields. The study was inclusive of three phases, Phase (I) was to analyze the retention capability of the different sand screen sizes against formation core samples from Gas Fields-A, B, C and D. Phases (II) and (III) were mud filter cake permeability damage/clean up tests in "Well bore collapse" and "Open annulus" scenarios respectively. For all three phases, different sizes of premium sintered meshes were selected along with a wire wrap screen.

The Shaybah oil field (SHYB) is located in the southeast area of Saudi Arabia and it's where Saudi Aramco drills the most complex multilateral wells and runs the most advanced intelligent well completions. The target reservoir is the "Shuaiba," which is an extensively drilled carbonate reservoir. Also, the geomechanics and overall stresses of the Shuaiba were characterized back in 2001 in a study, which concluded that the maximum horizontal stress orientation in SHYB appeared to be north - south and that the magnitude of this stress is only slightly greater than, or equal to, the minimum horizontal stress making up what is known as a normal faulting stress state (Geomechanics International)2. Consequently, due to the limited amount of data that was available back in 2001, the conclusions regarding stress orientation would need to be confirmed as additional data becomes available. And nowadays, after 14 years of development, a larger set of data has become available. Therefore, the purpose of this paper is to supplement the results of the previous geomechanical study performed in 2001 using recent drilling data from 100 wells drilled after the previous geomechanical study was conducted. In other words, this paper uses the findings of recent hole stability data from 100 wells to confirm the earlier suggested normal faulting stress state. And based on the findings of this analyses, there was no strong evidence to suggest that the hole becomes significantly more stable when drilling along the maximum horizontal stress direction (N-S) or conversely, becomes significantly less stable when drilling in any other direction, especially in the minimum horizontal stress direction (E-W). This finding confirms the normal faulting stress in SHYB and that hole stability does not vary greatly with drilling azimuth for this specific field. Most of the last 100 wells drilled in SHYB were drilled along the NE - SW directions of the field. And from 84 wells drilled along the NE - SW directions, only six wells experienced hole instability. Also, out of 11 wells drilled in the N or S direction, which is the maximum horizontal stress direction, no hole stability issues were recorded. Out of the seven wells drilled in the E or W direction, which is the minimum horizontal stress direction, only one well experienced hole instability. Therefore, the findings of the analysis show that there is no strong evidence to indicate that significant hole stability improvement is achieved by drilling in the maximum horizontal stress direction. In conclusion, this paper discusses the results of a field wide case study performed using the drilling data of the last 100 wells drilled in SHYB. The available data seems to confirm the normal faulting stress state that was earlier suggested for the SHYB field. With this confirmation of stress orientation, the expectations for hole stability are improved and this reflects positively on well planning and overall field development.

A well completion diagnostics methodology was developed in order to detect downhole packer leakage and plugged Inflow Control Devices. This methodology was based on integrating production logging tool (PLT) data with computerized ICD well centric modeling to identify packer leakage and plugged ICD’s in compartmentalized completions. This approach was implemented on several oil wells with the objective of trial testing new zonal isolation technology and to optimize oil flow from the different ICD modules. Optimization is achieved by identifying and solving problems such as packer leakage which negatively affects the performance of oil wells by preventing the isolation of water downhole increasing the water cut of the produced oil. It also identifies ICD plugging which introduces mechanical skin that reduces or completely prevents oil production in the corresponding plugged ICD modules. The diagnostics method described in this paper utilizes direct comparisons of ICD well centric modeling with actual production logging data and openhole formation logs to identify abnormalities within the ICD completions. The resulting information obtained is valuable and can be used in trial testing new packers to gauge their sealing ability in downhole conditions and is also useful in identifying areas of potential improvements within the completion. The implementation of this approach on several Saudi Aramco oil wells resulted in confirming the sealing ability of various mechanical and swell packers in addition to downhole constrictors. Furthermore, a potentially plugged ICD was identified for possible future remedial treatments to restore production. The significance of the subject matter is that it offers the petroleum industry a systematic approach to identify packer leakage or potential ICD plugging. Such an approach is needed to ensure that equipment being run downhole is functioning as per the design. Otherwise, ICD plugging or packer leakage can be identified for possible work over operations.