Sand retention tests have often been used to select optimal screen aperture for standalone sand screen applications. The purpose is to select a sand screen that maximizes hydrocarbon production and minimizes sand production. There are two types of sand retention tests currently used in the industry, i.e., slurry and prepack sand retention tests. The former aims to simulate gradual sand production condition with an open annulus between the sandface and the screen, and the latter to simulate the condition where no such annulus exists. There are, however, no agreed industry standards on how sand retention tests should be performed and test results interpreted. This paper presents a combined experimental and numerical modelling study on sand screen performance. The objective is to develop an improved methodology for optimal sand screen aperture selection by addressing some of the limitations presented in the existing sand retention tests. A new sand retention test facility has been developed at CSIRO, incorporating a number of improvements into the design and experimental procedure. A key component of the improvements is the ability to separately measure retained screen permeability and sand pack permeability. Correlations have been developed between sand screen performance and key parameters of the sands and screen based on a large number of sand slurry retention tests. Furthermore, the sand retention process was simulated numerically using a 3D fully coupled Discrete Element (DEM) – Computational Fluid Dynamics (CFD) model. Parametric studies have been conducted to assess screen performance and to gain a better understanding of sand retention and production mechanisms.
In general, the use of standalone screen (SAS) completion has significant economic (cost saving) and productivity (skin) advantages compared to the conventional open hole gravel pack (OHGP) completion. However, SAS completion, especially in horizontal gas well with high potential of sanding typically suffers from premature failure due to sand erosion caused by high annular velocity near the heel section. This paper describes the work conducted to understand in detail and quantify the erosion risks on SAS in horizontal gas well and the proof-of-concept assessment of using swelling elastomer packers to segmentize the flow in the annulus as a mean to reduce erosion risks near the heel. The work involves carefully designed and selected experimental and Computational Fluid Dynamics (CFD) simulation work programs that focused on development of erosion model at room and elevated temperature, understanding and validation of sand screen failure using the developed erosion model, and CFD simulation and validation of gas flow profile in basepipe and annulus sections to understand the effect of flow segmentizers in reducing annulus velocity. From this work, an improved sand erosion model was developed based on the Cylinder-In-Pipe methodology for the sand screen materials and downhole sand Particle Size Distribution (PSD) combinations at room and elevated temperature. Conditions that led to the failure of sand screen filter due to erosion damage were also established through the Sample-In-Pipe experiments. Validation of erosion on one-metre length of screen shows that CFD, combined with sound experimental techniques, can provide accurate prediction of sand screen material metal loss due to sand impact. CFD simulation of gas flow in horizontal gas well completion were conducted in order to provide further insights and confidence in using flow segmentizers to control annular velocity. Finally, a pilot application of the concept in a gas field in Malaysia, based on integration of all the findings will be presented together with comparison to a similar well within the same field but completed with OHGP completion showing that the SAS with flow segmentizers concept has led to significant CAPEX savings and high well productivity.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn mature, multi layered reservoirs with commingled, dual string, and gravel packed completions, selecting reliable acid stimulation candidates has always been a challenge. Achieving a high success ratio under these conditions requires a riskbased selection process, supported by reservoir understanding and characterization.As the traditional workflow, acid stimulation candidate selection starts with a thorough production performance review. Production history is provided on a string-by-string basis, and nodal analysis modeled based on production performance. Perforation and completions are evaluated to identify any damage. Logs are then reviewed to evaluate mineralogy and petrophysics. In this workflow, candidate selection is refined by reservoir modeling to predict the production gain in field level and production decline prediction. A decision and risk analysis is conducted with a strong emphasis on range of probability evaluates all possible outcomes associated with success and failure ratio. An economic analysis is evaluated based on risk analysis. This workflow is developed and tested in Bokor field, off the coast of Sarawak, Malaysia.After acid stimulation campaigns spanning over 6 reservoirs, the results have yielded to 40% oil production gain. Six strings showed an increment in oil rate, a reduction in water cut and an increase in productivity. Overall, the fine tuned acid job design combined with visco-elastic surfactant diversion technique proved to be effective. This paper presents the comprehensive workflow developed and implemented by the Bokor Project Management Team (BPMT) encompassing all the components necessary to deliver a risk based decision and therefore the optimum results.
The KN field in KM cluster is located approximately 200km offshore, at water depths ranging from 59–102m. The field is part of the KM Cluster Integrated Development Plan, where the primary objective for KN field development is to recover the reserve from fringing pinnacle reef carbonate reservoir, expected to be achieved through two deviated 7-inch open-hole monobore subsea wells. KN field is expected to deliver around 200 to 300 MMSCF/day to the LNG plant to help relieve an anticipated gas shortage, as such failure to deliver the target would definitely upset the gas supply. Besides cost savings, the shallow water subsea development concept is part of the company's long-term vision to train its staff with new technologies and prepare them with basic guidelines for future development especially in deepwater. Although this is already considered a norm in other parts of the world, subsea completion is relatively a new experience in the company operation. The open-hole sections were drilled using Potassium/Sodium formate fluids with calcium carbonate as weighting and bridging agent and later the wells were completed with Cessium formate. Based on extensive laboratory test, it was found that this formate fluids allow for thin mud filter cake that can be remove effectively with differential pressure alone, excluding the need for filter cake breaker. High rate acidizing was planned as contingency should the wells failed to deliver the targeted well deliverabilities. Based on transient simulation using OLGA, high rate clean-up were planned to ensure effective filter cake break-up, removing debris and confirming the technical potential of the wells. With high rate, the duration of well clean-up is shorter and effective thus saving rig time. This paper details the planning and execution towards achieving the successful project of KN field, the 1st subsea development in the company
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