A successful trial of the Gas Well Stimulant WS-1200 was recently completed on a gas well with high Condensate-Gas Ratio (CGR) and producing below the dew point to treat fluid blockage in Saudi Arabia. The treatment consisted of pumping from a surface 2 wt% active solution in common organic solvents that solubilizes and/or displaces the brine and condensate that are present in the near wellbore region of a fluid blocked well. After bullheading the treatment into the well, it was chased with two equivalents of nitrogen gas. The well was shut-in over night for the treatment to react and then the well was opened to flow and clean out. A test separator was connected to measure the flow at surface and compare the flow after the treatment. Several days were required after opening the well to back-produce the solvents and evaluate the well through the test separator until stabilization was acquired. The well was put back online and continued monitoring production for several months. Just prior to injection of the chemical treatment, the well was producing ~1.5 MMSCFD and ~275 BOD. Within five days of concluding the injection, the well was producing ~2.7 MMSCFD and ~1,000 BOD and in an increasing trend. The well was left in production with only the wellhead temperature (WHT) and wellhead pressure (WHP) being monitored on an ongoing basis. After three months of production, the well rate was again measured through a separator at similar conditions and found to be ~2.85 MMSCFD and ~1,152 BOD, a sustained improvement of 83% in gas production and a 313% improvement in oil production. In light of initial encouraging results, similar chemical treatments are planned in other sandstone reservoirs with similar problems.

This paper will discuss the largest coiled tubing acid stimulation operation completed on a water injection well in Saudi Arabia. Stimulation design, field execution and the well performance before and after the treatment as well as massive planning, logistics and coordination are the key elements of this discussion. Furthermore, the authors would like to briefly review the future plans for other long/ multilateral wells in the area. This job was conducted on a dual lateral horizontal power water injector. The objective of this job was to stimulate the formation of both laterals by pumping 20% hydrochloric acid (HCL) and 20% strength diesel-emulsified acid and diverting it with 20% viscoelastic surfactant based acid on using Coiled Tubing (CT) and a Multilateral Tool (MLT). A total of 10,335 ft horizontal interval was successfully stimulated with 362,700 gallons of treatment fluid in 27 stages using 2 3/8" CT. On this job the MLT was successful in locating each lateral. The post-acid injection rate has been increased by more than double, higher than initial expectations. Consequently, the injectivity index has been increased drastically above the field average. Based on success of this stimulation job, the concept of designing and treating other Maximum Reservoir Contact (MRC) injectors using this technique becomes a recommended intervention process. The key to enhance future jobs lies on the ability to effectively capture and use the lessons learned from this massive operation. The continuous success of these jobs will help to improve the water injection system in Ghawar field and will enhance oil recovery. Background Saudi Aramco drilling strategy has been rapidly progressing through several sequences in order to optimize the oil production, water injection and cost. Accordingly, a new generation of wells are being widely drilled and completed with multiple legs or laterals in the horizontal section of the desired formation. This type of horizontal well has been implemented in the Ghawar field. Although multilateral wells have proven their efficiency to meet the strategy, the complexity of well intervention becomes a challenge for Operating and Service Companies. Logging, stimulation and other downhole surveys are major and difficult tasks. Currently the situation is better and the well intervention work can be conducted on an individual lateral as a result of utilizing the MLT re-entry tool. It depends on mechanical and pressure differential without an electric line or guidance system. Also, it can be used in conjunction with other CT downhole tools. Case History Well-A is a Power Water Injection (PWI) well which was drilled in 2002 as a dual-lateral horizontal open hole to have a maximum reservoir contact and support oil production in a carbonate reservoir which is a relatively tight formation. The well was drilled with two laterals across Arab-D Zone 2A. The 6 1/8" main bore, lateral 1, was drilled to a Total Depth (TD) of 13,649 ft Measured Depth (MD) and lateral 2 was drilled to a TD of 13,676 ft MD. The 7" liner was set at 7,686 ft while the window depth is at 8,720 ft (see Fig.1 below). Job Justification The objective was to acidize the carbonate formation of both horizontal laterals by pumping plain 20% HCL acid and diesel-emulsified 20% HCL (SXE) acid and diverting it with viscoelastic diverting 20% HCL acid (VDA) using a Coiled Tubing Unit (CTU) and MLT.

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The water cut and gas fraction associated with oil field production typically increases over time. The production reaches a point where part of the field becomes severely restricted, leading to low production and even premature abandonment of an oil producer. Artificial lifting methods are applied in this case to maintain the production. The most widely used methods are electrical submersible pumps (ESPs) and gas lift. Recently, it has been shown that multiphase pumping (MPP) technology is becoming a competitive method. MPP can also extend well production life and ultimately increase total recovery from producing fields; however, there are selection criteria for the proper application of the MPP. Considering an MPP for a well should be carefully approached and evaluated on a case by case basis. MPP may not be the best alternative for all weak wells. For example, a dead well, which cannot flow smoothly to the surface, does not provide sufficient wellhead pressure to the MPP inlet, and therefore is not a candidate for MPP. The MPP (twin-screw technology) has been installed in a remote field to boost the oil production from three oil wells with high water cut and insufficient pressure to flow to the processing facility. For these wells, a MPP package was designed and installed at the field manifold. The unit was a simplified portable pumping system powered by a diesel generator. The MPP is now operated unmanned with local controlling and monitoring systems. The trial test has proven the high percentage of operating efficiency of this type of MPP1. An oil gain was realized from the manifold using this MPP, which improves the oil recovery and sweep in the subjected area. The MPP has proven its reliability to introduce a successful performance for specially selected low flowing wellhead pressure (LFWHP) wells' applications. In addition, the MPP has further advantages in terms of piping modification requirements, maintenance ease, power consumption, compatibility with intelligent fields, monitoring operations, etc. This paper discusses the advantages of utilizing MPP with twin-screw technology in a Saudi Aramco field. The paper also addresses project implementation as well as the operating experience with the MPP. Introduction The multiphase pumps (MPPs) are modified liquid pumps that are capable of pumping various combinations of oil, water, gas, and minor sand in flow stream without separation. The MPPs are most commonly used to add energy to unprocessed fluids, which are to be transported to processing facilities far located downstream. Therefore, a reduction or elimination of the production infrastructure such as separation equipment and offshore platforms can be achieved. This leads to lower operating costs associated with the development of hydrocarbon reserves. In this way, marginal fields located in hostile environments can be developed more economically2. The MPPs can also reduce the back pressure on producing wells, leading to an increase in production and recoverable reserves.