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.

Saudi Aramco has recently embarked on an exploration program targeting unconventional gas reservoirs to meet the ever increasing local gas demand. One of the targets is a tight sandstone play located to the east of a giant hydrocarbon reservoir with limited reservoir data through the few exploratory wells drilled in that play. The target formation is considered a deep reservoir with very low permeability and high fracture gradient. In order to evaluate the potential of the subject formation, wells have to be completed with a hydraulic fracture. Given the challenging nature of the reservoir in terms of stress, pressure and temperature, a sophisticated design of both well completion and fracturing treatment must be performed to successfully evaluate the potential of those wells.

Scale is considered as one of the major concerns in the oilfield industry. Usually, scale formation causes several issues such as: reduced production, formation damage, jeopardizing well integrity, and causing damage to assets such as artificial lift equipment. Therefore, a scale inhibition operation has to be conducted to sustain oil and gas production by assuring the flowing conditions of the reservoir and production assets. Scale inhibition in oilfield industry is carried out in one of four ways: 1- squeezing the inhibitor inside the formation, 2- continuously injecting the inhibitor through a capillary tubing, 3- apply an encapsulated inhibitor in the rat hole, 4- applying batch treatments. In this study, we are evaluating various treatment designs for the scale inhibition through the squeezing technique in terms of efficiency and lifetime. The efficiency of scale inhibition squeeze treatments is bound to a certain lifetime which depends on the interaction between the inhibitor and the reservoir rock. The inhibitor interacts with the rock in an adsorption fashion, then it desorbs to maintain a certain concentration in the aqueous portion of the produced fluids; thus, inhibiting scale deposition. When squeezing the scale inhibitor deep inside the reservoir, the inhibitor has a greater surface area to adsorb onto; therefore, less of it will be retained when flowing the well after the operation. The drawback of the squeeze technique is the duration, and the inhibitor loss right after the operation, the greater the inhibitor production the shorter the treatment lifetime. Squeezing the treatment deep inside the formation has reduced the inhibitor concentration; thus, increased the treatment estimated lifetime by almost 5 folds.

This paper discusses the first successful in-Kingdom coiled tubing intervention in a well without conventional stripping-out of the well leading to significant cost savings, reduced risks, and compliance to Saudi Aramco environmental protection policies by adhering to a zero flaring initiative. Conventionally, wells are shut-in, secured, and stripped out (depending on the operation, stripped out refers to the disassembly and removal of directly connected piping, cathodic protection, and other production system components) in preparation for performing any high pressure coiled tubing (HPCT) interventions (to allow crane and HPCT units to spot and rig-up). Wells are then again re-manifolded to the production system. These stages consume a tremendous amount of manpower, cost, time, and production loss. Unfortunately, some wells have severe condensate loading issues, to the extent that they tend to die again, during shutdown (re-manifolding period) after the lifting operation. A new approach was required to be developed to avoid asset depletion in problematic wells. The new approach suggests eliminating the need for stripping out and re-manifolding by lifting the well while it is connected and flowing to the gas plant. Many challenges were encountered during this effort, including the limited space for spotting equipment around the well connections, well control, and well response monitoring. In addition, it was difficult to overcome the downstream pressure across the pressure control valve (PCV) to allow unloading the well under its own pressure drive. The operation served as a benchmark for future wells. The operation turned out to be a huge success in terms of cost and safety. The avoidance of strip-out, re-manifolding, testing package, and producing to the gas plant instead of flaring resulted in significant cost avoidance and reduction in production time. This paper will provide an insight on the reasons behind selecting this well as a potential candidate for the job. It will also shed light on the risk assessment aspects, both technically and environmentally, and the operational safety backup plan that was thoroughly discussed and implemented. In addition, the challenges faced throughout the whole process of selecting the well, conducting risk assessment, issuing the Management of Change (MOC), designing the rigless program, and finally commencing operations will be discussed to ensure obstacles in future operations can be minimized. At the end, lessons learned and recommendations will be shared to ensure that the highest levels of operational efficiency are maintained for similar cases in the future.