In mature fields it can often be a challenge to obtain accurate well data and reliable formation parameters without imposing high cost and time constraints on development or production schedules. One common method to test non-naturally flowing wells is impulse testing, which makes use of differential pressures between the formation and a surge chamber or wellbore to perform a short flow period or surge test, followed by a relatively short shut-in period. Unfortunately, these tests frequently result in invalid or uninterpretable data as a result of several uncertainties and test constraints. An improved version of this common technique encompasses a three-fold approach to optimize the impulse test. A new numerical simulator designs the test to maximize depth of investigation without compromising the interpretable data. The coiled tubing-conveyed intelligent bottomhole assembly used to execute the impulse test may, in certain environments, reduce operating times in comparison to use of conventional tubing-conveyed solutions. The combination of the prejob design package and a functional bottomhole assembly enables consideration of the complexities that can result from impulse testing so that a valid data set is delivered. The interpretation is performed using traditional well test interpretation methodology and an analytical solution specifically designed for impulse testing. This solution considers the wellbore fluid density variation during the test while still maintaining the simplicity of the wellbore model; variable skin is described by an exponential function, thus improving on established analytical methods. A comparison of the results from both interpretation methods establishes the test validity in terms of flow capacity and skin. This paper describes the systematic approach, including its design, execution, and interpretation, and highlights advantages and limitations through the case study and field data of a well in the Wadi Rayan field of Qarun Petroleum Company. This technique offers a rigless testing method that can optimize test time while delivering valid, accurate results that aid in production forecasting, completion optimization, and planning of remedial intervention for non-naturally flowing wells.

Intelligent artificial lift technology is increasingly being used in Belayim Marine Field to enhance the value of maturing assets and new development wells. Wells equipped with electric submersible pumps (ESPs) are particularly suited to this blend of old and new. For years, the performance of ESPs has been monitored and controlled from the surface to prevent early pump failure by adjusting the frequency of the signal sent to the pump's variable speed drive (VSD) motor controller. This adjustment has also been used to avoid under-loading an ESP and increase production volume. To find this optimal operating range, real-time data and modeling are used to design the pump to fit the specific requirement of each well.Most recently, Belayim Petroleum has taken the concept a step further by deploying intelligent artificial lift in combination with stimulation technology aimed at reservoir management to help restore production from the 113-M-97-H well in Belayim Marine field, which is located in the central part of the Gulf of Suez, along the coast of the Sinai Peninsula. This new development well was drilled horizontally with maximum angle of 88°, and a 211 m. horizontal open-hole section was completed with 3.5-in. excluder screens. The well once achieved 22-hour good recovery at 550 BOPD. Then the production declined and the well was shut in due to low amperage, followed by no recovery caused by severe loss of circulation, which created a filter cake plugging the near wellbore pores. Complex stimulation treatment and flow, and well geometry and completion, as well as the offshore environment have complicated workover operations on this depleted reservoir and unproductive well issues. With intelligent ESP, a cost-effective stimulation was successfully deployed and enabled to evaluate production streaming data, such as pump intake pressure and temperature during the treatment across the horizontal section.Already equipped with in-well electric power cables, protectors, and multi-sensors, as well as a power controller VSD at the surface, this intelligent ESP system also enabled clean-out process at different production rates. Once clean reservoir fluids were observed during the flowing period, the ESP was stopped for a pressure build-up. A post-stimulation well test was performed to evaluate the treatment's effectiveness before running the new completion, hence minimizing intervention time to restore production promptly, reducing rig time, and achieving optimum completion design for long-term productivity of the well.

For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd. An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements. This paper describes the first application of FOTECT in sandstone formations, involving: The sandstone matrix stimulation operation.Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation.Accurate depth correlation to achieve optimum placement of the treatment fluidsMonitor the chemical reactions in real time of the engineered treatment fluid.Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions.Qualitative production allocation of the interval as a response to the treatment fluidsEvaluation of the skin value real-time while executing matrix stimulation.Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries). The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.

The Cheleken field offshore Turkmenistan is going through brown field development and challenges with retaining and enhancing production increase every day. Well Interventions are deemed to be a daily necessity to maintain production. Coiled Tubing, Wireline and other rigless interventions have been used directly on platforms resulting in occupying critical spaces, logistic and marine congestion (one Coiled Tubing Move comprises of over twenty lifts), structure integrity limitations, crane and lifting limitation, and a lot more. The need for a self-elevating platform arose and operator search for a proper one within the Caspian Sea ended with disappointments. This paper details the innovative and out of the box solution that was put in place to mobilize the first Lift Boat to the Caspian Sea. A lift boat was identified in the USA in the Gulf of Mexico which was underutilized after the pandemic and oil recession. The Class 230 specifications met the end user's requirements but the challenge was how to mobilize it to the Caspian. In addition, there were a handful of modifications that were requested for the Caspian operation that were not necessarily required in the Gulf. Mobilization of the lift boat must be carried out through the Volga-Don canal locking system which has a width of 57 feet 9 inch (maximum allowable beam for vessels is 56 feet 5 inches). The beam of the lift boat was 78 feet which is too wide to fit through the Volga-Don shipping canal. Hence, it was necessary to disassemble and transport the lift boat in sections. This paper describes the following: Disassembly requirements necessary to prepare the lift boat for mobilization The mobilization of the lift boat The reassembly requirements once the lift boat reached the shipyard at Caspian Sea Installation of well service and intervention equipment Technology and methodology adopted The Lift boat was disassembled into three major sections for transportation: a) the center hull module b) the port wing module, and c) the starboard wing module. The wing modules, miscellaneous equipment and containers were loaded onto a barge and sea-fastened for transportation. The center hull module was wet towed to the shipyard located in the Caspian where the lift boat was reassembled, and the well service equipment was installed. The mobilization and assembly happened during the Covid-19 era, and the vessel was hit by Hurricane Ida which impacted the disassembly schedule. Challenges on mobilizing the personnel, equipment, machinery, port clearance, etc. were all extremely tough due to Covid-19. The paper will also cover technical implications on conducting this task by complying with the classification and flag state requirements as per Turkmenistan authority. The main lesson of the paper is the identification of gaps on mobilization and how the improved techniques can be utilized for executing the task on a fast-track manner.

In an environment of high activity, large organizational growth, and the nearing of retirement age for a large proportion of the oil and gas industrial workforce (otherwise known as the "big crew change"), there is a high demand for experienced personnel to be correctly placed within an organization to bring maximum benefit for continued growth and knowledge transfer. For a business organization to ensure its success during this challenging period, it must optimize its human capital in a way that will reap the most benefit. Part of this process includes capturing the experienced generation's design knowledge and passing it on in a way that maintains consistency and yet allows the experienced personnel to focus on more business-critical decision making or operational supervisory roles. Configuring the bottomhole assembly (BHA) is typically a crucial point when preparing for well intervention using coiled tubing. Several strategies have been adopted by service providers to standardize and regulate the design stage and ensure continuity through the "big crew change," including:Providing intensive training and mentoring to act as a rapid handover between the experienced and the new generation of tool specialists.Creating and distributing fixed flow chart decision trees throughout the organization.Setting up a specialized group of experienced tool specialists that can be used as a geographically-mobile workforce that services the organization's global needs.Creating a dynamic technology-based computer system that captures the existing field design knowledge and also captures new lessons learned. This paper discusses these strategies, examining the positives and negatives of each approach, and then goes into further detail of how a leading coiled tubing service provider has decided to handle this issue. Introduction - Obstacles to be overcome As tool strings become more complex and spread across a variety of specialized applications, if nothing else changes, the knowledge base of a tool specialist is expected to expand. Due to the industry demand to move the experienced personnel into operational supervisory positions, and expand the working capability; what is needed is a way that allows the expansion rate of the industry to be met immediately by improved efficiency, along with physical work force growth. To maintain industry recognition the service provider must achieve this without any compromise and preferably with an improvement in their service quality. From both a company wide standpoint, as well as at a local level, the latest developments through lessons learnt and new technology developments in well intervention BHA's, from a configuration, and a design improvement standpoint; are all items that must be rapidly available throughout a coiled tubing service providers: tool specialists, sales staff and design engineer communities. Doing this means that every location can rapidly benefit from everyone else's experience, and thus the company as a whole becomes more efficient. Traditional thinking that competency is only achieved through years of seniority, and training based along those lines; alone simply cannot keep up with the current speed the industry demand is growing 1. This attitude must first change, and competency judged by documented training through a variety of media. However even with accelerated training, service providers must complement training with other processes, to achieve complete knowledge sharing through the relevant staff, and to gain the efficiencies needed.