In the last decade, hydraulic fracturing has been successfully applied in West Africa for the development of tight reservoirs. Since 2007, more than 200 fracturing stages have been achieved in 9 different fields targeting wells characterized by a wide range of conditions: from sandstone to carbonate formations, from low to high temperature reservoirs, and from old existing completions to new drilled wells. While applying this technology throughout the years, tailored solutions for treatments design have been continuously put in place to address the observed challenges and maximize the final oil recovery. The deployment of new technologies such as proppant flowback prevention additives, non-radioactive tracers for fracture height monitoring, and channel fracturing, to boost the fracture conductivity played a major role in achieving the desired results. The accumulated in-depth knowledge on hydraulic fracturing built from local experience allowed Eni West Africa to rapidly approach a new offshore tight oil field development with confidence that hydraulic fracturing would be an effetive stimulation technique. This paper will describe the fracturing campaign major milestones, from the promising results obtained on the exploration wells, to the optimization actions implemented during the first development phase. Thus far, six horizontal and two vertical wells were completed, including a total of 23 hydraulic fracturing stages during a single campaign spanning less than one year. On the first of the two vertical wells, each stimulated with a single frac stage, a non-radioactive tracer was employed for measuring the propped fracture height, and calibrating the frac model. For the horizontal wells, where 3 or 4 frac stages were implemented, a plug-and-perf (P&P) technique was selected. This method included coil tubing equipped with fiber optic, enabling precise perforation intervals placement, also providing flexibility in case re-perforation was required. Moreover, several actions were adopted to improve completion efficiency and cost-effectiveness, including perforation selection to limit near-wellbore pressure losses, and coiled tubing runs optimization for setting the bridge plug and perforating in a single trip. Finally, particular focus will be given to the steep achieved learning curve, describing the adopted decisions, to improve both completion performance and fracture conductivity.

Through a series of examples, this study examines how real-time bottomhole data has reduced or mitigated the risks inherent to coiled tubing (CT) applications, leading to safer job execution. A number of tasks such as rigging up, mixing fluids, pumping, and rigging down are part of conventional CT interventions. Each of these tasks has risks associated with it. With the intent of optimizing CT operations, a fiber optic system was developed to enable real-time bottomhole measurements, allowing live monitoring of interventions. By providing real-time downhole intelligence, the technology has provided the means to operate more efficiently and enhanced the service quality and reliability of the CT services. More importantly, it helps optimize or minimize the tasks associated with conventional CT interventions, reducing personnel exposure to many of the risks. By providing a real-time casing collar locator (CCL), performing an extra dummy run is no longer necessary for all depth- critical operations. Reducing the number of runs not only reduces overall operational time, it also reduces personnel exposure to hazards related to these operations. Downhole pressure and temperature sensors have provided positive confirmation of gun detonation on CT perforating applications, reducing the risk of pulling out of hole with live guns. The monitoring of real-time bottomhole pressure provides a safer way to manage pressure by either assessing and obtaining the preferred perforating balance condition or validating the operation of the choke during a cleanout to avoid gas entry and to maintain a better control of the well. In applications such as matrix stimulations, cleanouts, or even nitrogen kickoff, the system has proven beneficial and effective in optimizing treatment volumes, consequently reducing extended cleanouts and associated flow back and flaring. Finally, this study evaluates the process of making informed decisions during execution of a CT job based on real-time downhole critical parameters and their impact on overall HSE performance.

Subhydrostatic or low bottomhole pressure wells are wells with large hydrostatic overbalance, that is, the hydrostatic pressure of the fluid column inside coiled tubing, drillpipe, or similar well intervention means is greater than the wellbore pressure at the corresponding vertical depth. The number of subhydrostatic wells is growing as more and more fields mature. Consequently, there is an increasing number of interventions required for these wells to improve and/or optimize their production. U-tubing of the fluid column is a very common and uncontrolled phenomenon during interventions in subhydrostatic wells that can cause problems. In this paper the focus will be on coiled tubing interventions; however, the same basic principles apply to other areas as well.A backpressure valve (BPV) is a device that is used in subhydrostatic wells to hold the fluid column inside coiled tubing to prevent U-tubing. The BPV compatibility with other components in the toolstring is a critical operational requirement. Following recent tests conducted with the BPVs readily available in the market, it has been shown that these are not appropriate for a number of applications. One example is an application involving pressure pulse telemetry. For pressure pulse telemetry, conventional BPVs either cannot pass the pressure signals or greatly attenuate the magnitude of them.A backpressure valve that is fully compatible with pressure pulse telemetry has been developed and will be presented in this paper. The root cause of why the conventional BPVs were not able to transmit pressure pulse will be discussed using the results from fundamental physics, computational fluid dynamics analysis, and lab and filed experiments. Finally, a typical set of results from a field trial using the new valve will be presented.

Scale buildup due to water production can choke oil production and require repetitive scale treatments across entire fields. In subsea wells, the common solution employs a deepwater rig to conduct either workover operations or large-volume scale inhibitor squeezes. Less frequently, coiled tubing (CT) is used from a moonpool vessel. However, current oil prices required a custom solution for subsea well treatments that was more cost effective than either a rig or a moonpool vessel. Similar previous operations successfully used 1 ¾-in. and 2-in. (44.4 mm. and 50 mm.) CT at the same time from a moonpool vessel. A remotely operated vehicle (ROV) in the open water connected the CT to the subsea safety module (SSM) through a dynamic conduit and connected the SSM to the wellhead. An engineered solution to change to 2 7/8-in. CT and use high-rate stimulation pumps was planned to deliver subsea treatments at up to 15 bbl/min. The equipment layout was designed for a multipurpose supply vessel with chemical storage tanks; to increase the available selection of vessels, the CT was designed to run overboard rather than through a moonpool. This project was initiated after accelerated scale buildup occurred because of a pressure decrease close to the bubble point, which happened when the drawdown was increased for aggressive production targets. To effectively inhibit scale in this environment, treatments required thousands of barrels of inhibitor. For wells with more-severe scale conditions, acid treatments were planned. These treatments were delivered with one complete CT package, stimulation pumping fleet, and subsea equipment, which were all installed on the spare deck space of the available vessel. A custom overboard CT deployment tower was designed. The new tower improved the dynamic bend stiffener (DBS) placement, which allowed the clump weights to be deployed with the bottomhole assembly (BHA) and simplified the rig-up. The chosen vessel worked well for the operation; however, the equipment layout and the local weather conditions combined with the response amplitude operator (RAO) of the vessel shortened the projected fatigue life of the CT. CT integrity monitoring with magnetic flux leakage (MFL) measurement was introduced here, and the vessel’s motion reference unit (MRU) provided an input to a fatigue calculator, based on the global riser analysis (GRA). The measurements and the analysis were utilized successfully to prevent CT pipe failures in the open water and deliver the required well treatments. To allow further improvements in deepwater operations, the new engineering work-flow was carefully documented.

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