In this paper we present case studies describing the approach adopted to solve scaling issues in a complex well architecture, an analysis of the scaling root causes, and the construction of a novel execution plan incorporating scale inhibitors, diverting agents with different acid systems to maximize the treatment efficiency. Even when producing at a low water cut fraction, most of the offshore multi-fractured wells in the field experienced scale deposition phenomena because of instability of the calcium ions present in the formation water. When pressure drawdown is applied on the producing wells, a progressive and severe worsening of production performance was observed, and in certain cases this led to a complete obstruction of the well. Previous stimulations executed on the under-performing wells were able to temporarily restore the production. Those treatments were performed using a conventional HCl acid system with coil tubing and these yielded positive results initially, but performance progressively decreased after a few months. For this reason, it was a priority to analyze the root cause of the deposition and define an improved method to extend the effectiveness of the intervention. Scale tendency analysis of the formation water highlighted the instability and predicted calcium carbonate presence at the reservoirs’ pressure and temperature range. Based on the evaluation of Saturation Index it was determined that calcite build-up can occur at any point in the production system. This was confirmed by field evidence, with scale deposit samples recovered at the choke, surface line and along the completion tubing. A nitrified organic acid blend was applied to invade deeply into the fracture body, together with a liquid scale inhibitor squeeze treatment that was designed to prevent further re-depositions in the short-term. A diversion technology was implemented to treat the multi-fractured horizontal wells in efficient manner by rig-less bullheading. Furthermore, due to unavailability of a rig in place, efforts were made to solve the different challenges to operate in rig-less mode: a lack of space on the production platform deck prevented any pumping intervention, and the well restart and clean up was executed directly in a high-pressure sea line. This alternative approach, with novel technologies for diversion and scale inhibition, yielded excellent well responses to the placement of the acid mixtures, which were designed to dissolve the carbonate scales with minimum impact on the sandstone formation, completion equipment, and production facilities. The selected solid diverting agent self-degraded by hydrolysis once in contact with water base fluids in the high temperature environment. This diverter was able to effectively distribute the acid treatment into each of the fractures: the particle size distribution was designed to efficiently bridge on the proppant pack in the fractures. The well start-up production rates confirmed the major benefits resulting from this approach: a higher Productivity Index was estimated on all the applications when compared to past conventional stimulations. Moreover, the use of a scale inhibitor extended the post-stimulation well life from few weeks, up to several months or years and therefore reduced the frequency of future well interventions. This novel alternative approach resulted in a more cost-effective well intervention solution and addressed the challenges of an intense offshore rig-less stimulation campaign in the field.
The operator in West Africa embarked upon the "N" field offshore development in 2016 with 13 multi-stage horizontal wells being fracture-stimulated in Phase-I, with further wells being planned in next development phases. Due to the complex nature of the reservoir, which is a multilayered sandstone characterized by high heterogeneity and low permeability, wellbore connections are often located in structurally altered areas with high presence of faults. The unpredictable local re-orientation of the stresses has resulted in complications for the fracturing operations with multiple fractures being induced. This paper presents the challenges and solutions implemented for delivering more consistent fracturing execution and well productivity improvements. The horizontal wells in the "N" field were hydraulically fractured using the "plug-and-perf" method with up to four fractured intervals. The quality of the near-wellbore connection and the observations of complex near-wellbore fracture geometries have hindered far-field proppant distribution and limited maximum proppant concentration inside the fracture. When fracturing this tight formation, controlling the opening of the pressure-dependent multiple fractures was identified as a critical issue. An engineering breakdown process and adapted frac strategy was implemented to minimize the multiple fractures generated at the formation. For the early hydraulic fracture treatments performed, conservative treatment designs were applied in order to avoid premature screenout with the consequence of increasing operative time. Implemented solutions have shown to improve the near-wellbore connections and increase well productivity. The successful outcomes are attributed to the implementation of improved perforating strategies, the optimization of fracturing fluid performance, an engineered fracturing breakdown process, and the development of a frac decision tree for improved decision making. The hydraulic frac strategy has been tailored well-by-well depending on the reservoir conditions (e.g. faults, permeability thickness, contacts), and on the operational conditions interpreted from the diagnostic injection tests (e.g. near wellbore tortuosity, net pressure). The holistic implementation of these new concepts for hydraulic fracturing and field development have delivered positive production results beyond initial expectations. For the horizontal wells intersecting the deep low permeability "D" reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques and unique solutions applied for each fracturing stage.
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.
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