No abstract

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.

Bir Rebaa Nord (BRN) and Bir Sif Fatima (BSF) fields, operated by Groupement Sonatrach-Agip (GSA, a JV between ENI and Sonatrach), are located in the Berkine basin in north-eastern Algeria. These fields are characterized by oil-bearing sandstone reservoirs with low to medium petro-physical properties. During the development phase, to counteract the effect of pressure depletion, water and gas injection was implemented for reservoir pressure maintenance. In addition, due to the increasing water cut, artificial lift systems were employed to effectively produce these fields. Hydraulic fracturing has been implemented in GSA since year 2000 to improve well performance, both in terms of productivity and injectivity for oil producers and water injectors respectively. The fracturing process has been improved over the years regarding operational procedures, enhanced reservoir knowledge and implementation of new technologies towards resolving the many uncovered challenges. Changes to the perforation strategy, fracturing fluids formulation, rock mechanics studies and design of proppant schedules are examples of enhancement to the fracturing practice that have been implemented in the recent years. One of the uncharted matters in GSA, coming out from the post-job data re-processing, was the necessity of a precise characterization of the hydraulic fractures vertical coverage. The presence of several sandstone layers with different properties brought questions if the fracture had grown into an unwanted zone or may had not properly covered the entire target formation. Moreover, fracture height is an essential parameter for frac models calibration. Its accurate determination drastically reduces the margin of error in treatment net pressure matching, helping to more precisely established fracture half-length and width, stress profile and, last but not least, achieving a calibrated model for future operations in the same area. This paper describes the successful implementation on two water injector wells of a novel non-radioactive detectable proppant for the first time in Algeria. The taggant material within the proppant has been located by comparing the pulsed neutron capture cased-hole logging passes registered before and after the hydraulic fracturing treatments. The detectable compound does not affect proppant properties and, in addition, its non-radioactive nature reduces the timing for materials delivery and eliminates the HSE risks linked to other tracing methods. The pulsed neutron measurements evaluation provided valuable information regarding fractures confinement, avoidance of contact with undesired layers and possible presence of cement channeling. Furthermore, combined with sonic logs and cores data, it helped refining the geo-mechanical model for future interventions design in the same reservoirs.

Hydraulic fracturing technique is worldwide used to unlock reserves in tight formations. The Devonian layer, present in this field in the Berkine Basin (Algeria), is gas condensate bearing with a permeability range of 1 to 0.1 md; the zone shows also an highly tectonic stresses, and the frac gradient can rise easily values above 1.0 psi/ft. 3 previous fracturing treatments performed in 2005 and 2006 in 3 vertical wells were without success, due to the high stresses encountered, the wrong frac designs and completion limitation. Aim of this paper is describing the successful multiple propped hydraulic fracturing treatments, placed in a subhorizontal well in March 2012, listing all the actions done in terms of Completion design Materials choice and Frac schedule optimization. This paper describes also the multiple lessons learned experienced in the execution phase of the multifrac job about frac placement, frac design and completion choice, that have to be considered for the fracturing jobs already planned, in fact the good results of this treatment allowed the Operator to plan a future appraisal/development phase for the Devonian layer.

Hydraulic fracturing for well performance optimization has been implemented for many years in BRN field in north-eastern part of Algeria, operated by Groupement Sonatrach-Agip (a JV between ENI and Sonatrach). Because of unfavorable petro-physical properties of the reservoir, some challenges have been encountered in avoiding any additional damage to the fracture faces and to facilitate the post-job treating fluids flowback. Effective fracturing treatment designs should consider preventive actions for possible fracture conductivity impairment, such as damage attributed to stress, proppant embedment, and damage caused by fracturing fluid residues. Correct proppant selection can minimize effects from stress and embedment, while a suitable fluid system can minimize conductivity impairment from gelling agent solid residue. Traditional guar-based fluid systems, which are often a preferred choice in the industry for fracturing operations, can have damaging effects on fracture conductivity attributed to inherent insoluble residue that can plug proppant pack pore spaces. Implementing a less damaging fluid system can not only maximize retained conductivity, but furthermore provide longer effective fracture half-lengths which may result in more efficient treatment fluid recovery. Therefore, to overcome such issues, a new fracturing fluid has been developed, leaving little or no residue after breaking. Moreover, this fluid system can be tailored to a wide variety of bottom-hole conditions and has comparable properties to guar-borate fluids with respect to proppant transport capacity and rheological characteristics (e.g. viscosity building and breaking behaviors). This paper presents the first successful implementation of this novel fluid system in the BRN field in Algeria for improving the water injection performance of a well characterized by a tight sandstone reservoir. Field data collected after performing the propped fracturing treatment confirm the effectiveness of the fracturing fluid design. Specifically, the following topics will be extensively described within this paper: Characteristics of the BRN field and history of conventional guar-base fluid systems used previously within this field;Specifics of the near residue free fluid system (cross-linker types, pH requirements, etc.);Design considerations for the implementation in the BRN field of this novel fracturing fluid;Results of post fracturing water injection performances.