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Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This can minimize or even eliminate costly vessel trips necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and also presents the results of successful field applications. This seawater-based fracturing fluid uses a low-residue polymer crosslinked with zirconium that has a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, a multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Three wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Wells B and C comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages. During development evaluations, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m3 (50 lbm/1000 gal) The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m3 (30 lbm/1000 gal). The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, demonstrating the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine. Twenty total stages of hydraulic fracturing operations were designed and executed successfully in the three horizontal wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m3 (6 lbm/gal) during the tail stage. A total of 1533 tonnes (~3.38 million lbm) of proppant was pumped in 5915 m3 (~1.56 million gal) of crosslinked fluid. The seawater-based fluid properties present an innovative approach for addressing the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).

Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This minimizes or even eliminates costly vessel trips that are necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and the results of successful field applications. This seawater-based fluid uses a low-residue polymer crosslinked with zirconium having a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Two sidetrack wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Well B comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages. The seawater-based fracturing fluid was not expected to generate damaging effects on reservoir productivity. During development, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m3. The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m3. The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, which demonstrates the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine. Eleven hydraulic fracturing operations were designed and executed successfully in both horizontal sidetrack wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m3 in the tail stage. A total of 851 tonnes of proppant was pumped in 3156-m3 crosslinked fluid. The seawater-based fluid properties present an innovative approach to address the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).

This paper identifies restimulation opportunities in existing multistage completed horizontal wells with plans for a customized refracturing solution applying breakthrough stimulation and diversion processes to increase oil production in a tight carbonate formation, offshore Black Sea. Because operators are shifting strategy in a low oil price environment from new well drilling toward well interventions, refracturing is gaining more focus, particularly for tight and less conventional reservoirs. Many potential candidates also have suboptimal completions for refracturing, so the challenge for operators is selecting the best candidates and designing a refracturing treatment for improved well performance in these complex situations. This paper describes the well screening and selection process for the restimulation of existing horizontal wells with multistage openhole completions. During Phase 1 of the project, pilot candidates were ranked using a weighted average score of specific decision criteria for evaluating the refracturing potential. The goal of the screening process was to identify wellbores with the most bypassed reserves and to determine the root cause. Top candidates demonstrated bypassed reserve potential because of large completion spacing and lower average permeability than was originally estimated. The design process emphasized identifying areas where incremental oil could be accessed by substantially increasing total exposed conductive surface area and placing new fractures between existing using novel approaches to refracturing incorporating flow diverting technology. The application of an engineered pressure-managed design approach optimized proppant cycles, and flow diverting refracturing methods were a fundamental component in recognizing that the restimulation pilot was realistic, achievable, and justified economically. By dynamically managing and adapting proppant schedules, diverter volume fractions, and total materials pumped over time, new induced fracture surface areas can be reliably created in the most economic manner. Phase 2 consisted of executing the refracturing operation on the selected pilot well, which had been originally hydraulically fractured in 2009. A repressurization procedure of the reservoir was performed before the main treatment to equalize pressure depletion along the lateral and ultimately enhance the coverage of newly fractured zones along the wellbore. The refracturing treatment on the pilot well consisted of four proppant cycles with application of engineered pressure management to improve fracture initiations and flow distribution. A degradable particulate diverter technology was used as primary isolation of each fracturing cycle. Restimulation results of the pilot well demonstrated technical and production success, with huge potential to implement this technology during the next phase of field revitalization (Phase 3). This pilot project has proved that the combination of a well selection process aimed at finding unstimulated and bypassed reservoir volume and the application of customized technical solutions for refracturing can be successfully applied to increase recovery factors and identify new opportunities in mature field redevelopment.

This paper identifies re-stimulation opportunities in existing horizontal wells with existing multistage hydraulic fracturing to increase oil production in a tight carbonate formation, offshore Black Sea. Pilot candidates were screened and ranked through the following decision criteria described in this paper, coupling reservoir, production and completion parameters. Favorable pilot candidates were verified by numerical simulation, which also highlighted potential areas of by-passed oil for future sidetracks. In an era of low oil prices, it is increasingly difficult to justify drilling new wells, especially in the offshore environment. A strategic shift towards revamping and workovers has made operators of tight and unconventional reservoirs to focus on restimulation. Many factors define success herein, and the key to finding the right candidates. Synergy between numerous parameters, combined often in indexes or drivers by their nature, is used to score and prioritize existing well potential and associated risks. On the other hand, reservoir and its understanding still play a major role and prevail over solely statistical methods. Top scoring refracturing candidates in this work were simulated in both full field and sector models. Real post-job fracture geometries and newly initiated fractures were critical inputs into unstructured reservoir simulation grids to ensure that the identified targets of the restimulation pilot wells are realistic and achievable. Recent multistage stimulation jobs in this field accidentally led to several "frac hits" (cross-well communication initiated while pumping a hydraulic fracturing treatment), which were confirmed by tracer analysis in the adjacent wells. Subsequent offset well behavior had both positive and negative effects, thus enabling the quantification of gains from restimulation, where possible, and intrinsic well interference. The choice between refracturing old or new wells, and finding the balance were the major pitfalls in this work. Wells, drilled 5-7 years ago and stimulated with typically 3 stages, had sub-optimal completions for refracturing, however were placed in the better quality rock, therefore displayed higher initial production. Delineating the reservoir bodies from seismic inversion and integrating with the simulation model, highlighted favorable well placements and historically it was proven to reduce initial water cut by 2-3 times. Recent and more extended wells were positioned in the tighter, "saddle" zones, drilled and completed couple of years ago. They had due drawdown management, flatter decline, plus less mechanical and operational risks. Pay in these extended wells was recognized as a major uncertainty when history matching flowing bottomhole pressures. Results of the statistical scoring and decision criteria, to enable selection of refracturing candidates, are presented in this work, along with the integration and coupling these outcomes with the applied reservoir simulation. Both sets of results were used to find new opportunities for the mature field redevelopment.