Proppant produced during production often causes damage to downhole pumps and surface equipment. In addition to restricting production rate, frequent workovers are often required to remove proppant or sand infill, thus resulting in costly downtime. To help resolve these proppant production problems, solvent-based curable resins have often been used in remedial treatments of affected wells. These resin systems have been applied in intervals of less than 100 ft. For longer intervals, ineffective diversion of solvent-based resins and their potential interaction with water in the wellbore can prevent them from providing complete coverage over the entire perforated interval.A novel water-based consolidation system has been successfully developed to overcome safety, fluid compatibility, and placement issues, which most current solvent-based resins encounter during their field applications. This paper presents the results of laboratory testing and field applications and discusses the challenges, lessons learned, treatment procedures, and recommendations in applying this newly developed resin system.The curable consolidation component is emulsified to form a water-external emulsion so that the active material can be delivered in a brine-based solution. Extensive laboratory testing has indicated that optimum concentration of coating is necessary to maximize the bonding between proppant grains. This allows the proppant pack to withstand high production flow rates and to overcome the effects of stress cycling while minimizing any reduction in its permeability. Results from field trials showed that this aqueous-based consolidation system successfully treated both proppant and formation sand in nearwellbore regions to lock them in place without damaging production flow paths. In these field tests, intervals in excess of 300 ft were treated effectively with a bullhead squeeze using consolidation-treatment fluids that were foamed to a quality of 50 or higher to aid in diverting treatment fluids and extending treatment volume.One major advantage of this aqueous-based system is its simplicity in field treatments without the concern of fluid incompatibility between fluid stages during their placement because of its benign behavior. The new system uses small treatment volumes to impart excellent consolidation properties while, at the same time, retaining formation permeability. This makes the treatment system simple to deploy and economically viable.

The successful application of sand-consolidation treatments is, for a major portion, dependent on correct fluid placement of the consolidation material. It is crucial to achieve a uniform placement of the material and, therefore, techniques are needed to overcome natural or artificially created heterogeneities. Diversion methods such as foams are being used frequently. However, fluid-placement verification of these treatments is rare. This paper discusses the placement of a novel sand-consolidation material using a foam diverter and the verification of the placement by using distributed temperature sensing (DTS). Two case histories are analyzed in detail and used for illustration. In both case histories, foam was used to place the sand-consolidation material in multilayer reservoirs, and DTS was used to verify the placement in real-time. Qualitative and quantitative fluid placement information was derived in both cases. From the DTS data, the parts of the formation that were treated could be identified in both case histories. In one case history, recently placed hydraulic fractures were identified and were treated. In the other case, reservoir-pressure variations were determined and identified to be the reason for preferential fluid placement and diversion over time. The lessons learned from the case histories will lead to further improvement of fluid placement.

Mechanical sand control completions are often used to optimise hydrocarbon production from weak formations. In a few wells this primary sand control method has sub-optimal performance. There is substantial value in remediating some of these wells, but developing this capability is not a quick and simple task. Recompleting a well could be feasible, but is often cost prohibitive. Mechanical solutions could be applied to stem sand production if the sand producing interval is known; however, in some cases chemical sand consolidation is the most effective approach. Chemical sand consolidation works by pumping chemicals downhole to strengthen the formation and stop sanding. In most cases reported in the industry, chemical consolidation has been used in short production intervals (<100m). Our approach was to develop a laboratory programme to test various industry chemicals and to achieve a good understanding of how these can be applied. Candidate wells were matched to chemicals to identify which systems (may be more than one) would be the best fit. The strategy was to initially trial the technology in low-rate onshore wells (typically <1 mmscf/d), before moving progressively to more challenging wells (up to 2,500 bopd). The wells were split into 3 groups based on their complexity: (1) proppant flow back remediation, (2) <100m producing interval and (3) >100m intervals. Each has unique challenges, but this approach facilitated a progressive learning curve. In proppant flow back remediation 7 field applications were conducted with 100% success rate. Longer intervals were successfully treated over time. Matrix consolidation presented a bigger challenge - 10 field trials have been carried out with a mix of successes and failures. A key learning is that adequate placement of the chemicals is critical. Chemical sand consolidation would fulfil its potential only when the chemicals can be reliably delivered to the target sand-producing zone – (often unknown), and remain static to allow sufficient curing time. Some treatments have been bullheaded (i.e pumped down the production tubing); others have been placed with coiled tubing. Operator has successfully developed an organisational capability whereby this technology can be part of the toolkit and - where appropriate - can be applied with a reasonably high chance of success to add value. Wells have been treated in the Lower 48 states in the USA, Canada, Alaska, Azerbaijan and Egypt and other wells are constantly being evaluated. Well types include oil and gas producers, onshore and offshore, with reservoir temperatures from 29 °C to 135°C. This technology is therefore being used across a wide well portfolio.

Premature failure of downhole and surface equipment can be caused by the production of formation fines, sand, and/or proppant. This leads to increased production costs associated with frequent workovers to remove fill, replacement of downhole equipment, and surface-equipment overhauls. In addition, production rates are often decreased to minimize solids production and can also compromise ultimate reservoir recovery.Conventional resin-consolidation systems have been successful in preventing solids production in short, homogenous intervals. However, resin consolidation in longer intervals has resulted in erratic success because of the lack of complete and uniform treatment of the entire interval length. Any untreated length of interval has the propensity to produce solids, resulting in a failed treatment.This paper presents the results of laboratory development and field testing of a new water-based resin-consolidation system applicable for proppant flowback and sand consolidation as well as field trials for proppant-flowback applications. This new system benefits from effective and efficient treatment of significantly longer intervals and improved health, safety, security, and environmental compatibility (HSSE) compared to conventional consolidation systems.

Premature failure of downhole and surface equipment can be caused by the production of formation fines, sand, and/or proppant. This leads to increased production costs associated with frequent workovers to remove fill, replacement of downhole equipment, and surface-equipment overhauls. In addition, production rates are often decreased to minimize solids production and can also compromise ultimate reservoir recovery.Conventional resin-consolidation systems have been successful in preventing solids production in short, homogenous intervals. However, resin consolidation in longer intervals has resulted in erratic success because of the lack of complete and uniform treatment of the entire interval length. Any untreated length of interval has the propensity to produce solids, resulting in a failed treatment.This paper presents the results of laboratory development and field testing of a new water-based resin-consolidation system applicable for proppant flowback and sand consolidation as well as field trials for proppant-flowback applications. This new system benefits from effective and efficient treatment of significantly longer intervals and improved health, safety, security, and environmental compatibility (HSSE) compared to conventional consolidation systems.