The Valhall field, operated by AkerBP, has been a major hub in the North Sea, on stream for thirty-eight years and recently passed one billion barrels of oil produced. The field requires stimulation for economical production. Mechanically strong formations are acid stimulated, while weaker formations require large tip-screenout design proppant fractures. Fracture deployment methods on Valhall have remained relatively unchanged since the nineties and are currently referred to as "conventional". Those consist in a sequence of placing a proppant frac, cleaning out the well with coiled tubing, opening a sleeve or shooting perforations, then coil pulling out of hole pumping the proppant frac. For the past few years, AkerBP and their service partners have worked on qualifying an adapted version of the annular coiled tubing fracturing practice for the offshore infrastructure - a first for the industry, which has been a strategic priority for the operator as it significantly reduces execution time and accelerates production. As with all technology trials, the implementation of this practice on Valhall had to begin on a learning curve through various forms of challenges. Whilst investigating the cause and frequency of premature screenouts during the initial implementation of annular fracturing, the team decided to challenge the conventional standards for fluid testing and quality control. Carefully engineered adjustments were made with regards to high shear testing conditions, temperature modelling, and mixing sequences, these did not only identify the root cause for the unexpected screenouts, but also helped create the current blueprint for engineering a robust fluid. Since the deployment of the redefined recipe, adjusted testing procedures and changes made to the stimulation vessel, there have not been any cases of fluid induced screenouts during the executions. The fewer types of additives now required for the recipe have lowered the cost of treatments and the lower gel loading leads to reduced damage in the fractures, thereby contributing to enhanced production over the lifetime of the wells. This paper describes the investigation, findings and the resulting changes made to the fluid formulation and quality control procedures to accommodate for high shear and dynamic wellbore temperature conditions. It discusses the rationale behind the "reality" testing model and, proves that significant value is created from investing time in thoroughly understanding fluid behaviour in the lab, prior to pumping it on large-scale capital-intensive operations. The study demonstrated that there is always value in innovating or challenging pre-conceived practices, and the learnings from this investigation significantly improved the track record for annular fracturing on Valhall, redefined fluid engineering for the North Sea and will inform future annular fracturing deployments on other offshore assets around the world.

The ubiquitous challenge that is faced by chemical stimulation techniques, of any kind, has always been achieving an economic and efficient distribution of the stimulation solution across the exposed reservoir interval. Many have approached this problem from a chemical perspective and others from the use of additives for mechanical diversion; however the very nature of stimulation itself means that a changing injection profile will make efficient diversion by such techniques uncertain and unpredictable. Instead, rather than relying on serendipitous deployment techniques, the approach described and reported here places true mechanical diversion as part of the well construction process. This paper will completely describe the process and achievements to date, including successful application in a number of horizontal wells completed in the Austin Chalk, as part of an overall deployment plan.Essentially, this new completion system comprises of multiple pressure actuated assemblies, distributed along the liner/casing. These assemblies, when activated, allow the lateral deployment of forty-foot needles, radially distributed at ninety-degree phasing around the casing, into the unstimulated reservoir. These subs can be precisely located across pre-selected intervals and thereby provide certainty of acid treatment distribution. The acid is pumped through the needles themselves during stimulation; however production takes place through a suite of ports. A bespoke debris basket may be run, after the stimulation treatment, in order to recover a suite of needle deployment indicators. This run, if performed, effectively establishes the success of the deployment.In order to demonstrate the concept and avoid the high-cost environment of the North Sea, a low cost field trial location was sought and identified. An Austin chalk operator was looked for that had an extensive horizontal candidate well set available for re-completion in open-hole. A number of candidate wells were then identified and the wells were recompleted and stimulated with this new system. This paper will present the entire suite of data related to these deployments, stimulation operations, lessons learned, production impact and potential. This novel technology was greatly assisted, supported and delivered via the Joint Chalk Research (JCR) council, comprising of some ten operating companies that encourage, fund and drive the development of carbonate completion and stimulation solutions.

The Valhall and Hod chalk fields have seen the rise of single-trip multistage fracturing (STMF) that allows stimulating two to four zones in a single day in contrast to the average of one zone every 2 to 3 days for conventional applications. Recent advancements focus on lowering operational costs while bringing wells on production faster. One way of doing this is to further improve the STMF method by the introduction of fracturing through coiled tubing (FTCT). Conventional multistage fracturing operations use the plug-and-perforation method to complete each stage separately. With a sliding sleeve completion, coiled tubing (CT) is used to manipulate sleeves; then, proppants are pumped down the wellbore without CT in the well. Conversely, STMF uses a bottomhole assembly (BHA) with sleeve shifting tool and multiset packer for selective proppant stimulation down the CT-tubing annulus. Any underflush of proppants is cleaned by CT forward circulation. FTCT builds upon the STMF method, but proppants are pumped through CT. The underflush proppants are reverse circulated out of CT through a BHA without a check valve. FTCT was first used in a well at 5,000-m measured depth (MD) using a 6,700-m 2 7/8-in. CT. Data from this operation were used to match the friction calculation. In the second well at 6,500-m MD, intervened with a 7,400-m-long CT, 10 zones were stimulated using FTCT, and 2 zones with conventional fracturing. FTCT only required 8.5 hours whereas conventional fracturing took 75.6 hours per zone. The underflush volume was 50% less and removed through reverse cleanout that is 4 hours faster per stage compared to STMF. In the third well at 6,700-m MD, the well was killed with 1.35-SG heavy brine due to a leak in the completion. Proppant was pumped through CT and displaced with 1.04-SG brine. An increase in pumping pressure during reverse cleanout, compounded with the difference of fluid density, led to the collapse of CT section above the BHA. The collapse created difficulties for the BHA to unset, thus creating a mechanical sticking point, and hindered the ball drop release mechanism for the BHA. Awareness of pressure limitations of CT at the thinnest section is essential to improve the reverse cleanout design since high initial forces are required to reverse circulate. FTCT requires careful pressure analysis, especially when attempting operations in deep horizontal wells. Most standard CT cleanout simulation software lacks complete hydraulic modeling capabilities for reverse cleanout of crosslinked fluids with proppants. Data gathered from the three operations are thus important to improve the method. This study highlights associated challenges, considerations during design, operational benchmarks, and learnings from the world's longest FTCT operation in the North Sea.

This paper presents the development and installation of a modified stimulation system, based on an existing system, field-proven for more competent formations. The system simultaneously deploys 0.8 cm diameter, 12 m long needles from the main bore by jetting into the formation. Modifications have been made to facilitate production from a soft chalk formation, which is prone to plastic deformation and liquefaction under the stresses of production. The original design of single titanium needles has been changed to a combination of an aluminum outer needle for the deployment phase, and a titanium slotted inner needle for the production phase. The aluminum needle is dissolved by pumping hydrochloric acid, enabling production through the inner needle. The objective of the system is to reduce cost by simplifying the stimulation to a single pumping job, while achieving production enhancement for wells drilled in pay zones of less than 25-meter thickness. The objective of the field trial was to confirm the system could be deployed offshore, and to evaluate its production performance. A series of functional tests to ensure pressure integrity of the modified design were performed in the lab. Promising lab test results were extended to functional yard trials, to verify the chance of success at downhole-like conditions. The running procedure was modified to honor well control requirements, while optimizing the likelihood of successful deployment of the system. The paper presents the results of the qualification testing. The experiences from the installation and jetting are discussed in detail. Interpreted pumping pressure charts are presented for discussion. The productivity results are presented and compared to conventionally stimulated Valhall producer wells. The installation of the jetted needles system with solids-control slotted laterals is the first of its kind in the world. The results of lab and yard testing presents a solution for achieving solids control in laterals jetted out from the main bore. Analysis of the deployment data provides grounds for future optimization of the system. The productivity results are used to evaluate whether the system is ready for full scale deployment across an entire horizontal well.