The paper outlines the full-scale qualification testing of high differential pressure (ΔP) swellable element packers (SEPs) for fracture stimulation application in prop fracture stimulation in production wells on the Valhall Field, which is operated by BP Norge AS. The SEPs use solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe, which forms part of the reservoir liner. This eliminates the need to spot dedicated swelling fluid. Also discussed is the system used to perform the fracture stimulation in the field. The results of the successful qualification full scale testing up to 10k psi across two 5-meter packers are described. Details are also given for the Valhall Field operation with the deployment and swelling of 20 SEPs, followed by the hydraulic fracturing operation. Reservoir management for the Valhall redevelopment program relies on multi-zone water injection and proactive management of unwanted water production. Produced water isolation is achieved with an arrangement of heavy-duty sliding sleeve circulating devices. A method of annular zonal isolation to prevent flow behind the reservoir liner is essential to success. The oil-swelling SEPs offer a viable alternative and several improvements over the currently used cement barriers. These advantages are described in the paper. At the heart of these is the key requirement that any annular barrier must withstand very high ΔP (10k psi) during stimulation of the individual producing zones. Several unsuccessful attempts had been performed to qualify a SEP to 10k psi for Valhall; therefore, it was decided to try a new design featuring an innovative mechanical end-ring system. This represents a step change in the design methodology of SEPs. It enables reduction of element length and packer OD while retaining high differential pressure (DP) ratings and/or increase the DP rating of long SEPs. The features and benefits of the new SEP design are presented.

Historically, cemented plug and perf completions have been used for wells requiring multistage fracturing and stimulation in the North Sea. This is a well-known and trusted process, but also time consuming. Often the turnaround time per stage in the North Sea is 3-7 days. With high rig and frac vessel rates, this excessive operational time can negatively impact project economics and well payback times. Consequently there is a drive to develop new systems to gain efficiencies without compromising the quality of the planned stimulation treatments in these applications. This paper will review two newly developed novel completion systems that significantly reduce time spent performing multistage stimulation in environments where cost and consequence of failure are high. North America land frac operations rely heavily on ball drop actuated frac sleeve systems now commonly available in the market, however these typically require some over displacement of the previous frac stage and typically are only available for un-cemented liners. Hence, these are not always a good fit for North Sea frac applications. In order to prevent compromising the required stimulation treatment and allow flexibility to run cemented reservoir liners with frac valves, new technologies had to be developed. Both coiled tubing and wireline manipulated sliding sleeve/valve systems and ball-drop actuated systems have been developed and deployed depending on the various completion and stimulation challenges faced. Since the first installation in 2009 these systems have been proven and refined in multiple wells for two large operators. Various well installations will be discussed, illustrating that systems are being tailored for open hole and cemented environments both for proppant and acid frac stimulation treatments. The paper will give the audience insight into the depth of options available with these systems and explain how they are tailored for different types of stimulation and zonal isolation requirements. In addition operational considerations and experience will be shared. Testing and field data will be presented to verify the development, installation, operation and success of these systems. This data include pressure and temperature data, downhole monitoring during stimulation and sleeve manipulation. An overview of the results and efficiencies achieved in the installations will be presented and compared to conventional methodologies. These completion solutions have a broad application in areas where fracturing and stimulation is required and project cost and risks are significant, both in conventional and unconventional stimulation and fracturing operations. The installations discussed in the paper include first ever proppant frac done offshore through these systems, and introduction of specially developed intervention tools to aid the operation of the system. It also covers the first ever successful installation of cemented frac valve reservoir liner completions in an offshore environment as well as the use of dissolvable frac balls.

Since the introduction of swellable technology to the oilfield in 2001, its acceptance has grown significantly, and the scope of applications has expanded accordingly. Most of its usage has been in applications in horizontal, multi-zone fracturing, and in combination with inflow control devices (ICDs) and screens during the completion phase of the wells. One application that is gaining interest globally is the use of swellable tools during the well construction phase. The main objective here has been to provide extra sealing capability in addition to that of the cement sheath to prevent a micro-annulus or a mud channel when the packers are cemented in. In certain cases, swellable elastomer packers (SEPs) are designed to provide a full redundant seal above the top of cement (TOC). There are several reasons why SEPs and cementing operations are a good fit; primarily, the application of the technology is simple to implement, and allows pipe movement during the cement job. One other advantage is the fact that no specialized personnel are required for packer installation. However, several implications to the use of SEPs in combination with a cement job must be considered: Packer design and impact on cement placement; the packer must not impact the cement placement, as the main objective of a cement job is to get the cement slurry placed properly. Impact of swelling rubber on cement matrix once the cement is in place, it is important to know whether the SEP will impact the hydration process (setting) of the cement, changing the properties of the set cement. Bonding at the cement/rubber interface; the bond at the cement/rubber interface must be confirmed. This paper discusses the issues above, and benefits that can be expected when SEPs are used during well construction. Two case histories will be presented to illustrate the use of SEPs during the well construction phase.

TX 75083-3836, U.S.A., fax 01-972-952-9435.Abstract BP-Norge AS operates the Valhall Field in Norway and relies on multi-zone water injection for reservoir management and control of unwanted water production for Valhall wells. A produced water shutoff method in this field is necessary, and equipment must be capable of maintaining integrity at differential pressures of 10,000 psi during prop-fracture stimulation of the individual zones in the oil-producing wells. The operator wanted to find a new completions solution that would enable long horizontal reservoir sections to be completed and stimulated with the capability to shut-off unwanted water at a later time during well life.Swellable elastomer packers (SEPs) were suggested to the operator as a possible method for zonal isolation. Unfortunately, three attempts to qualify the currently available SEPs to the 10,000-psi differential pressure (DP) for Valhall were all unsuccessful; therefore, the decision was made to try a new design that used an innovative mechanical end-ring system. This configuration uses a solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe that forms part of the reservoir liner. This eliminated the need to spot dedicated swelling fluid.The changed configuration represented a significant step change in the design methodology of SEPs. The new design not only enabled the reduction of element length and packer OD, but it also could withstand the high DP ratings as well as increased the DP ratings of long SEPs. The new configuration required qualification testing, and this paper presents the case history of the operator's full-scale qualification testing up to 10,000 psi across two 5-meter packers as well as the improvements the new SEPs could offer over previously used equipment and methods.The paper will also discuss the design, other potential applications, and the advantages of the new SEP design. A case history of the first installations of the new SEP worldwide will be presented as well.

The paper outlines the full-scale qualification testing of high differential pressure (∆P) swellable element packers (SEPs) for fracture stimulation application in prop fracture stimulation in production wells on the Valhall Field, which is operated by BP Norge AS.The SEPs use solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe, which forms part of the reservoir liner. This eliminates the need to spot dedicated swelling fluid.Also discussed is the system used to perform the fracture stimulation in the field. The results of the successful qualification full scale testing up to 10k psi across two 5-meter packers are described. Details are also given for the Valhall Field operation with the deployment and swelling of 20 SEPs, followed by the hydraulic fracturing operation.Reservoir management for the Valhall redevelopment program relies on multi-zone water injection and proactive management of unwanted water production. Produced water isolation is achieved with an arrangement of heavy-duty sliding sleeve circulating devices. A method of annular zonal isolation to prevent flow behind the reservoir liner is essential to success.The oil-swelling SEPs offer a viable alternative and several improvements over the currently used cement barriers. These advantages are described in the paper. At the heart of these is the key requirement that any annular barrier must withstand very high ∆P (10k psi) during stimulation of the individual producing zones.Several unsuccessful attempts had been performed to qualify a SEP to 10k psi for Valhall; therefore, it was decided to try a new design featuring an innovative mechanical end-ring system. This represents a step change in the design methodology of SEPs. It enables reduction of element length and packer OD while retaining high differential pressure (DP) ratings and/or increase the DP rating of long SEPs. The features and benefits of the new SEP design are presented.