Recently, there has been an increased interest in optimising horizontal multifrac completion technologies used to complete unconventional US onshore wells. The developing technologies and techniques are increasingly being used for offshore applications and have found widespread use in horizontal wells in areas such as the southern North Sea. This case history describes the application of two complementary technologies which have enabled the placement of 1.4 million pounds of proppant in four treatments within 4 consecutive days. Prior to this similar offshore completion operations have typically taken 12 to 25 days. Historically, cemented liners and "plug-and-perf" completions have been used for horizontal fracturing in the southern North Sea. Such operations often involve extensive coiled tubing interventions between fracturing stages. This introduces unnecessary technical and associated operational risks due to the extended, long horizontal well architectures that are often used. An openhole, ball-activated multi-stage system, recently introduced into the North Sea, was applied in tandem with the application of a new environmentally-compliant seawater fracturing fluid. The use of the seawater-based system allowed sufficient fluid volume to be loaded and pumped for the placement of four hydraulic fracturing treatments on consecutive days, without the need for the vessel to disconnect and sail back to port to reload fresh water. As a result of this dual development and correct application of the completion technologies, the requirement for coiled-tubing interventions between stages was eliminated, saving both vessel and rig time. Ultimately, such savings result in faster turnaround times for wells to be placed on production, thereby improving overall well economics. Following the success of the application of this technology the operator is actively pursuing similar new complimentary technologies. Such operational improvements will not only enhance well economics, but possibly define future North Sea fracturing operations.

There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. Tight reservoirs, distant infrastructure, small volumes, and anomalous gas qualities are amongst the main reasons why these resources have not yet been developed. One of these stranded tight gas fields has been successfully developed with the use of a subsea well, horizontal drilling, and hydraulic fracturing. The Kew structure is a northwest/southeast trending horst straddling licenses 49/4c, 49/4a, 49/5a, and 49/5b of the UK sector approximately 2 km east of the Chiswick field. The primary reservoir objectives are the Carboniferous sandstones of the Caister formation (Westphalian A). This gas field has now been developed with a singlewell that employs a combination of horizontal drilling and multistage hydraulic fracturing to achieve maximum reservoir contact in this low-permeability and interbedded structure. The absence of data and analogue wells for the design and execution of the fracturing treatments necessitated extended injection tests prior to the execution of the stimulation treatments. To maximize the data acquired from this well, chemical tracers were injected during the stimulation treatments and returns evaluated to assess the flowback of each individual hydraulic fracture. As this was a subsea development well, all the hydraulic fracturing operations had to be performed with the rig in place. Hence, the utmost efficiency of the operations was paramount; otherwise, the economics of the project would be negatively impacted. Innovative techniques of isolation between each fracturing stage were developed to minimize the risk and decrease completion time. The time of massive gas field discoveries has passed, and smaller developments are proving to be the future, through tying them to existing assets, to boost gas production in the North Sea and extend the life of the existing infrastructure. This challenge was successfully addressed for the Kew field by combining existing technologies and developing new techniques.

Summary In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 md have been developed with horizontal wells with transverse fractures. The potential negative effect of convergent flow in the fractures seems to have been forgotten. The widespread use of resin-coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared with uncoated proppant. Several North Sea horizontal and deviated multifracture gas wells that used RCP and had a significant mechanical skin are presented. Pressure-buildup data confirm the presence of a near-wellbore pressure drop in the fractures. Reservoir simulation with a fine grid reproduces the observed pressure drop because of convergent flow, using realistic proppant-pack permeabilities with gel damage. The effect of proppant production on the convergent-flow skin is shown using production data before and after discrete proppant-production events, demonstrating how proppant production has a beneficial effect on removing convergent-flow skin. We also compare the performance of a new horizontal multifracture well to the original discovery well in the same location, in which a vertical well was fracture stimulated with uncoated proppant and had comparable productivity. If there is a large convergent-flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create “infinite conductivity” channels at the perforations. This removes the convergent-flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily, and convergent flow acts as a downhole “choke” on production. This “choke” can produce a significant positive skin. In the worst case, a horizontal multifracture well with three or four transverse fractures can produce the same as a fully perforated vertical well with a single fracture. On the basis of a number of real-world incidents of proppant production during post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well productivity index (PI) and a decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. In this paper we highlight the potential reduction in well productivity from using RCP for fracturing in gas wells (0.1 to 10 md) with limited inflow area (transverse or oblique fractures), where convergent-flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite-conductivity channels and removing the convergent-flow skin.

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In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 mD have been developed with horizontal wells with transverse fractures. The potential negativeimpact of convergent flow in the fracture seems to have been forgotten. The widespread use of resin coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared to uncoated proppant. A number of North Sea horizontal and deviated multi-frac gas wells that used RCP and had a significant mechanical skin are presented. Pressure buildup data confirms the presence of a near-wellbore pressure drop in the fracture. Reservoir simulation with a fine grid reproduces the observed pressure drop, due to convergent flow, using realistic proppant pack permeabilities with gel damage. The effect of proppant production on the convergent flow skin is shown using production data before and after discrete proppant production events, demonstrating how proppant production has a beneficial effect on removing convergent flow skin. We also compare the performance of a new horizontal multi-frac well to the original discovery well in the same location, where a vertical well was fracture stimulated with uncoated proppant, and had comparable productivity. If there is a large convergent flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create "infinite conductivity" channels at the perforations. This removes the convergent flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily and convergent flow acts as a downhole "choke" on production. This "choke" can produce a significant positive skin. In unfavorable cases, a horizontal multi-frac well with 3 or 4 transverse fractures will produce the same as a fully perforated vertical well with a single fracture. Based on a number of real-world incidents of proppant production during the post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well PI and decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. This paper highlights the potential reduction in well productivity due to using resin coated proppant for fracturing in gas wells (0.1 to 10 mD) with limited inflow area (transverse or oblique fractures) where convergent flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite conductivity channels and removing the convergent flow skin.