Simple, cheap, and reliable treatment of produced water will transform the economics and viability of unconventional plays. Produced water recycle not only creates options to minimize fresh water usage; in local areas it can take tens of thousands of water hauling trucks off the road and significantly reduce salt water disposal. This is no pipe dream. A novel process based on a step-change in the application of chlorine dioxide chemistry has been proven to work and consistently generate frac-compatible fluid at several company facilities in Texas. The solution is an inline system that simplifies the operation, optimizes chemical consumption, and enables continuous on-the-fly treatment. Case studies over multiple years and greater than 18 million barrels used at the field level show that produced water is being recycled for less than half the equivalent cost of using fresh water.
Summary Andrew field in the U.K. Continental Shelf, which is operated by British Petroleum (BP) Exploration, is being developed using horizontal oil producers and completed with cemented liners. The main challenges of perforating these wells are maximizing well productivity by avoiding formation damage, minimizing the possibility of sanding, maximizing ultimate hydrocarbon recovery, perforating long horizontal sections safely and efficiently, optimizing the economic value of perforating, and minimizing perforating debris. In general, to avoid impairing well productivity, it is best to perforate the underbalance. However, the advantage is compromised, because of the fluid invasion and loss-control material, if a well will be killed when the tubing-conveyed perforating (TCP) guns are removed. Existing deployment methods with coiled tubing (CT) enable perforation and subsequent gun removal in an underbalance condition. Unfortunately, various limitations would require multiple runs with CT for perforating each horizontal well in the Andrew field, which would result in significant time and on balance perforation for each subsequent run. The combination of the newly developed mechanical ball valve and the deployment of TCP guns with hydraulic workover units enables long horizontal wells to be perforated in one run in underbalance, and enables the guns to be removed without killing the well. Specially engineered guns and perforating charges are used to minimize sanding and gun debris. This paper describes how these new technologies, used for perforating operations, meet many challenges. The same technologies can be used readily for perforating other long horizontal wells with similar problems. To date, three horizontal wells in Andrew field were perforated successfully with the method described in this paper. The initial results indicate that the combination of the cemented liner completion, the engineered perforation systems, and the correct TCP gun deployment method using the mechanical deployment valve have contributed to improve well performance, to reduce cost, and to improve operability and safety in long horizontal wells.
The Andrew Field produces from a Palaeocene sandstone saturated oil reservoir, in UK North Sea Blocks 16/27a and 16/28. Cyrus is a small subsea tieback, 7km NE of Andrew, containing undersaturated oil. Both fields are operated by BP Exploration. Field development was sanctioned in 1994, some 20 years after discovery. During those 20 years, numerous development concepts failed to achieve the expected economic return. However, in 1992 the Andrew well count was reduced from 18 to 10 by changing from vertical to horizontal producers. In conjunction with an Alliance risk/reward approach to topsides construction, which was expected to significantly reduce Capex, development sanction was obtained. Andrew development drilling started in September 1995, with three pre-drilled template wells. These were tied-back to the platform in 1996 and followed by further platform-drilled producers. A 1993 horizontal appraisal well was also tied back as an Andrew producer. Two horizontal subsea producers were drilled on Cyrus in 1996, replacing two earlier horizontals wells which had suffered rapid water production. First oil was achieved in June 1996, 6 months ahead of programme. Current production is at the expected plateau level of about 58 000 bbl/D from Andrew and 12 000 bbl/D from Cyrus. Reducing well numbers and using only horizontal wells relies on the long term performance of these wells for economic success. Andrew/Cyrus is amongst BP's first all-horizontal field developments. Key design decisions started at the sandface completion: openhole sand control screens were considered because of sand production concerns; the cost and difficulties of cementing and perforating long horizontal liners were reviewed; the savings from using pre-holed, uncemented liners were set against the concerns over long-term production and external casing packer (ECP) reliability. Multilaterals were also considered in detail. The outcome of this work was to install pre-holed liners with cement inflated ECP's in both Cyrus wells, but to use cemented and perforated liners on Andrew. The Andrew Well Engineering Alliance was created, and was aligned to BP's key business objectives through the 'minimum performance standards' of well on target, % of the horizontal section contributing to flow, zonal isolation and data acquisition. These measures were the basis of triggers for gainshare payments. Maximising the % contributing to flow led to the world's first through-tubing, underbalanced, single trip, no kill, horizontal perforating system using a hydraulic workover unit and formation isolation valve. The success of this approach has been confirmed by recent coiled tubing production logging (CT-PLT). This paper discusses the reservoir uncertainties and anticipated well management challenges. It describes the balance of factors that impacted the design of the horizontal completions. Initial well construction experiences and the first 6 months of production are described. Development Outline Figure 1 gives an outline of the development area. The Andrew topsides were installed in May 1996, with the gas and oil export pipelines and subsea bundle tie-back of Cyrus completed a few weeks later. Andrew reserves are estimated at 112 × 106 bbl. Development drilling on Cyrus has suggested that the sanction estimate of 24 × 106 bbl was optimistic, with the structure being somewhat smaller than expected. Cyrus 're-development' is through primary depletion from two new horizontal wells, replacing the previous horizontals. The Andrew reservoir, a four-way dip-closed structure with a 58m oil column between gas cap and aquifer, is being developed with ten horizontal producers. It is expected that aquifer support will be sufficient to maintain reservoir pressure. Whilst the development includes a vertical gas management well completed in the gas cap, there are no plans for water or gas injection wells for pressure maintenance. P. 375^
Most oil and gas wells are cased and perforated. Perforating is usually the most important part of completing a well because it has a major impact on well productivity. However, conventional perforating studies use single-shot perforations into cylindrical core targets, which do not provide information on the interaction between phased multiple perforations. Four laboratory ‘Block Tests’ were performed during 1991 and 1992, in a joint venture between BP Exploration, Schlumberger, Elf Aquitaine and Oryx Energy. A 4 3/4" (121mm) wellbore was drilled through each of the 25 ft3 (0.7m3) blocks of Berea sandstone. Each block was loaded into a large ‘stress frame’ and placed under confining stress before a 3 1/2" (89mm) diameter casing was cemented in place. The four tests included underbalance and overbalance perforating, well killing, clean-up and acid stimulation. A pack-off tool was used to measure the flowrate from individual perforations. The differences between perforations and the interactions between them dominated the behaviour of the large sandstone blocks. Variability in the apparently homogeneous Berea sandstone, over just a few inches, meant that no two perforations behaved in exactly the same way. The work showed how the most productive perforation can become the least productive after killing a well, and how a poorly designed kill pill can give clean-up from very few perforations. Underbalance and overbalanced perforating did not give the expected results. By simulating the downhole situation with real phased perforations, the Block Tests improve the understanding of what happens downhole, allowing better design of well operations.
The reliable calculation of tubing pressure drops in oil and gas wells is important for the most cost effective design of well completions. None of the traditional multiphase flow correlations works well across the full range of conditions encountered in oil and gas fields. Consequently, two of the recently published "mechanistic" models, one by Ansari, the other by Hasan and Kabir, were evaluated. The performance of these methods was compared against traditional correlations in three ways:The predicted against measured pressure drops were compared for stable flow conditions using 246 data sets collected from 8 producing fields, including a gas and gas-condensate field. None of these datawere available to the developers of any of the multiphase flow model sevaluated.Suitable methods should reliably predict the "lift curve minima".This determines when a well may need to be "kicked off", artificially lifted or recompleted.The multiphase flow model must not contain discontinuities or be subject to convergence problems. No single traditional correlation method gives good results in both oil and gas wells. In fact, most of the traditional methods which work reasonably in oil wells give very poor predictions for gas wells. Hasan and Kabir's mechanistic method was generally found to be no better than the traditional correlation methods. However, the Ansari mechanistic model gave consistently reasonable performance. Although it did not give the most accurate results in every field, it gave reasonable results across the complete range of fields studied. The Ansari method also gives a reliable prediction of the lift curve minima. Areas in which it needs improvement were identified. By comparison the best of the traditional methods, the Hagedom and Brown correlation, gave good results forstable flow conditions in oil wells, but it does not correctly predict the lift curve minima. A field example shows how this can lead to erroneous conclusions. Background Flow up the tubing in oil and gas wells is usually multiphase. Calculation of pressure drops in upward multiphase flow is not simple, due to the slippage of gas past liquid, along with the changing temperature and pressure conditions. Nevertheless, Petroleum Engineers need to predict pressure drops in oil and gas wells for the following reasons:To construct "lift curves", which are tables or plots of flowrate versus bottom hole pressure, used to predict well flowrates.To select the appropriate tubing size. If the tubing diameter is too large, the well acts as a gas-liquid separator and a flow conduit, and the excessive slippage results in needlessly high bottom bole pressures. However, tubing which is too small will cause excessive frictional pressure drops.To design artificial lift completions such as electric submersible pumps, jet pumps or gas lift. Several multiphase flow correlations are available for predicting tubing pressure drops. P. 109^
The BP Schiehallion and Foinaven oilfields West of Shetland are benign shallow reservoirs, but lie in a harsh subsea environment, with 350-550m water depth. There have been up to three 4th generation semi-submersible rigs operating yearround in these fields since development drilling began in 1995. The two fields currently deliver about 250 Mstb/day from 2 FPSOs, 25 gas-lifted oil producers, 15 water injectors and 2 gas disposal wells. As the end of development drilling approaches, the rig programme will focus on infill and satellite targets over the next few years. With operating costs approaching US$250,000 per day per rig, the major part of well cost is rig time, and so rig time savings represent very significant cost savings. High angle and extended reach wells are usually required for these fields, putting completion packers beyond wireline access. The early completions used extensive coiled tubing operations to run and pull plugs as part of completion installation and often suffered from non-productive time and waiting on weather associated with the coiled tubing work. Completions could take up to 15 days, excluding the subsea tree installation, highlighting the potential savings of interventionless completion installations. In 1999, following experience on 25 West of Shetland wells with other interventionless systems, the newly developed SB-3H packer was used for the first time. The primary method of packer setting is by rupture disk against an atmospheric chamber. There is an independent, secondary, hydraulic setting mechanism. The new interventionless hydrostatic packer can reduce rig time to set the packer from as much as 6 days (working with coiled tubing on floating rigs in poor weather) to less than 30 minutes. On top of these immediate cost savings, eliminating intervention brings significant health and safety advantages. This paper describes development and application of the interventionless hydrostatic packer. Several other changes in completion practices are also mentioned, which together with the SB-3H packer have cut completion installation times by up to 50%. Introduction The West of Shetland Foinaven and Schiehallion reservoirs are benign, shallow turbidite Tertiary sands, requiring high angle wells to access reserves and improve production rates(1). Figure 1 shows a typical high angle well profile for a West of Shetland well. Such profiles prevent wireline access to the packer / liner top. The sands are also weak, around 500-1000 psi unconfined compressive strength, requiring sand control completions in all oil producers and in most water injectors. From the start of planning development wells, there was considerable focus on efficient drilling(2) and completion installation and on designs to last for life of field. The field developments are high profile and a significant milestone for the UK industry, opening new oilfields in a new province. Premium connections were used throughout the production casing and completions. Thirteen-percent chrome metallurgy was used for production wells, while water injectors used Inconel jewellery with lined or coated carbon steel tubulars. All wells used surface-controlled subsurface safety valves and permanent packers without an expansion joint. The oil producers also have conventional gas lift mandrels and permanent pressure/temperature gauges. Conventional dualbore subsea trees were used, 5×2 for Foinaven and 7×2 for Schiehallion. High rig rates provide a clear focus for avoiding workovers and interventions.
In sand-producing formations, a cased hole gravel pack is usually the preferred completion method. There are various reasons why the alternatives, an open hole gravel pack or a sand consolidation treatment, may not be suitable. However, the productivity of the cased hole gravel pack is much poorer than the alternatives because of high mechanical skins. Despite the importance of this mechanical skin, the existing pressure drop prediction models are incomplete. Many papers deal with the region of linear flow in the casing/cement tunnels and the flow through the gravel between casing and screen. What happens just outside the casing is rarely mentioned, even though the pressure drops beyond the casing may be significant. One complication is that perforation tunnels in the formation might either remain intact or they could collapse before gravel packing, creating a void behind the casing. This paper presents new methods for predicting the pressure drops outside the casing and so allows the construction of a comprehensive model for cased hole gravel pack productivity. A newly-developed finite difference computer simulator was used to produce a general method for intact perforations packed with gravel. For collapsed perforations, an analytical method was developed which is based on the amount of gravel placed behind the casing.
The Clair Ridge field development is located in the UK Continental Shelf, 142 miles north of mainland Scotland. This is the second phase of the Clair Field Development involving a subsea pre-drilling campaign and programmed long term well suspensions prior to new platform arrival. Two pre-drilled horizontal wells have been successfully completed with downhole sand screens in a geologically challenging environment, and suspended with cleaned-up hydrocarbons across the reservoir until the wells can be tied back to the platform in 2016. The reservoir drilling and completion design strategy was complicated due to the reservoir section being a naturally fractured sandstone alongside high permeability and weak matrix intervals susceptible to sand production. This presented several challenges to the team: the high risk of losses whilst drilling the reservoir with the probable use of large volumes of lost circulation materials (LCM), the risk of damage to the natural fractures or high permeability zones impacting subsequent well productivity, the need for down hole sand control completions, the ability to run these across a reservoir section containing large amounts of sized calcium carbonate LCM materials and also the mitigation of screen plugging from filter cake and LCM during well start-up. The downhole completion hardware was specifically designed to allow efficient placement of chemical breaker to dissolve LCM and filter cake to reduce the risk of sand screen plugging. The importance of minimising screen plugging and formation damage was also dictated by long term suspension of the pre-drilled wells required for start-up of a new offshore platform. This paper details the reservoir sand control completion design philosophy, the drilling and completion fluid system design and assurance testing in readiness for the technical challenges to be faced and the overall operational practices used in the field execution. The well flow-back and test results exceeded expectations, indicating good flowing length, greater than predicted Productivity Index (PI) and absence of skin damage, which creates significant benefit for the Clair Ridge project.
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