24 Frontiers April 2003

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24 Frontiers April 2003

  1. 1. 24 Frontiers April 2003
  2. 2. BP is engaging with a wide variety of technologies as it seeks ways to construct new wells more economically and keep older wells running at their best. Terry Knott looks at two of the many projects under way ince Edwin ‘Colonel’ Drake drilled busily pushing out the boundaries of S the first well to tap the ‘rock oil’ of Pennsylvania in 1859, oil wells have moved on in scale and sophistication to current know-how on several fronts. Two of the projects being actively pursued by the company’s well technologists in the point where Drake would recognise Houston are focused on improving only the black gold flowing from the the performance of gas wells: one wellhead. Compared with his primitive by introducing plastic liners into the 21m-deep hole, today’s drilling technology wellbore, another by applying an expert can bore holes with pinpoint accuracy system to optimise production. down to depths measured in many thousands of metres, turn at angles to run Problem-solving plastic horizontally along targeted oil payzones, Corrosion is an inherent problem in and branch out in multiple directions. almost all hydrocarbon wells, as liquids Now wells are being rendered intelligent and gases carrying a range of chemical by the installation of monitoring and components interact over time with communications equipment to relay the steel production tubing in the well, information back to the surface (Frontiers, the main artery to the surface. The April 2002), and are being equipped with conventional solution is to ‘pull the well’ – downhole devices to enable flows from removing and replacing hundreds or different zones of the reservoir to be thousands of metres of tubing, a major turned on and off as their performance operation requiring a drilling rig. Costs changes over time. can be high, particularly offshore, running But drilling the hole and then sometimes to millions of dollars. completing it by constructing a complex One alternative for dealing with metal-clad passageway to the surface, corrosion being investigated by BP is are only the beginning of the story. To to install plastic liners inside the tubing, maximise the value of a well over its removing the contact zone between lifetime, it must be maintained against hydrocarbons and steel and avoiding the wear and tear and a variety of techniques pulling operation. Besides being a much need to be employed to coax the most less expensive solution, the technique hydrocarbons through it. To this end, BP’s offers several potential benefits, as exploration and production specialists are George King, who holds the position >> Frontiers April 2003 25
  3. 3. load is released from the liner, allowing it to Installing a tight fit liner expand to form a tight fit against the steel tubular – as the liner’s true diameter is greater than the internal diameter of the tubular, it expands and fills corrosion pits, Spool of plastic liner pipe Power wheel channels and into the spaces of tubular connections. The weights are fished out through the set plastic liner, any excess liner Roller reduction wheels reduce length arising from linear expansion is cut off pipe diameter by 13% at the top, and a flanged cap is heat fused to the top of the liner to seal it. Several materials of manufacture have been evaluated by BP. Cross-linked high density polyethylene (HDPE) has been Wellhead selected as an initial way forward for its Liner is run strength and resistance to water and gases into the well Weights attached to the and erosion from sand, aimed at applications liner keep its diameter up to around 100˚C and pressures of 2000 reduced until it reaches the bottom of the well pounds per square inch (psi). Reels containing several thousand metres of such a liner can be transported by road – liners can be joined by heat fusion to create longer lengths, and >> of distinguished advisor in BP’s well BP. The industry has some experience of are suitable for both production and injection interventions team in Houston, explains. lining the inside of the larger outer casing of wells. A nylon ‘research liner’ material, suitable ‘Plastic liners are a way of rejuvenating wells with plastic materials. But installing for dry gas wells, is also under test by BP. the tubing without pulling it. The primary plastic liners in situ into the smaller bore Should tight fit liners need to be removed, purpose is to seal any leaks which may be tubing inside the casing – internal diameters this can be done by running a cutting tool present and provide a barrier to any further are typically 50-125mm – requires new down the well. As the tool is pulled up the metal loss. But there can be other benefits too. techniques to be developed. To this end, BP well, it cuts the liner along its length and rolls ‘The reduced diameter created by a liner began carrying out onshore trials two years the liner onto itself, reducing its grip on the increases flow velocity which helps lift ago in Texas, followed by further field tests tubing. This allows the liner to be pulled out liquids up the well – in some older gas wells, last summer in Oklahoma and Alaska. of the well. In conjunction with reduction liquid build-up at the bottom of the well can Three principal types of liner are under roller specialist Trican Production Services of be a problem as it can create back pressure evaluation: tight fit, velocity, and thermal Canada, BP is now developing a purpose- in the reservoir formation and reduce liners, each of which has a different designed lightweight unit for installing plastic production. Plastic is also a better thermal target application. liners in offshore wells. insulator than steel, which means heat Tight fit liners are primarily aimed at well losses are reduced. This helps maintain tubing repairs. To install a tight fit liner, a Lifting liquids higher fluid temperatures as the continuous plastic tube is fed from a reel into Sometimes tubing repair is not the primary hydrocarbons move up the well through a objective. As low rate gas wells age and gas the well, preventing roller reduction unit, rates drop, liquids fall back into the well – a liquids from condensing Plastic liners could which squeezes the higher flow velocity is required to lift the and falling out. tube and reduces its liquids up the wellbore. In these cases, a ‘Flowing friction is also help wells deliver diameter (see figure second kind of liner, a looser type known as reduced by the smoother surface of plastic liners. between 10% above). This technique has been adapted from a velocity string, can be installed to occupy part of the flow path in the tubing to increase This can contribute to better production, and it and 30% higher lining horizontal pipelines but using flow velocity. ‘Where velocity strings are installed, steel also may reduce the deposition of scale, waxes production levels thicker plastic, around 5mm thick, depending coiled tubing (CT) has been the widely used conventional solution because of its relatively and asphaltene on the on the application. The low cost,’ says Donald Reeves, production surface of the liner, decreasing the need for liner deforms in the elastic range, reducing engineer in BP’s upstream technology costly intervention to remove these.’ its diameter. For example, a 132mm outside interventions team. ‘The CT, usually older The twin economic prizes of reduced diameter liner can be reduced to 117mm, retired stock with diameters below two maintenance and higher output – 10-30% allowing it to pass inside the 124mm internal inches, is fed into the wellbore tubing and is more production may be possible, says King diameter steel tubing in a well. suspended from the surface. The resulting – are certainly attractive. As he points out, in The liner, sufficient to cover the entire flow can be inside the CT string or forced up the North American arena alone, BP operates well or sized to act as a shorter repair ‘patch’, the annular space outside the CT. over 6000 wells, some of which, notably low is pulled into the well by attaching weights – ‘But CT is designed for short duration well pressure gas wells, have been in operation drillpipe collars – at its lower end, weighing workover operations, not long-life in-well for 40 years and may have 20 years or longer around a tonne in all. Once the weights reach service. Friction losses are high due to its to run. Keeping these in production safely, the bottom of the well or touch down on a rough surface, particularly if it is old material, with minimal maintenance cost, is a goal for temporary plug pre-set in the well bore, the and the CT is prone to corrosion, especially 26 Frontiers April 2003
  4. 4. so if carbon dioxide is present. This brings ‘Vacuum insulation of the steel tubing is well, as its own weight is sufficient and the the risk that the CT will fail and drop into the one solution to this problem,’ says King, ‘but toothed profile reduces wall drag. Diameter well. And when you have CT in the wellbore, this carries a price tag around ten times reduction in this case can entail plastic following a loose, indeterminate pathway, it higher than using plastic thermal liners. The deformation, permanently reducing the means you can’t always get wireline tools goal is to raise the gas temperature at the outside diameter – subsequent thermal into the well for other normal interventions.’ surface – in many cases a temperature expansion due to temperature in the wellbore As an alternative to steel CT, BP has increase of 13-22ºC is all that is needed to causes the liner to expand to grip the sides been experimenting with velocity liners prevent condensate dropping out over of the tubing, giving the liner support. manufactured from composite materials – several thousand metres of the well. Thermal In addition to its mechanical and thermal for example, a corrosion resistant plastic inner liners have a material heat insulation capacity properties, the liner’s profile brings other sheath with a braided Kevlar reinforced outer, over a hundred times greater than steel and benefits. When the teeth contact the tubing giving the liner both corrosion and erosion of the order of twice that of the whole steel wall they form ‘back channels’ which can be resistance and the inherent well system, and can used for gas venting or gas injection, or act strength to hang from the provide the desired as passages for chemical injection. surface (see figure, below right). The liners can be You could say temperature increase. We expect to see up to 30% Validation of the thermal model BP has developed for the liners will come from an sized to give a closer fit we are heading hydrocarbon production onshore trial which has just begun in a gas in the wellbore than CT – uplift as a result.’ well in the Red Oak field in Oklahoma. a diameter difference one day for BP is currently testing Looking ahead, BP sees significant down to 5mm between a thermal liner having a potential in the thermal liner and its overall liner and tubing is possible. the shallow cross section like a gear concept, and is looking now at several This causes the bulk of the fluids to flow up the inside all-plastic well wheel, which can be applied to existing wells variations on the theme. ‘In theory, if you can get the costs right, of the liner where low or built into new well you could replace the steel tubing entirely with friction enhances production rates. completions. This can be manufactured to such a liner in shallow, low pressure wells,’ For installation, conventional CT reeling a given outside diameter with an inside King comments. ‘You could then extrapolate equipment can be used to run the composite diameter of choice, or even internally tapered from there and say we are heading one day liners, which, because of their open bore and to boost velocity lower down and decrease for the shallow all-plastic well.’ controlled position, retain access space for friction nearer the surface, serving as a wireline operations. BP’s North Sea velocity string as well as a thermal liner. Taking the plunge operations are also experimenting with this Nylon and HDPE are the materials of Gas wells in BP’s onshore business unit material, under the guidance of Stuart Shaw manufacture currently under evaluation, the in the USA and Canada are the focus of and Darrel Wood in Aberdeen. latter in the form of the proprietary ChemPex attention of another project aimed at Composite velocity strings bring cross-linked polymer. The resulting liner is boosting production levels, in this case not advantages over CT, but there are still issues extremely strong, so much so that at small by modifying the wellbore, but by applying to be addressed, says Reeves. While the diameters it is thought to be light enough to know-how and automated controls to their reinforced composite is capable of standing stand without buckling under its own weight, operation in the form of an expert system. burst pressures up to 2000psi, its collapse enabling it to be installed directly into ‘In low rate gas wells, say those strength is low, requiring internal pressure to existing wells using conventional CT producing less than 3000 cubic metres be kept above external pressure in the small equipment and without expensive surface of gas a day, the accumulation downhole annular space. BP is looking at a variety of hangers or wellhead modifications. of even small quantities of produced water ways to ensure that internal pressure is Larger diameters can be installed using or condensate seriously constrains gas always greater. Upfront capital cost is the roller reduction method, although there is production,’ explains Carl Sisk, well another challenge and new composite no need for weights to pull the liner into the performance programme manager. >> materials are being investigated to close the gap on used CT which currently costs around one third of the plastic alternative – however, Liners for speed, liners for insulation CT will need frequent in-service replacement due to corrosion. A composite liner Composite Thermal thinking (shown in cutaway, velocity near right) can be liner The third category of plastic liners is made strong enough essentially a new idea being driven forward to hang from the surface wellhead. It is by BP, referred to as thermal liners. Aimed used to increase the Thermal primarily at low pressure gas wells, thermal velocity of well fluids. liner liners can be used to reduce heat loss from BP’s experimental thermal liner (far right) the well fluids through the steel wellbore will preserve the into the surrounding rock formation. If the temperature of well temperature of the produced gas can be fluids to prevent liquids condensing in preserved, there is less tendency for water the well. The liner can vapour and hydrocarbons to condense and also serve as a Well velocity string cause liquid build-up at the bottom of the well and in the reservoir. Frontiers April 2003 27
  5. 5. the well at intervals, dependent on manually Plunging to the depths adjusted pressure settings. Both approaches involve teams of field operators, continually In gas wells where liquids build up over time, monitoring the performance of the wells to plungers (like the example shown on the right) adjust equipment settings in attempts to get are used to intermittently drive the liquids from the well (see diagram below). BP has developed optimal gas output from the fields. an expert system to optimise gas output, which BP has around 2800 plunger wells in the automatically maintains and adjusts the frequency of plunger operation across entire gas USA, and four years ago set out to find a fields (see diagram on opposite page) more effective way to control these, including alarming abnormal operation, in order to optimise the removal of liquids and increase gas production. When operated conventionally, BP’s plunger well operating cycle begins with the RTU plunger at the bottom of the well – several proprietary designs of metal plunger are available, but typically in BP’s wells these are To pipeline gathering system around 0.5m long and 50mm in diameter, Motorised control valve with sprung sides which form a seal in the wellbore. At this stage the well is shut in by a surface mounted motorised valve (see figure, left), and as gas and liquids flow into the wellbore from the formation, the liquids build up above the plunger. The pressure in the well rises to a predetermined level, >> automatically opening the valve, allowing the gas pressure from the reservoir to drive the plunger up to the surface, pushing the liquids ahead of it as it travels. During the subsequent gas flow, liquids are carried out of the well as small droplets while the flow Liquids velocity remains high enough. At the surface the plunger is caught in the wellhead, its arrival being detected by a sensor strapped to the wellhead. The sensor Plunger moving at 2-8m/sec sends a signal to a solar-powered remote 2500m (typical) terminal unit (RTU) dedicated to each well, which controls the overall cycle of operation. The RTU is connected to the gas sales flowmeter, continuously monitoring gas Gas flowing from the well. When the flow falls to a preset rate, the RTU closes the valve, the plunger falls back to the bottom of the well and the cycle begins again. Bumper spring Determining the set point for the valve opening pressure and the length of run time requires field operators to manually ‘tune’ the system over a period of days until the Gas Gas plunger is operating in the ‘safe zone’ – that is, delivering an acceptable output of gas, even if this is not the maximum rate achievable, particularly when reservoir behaviour begins Diagram not to scale to change. The RTUs transmit their signals by telemetry to a supervisory control and data acquisition (SCADA) unit, through which >> ‘The back pressure this causes can two primary methods for unloading the field operators can change set points on dramatically reduce production in a well in accumulated liquids from the wellbore. a well. But faced with hundreds of wells to just a few months. Unloading the liquids One of these is to shut off wells manually for monitor and adjust, operators find production from the well can extend its producing life a period until enough gas pressure builds up optimisation across the field to be very and perhaps keep it running for 20 years, to expel the liquids when the wells, known difficult to achieve. And when the pipeline which makes good sense having already as intermitter wells, are reopened. The other pressure in the field’s gathering system invested the capital.’ is to deploy a metal piston inside the tubing, changes, all wells will be affected and will The industry has traditionally employed called a plunger, to help push the liquid out of need retuning. 28 Frontiers April 2003
  6. 6. Not only does the amount of liquid lifted change with each cycle, the plungers themselves also present another variable in Expert well management Each well in a gas field is equipped with a remote terminal unit (RTU). The RTU monitors well performance the finely balanced equation. As they travel and is interrogated by the SCADA system. Data are analysed by the expert system to decide how operating up and down the wellbore several times a parameters for the wells should be changed day at speeds of 2-8m per second, hitting bumper springs at the top and bottom of a RTUs (remote terminal units) at typical 2500m journey, plungers wear out wellheads throughout the gas field over a period of months, and sometimes their seals can become jammed by sand in the well fluids. The condition of a plunger affects its time of travel, and time is a key RTU RTU RTU RTU RTU parameter in the liquid unloading cycle. Predicting when a plunger will begin to underperform is not easy, even for Performance New set experienced operators. data IN points data from wells OUT to wells Expert capture SCADA BP recognised that to mitigate the effects of (Supervisory control and data acquisition) these operational uncertainties, the experience of its field operators could largely be captured in a computerised expert Database Expert system system, one which would allow continuous adjustment of the set points to optimise production, taking account of trends in well performance. In addition, ‘intelligent Troubleshooting and performance reports alarming’ could indicate abnormalities in operation, such as deviations from expected production decline curves, worn plunger warnings, or tubing leak detection. Using the SCADA system’s continuous As more software modules are developed The company selected Emerson Process polling around the wells every 15-45 for the system and these are more widely Solutions as technology partner for the minutes, MaxGas checks on individual deployed, BP expects to see not only development of the system, following performance and set points and compares improved gas production results, but greater Emerson’s earlier success with an expert these with the trend over the past ten benefits arising from intelligent alarming – system for electric submersible pump control cycles. New set points are computed in for example knowing when to replace a in BP’s Milne Point field in Alaska. Working response to changing performance, which plunger, or carry out maintenance on gas together, BP and Emerson have developed a are relayed back to the SCADA system for compressors. A new programme started this proprietary expert system for the plunger transmission to each well, optimising year is focusing on wells that produce sand. wells, based on Gensym Corporation’s G2 gas production. Avoiding sand build-up in wells is another software engine, known as MaxGas Expert. Intelligent alarming is another function of potential use for the expert system by The RTUs and SCADA system hardware MaxGas, identifying abnormal conditions and ensuring flow velocities remain high enough remain unchanged, but now, instead of displaying these to the operators for to flush through any sand coming from the operators trying to corrective action – a list reservoir, a technique that could also be interpret the many of suggested best applied offshore to subsea flowlines prone inputs transmitted from Fuzzy logic is actions is made to sand accumulation. the wells, this available, and the alarm ‘We intend to extend the use of the information is relayed to used to mimic the can be traced right back expert system technology to almost all of a computer for analysis to the original readings BP’s plunger wells in North America,’ by the expert system. human decision which triggered it. concludes Sisk. ‘Operators are already And built into that system is a set of ‘if- making process The expert system was first employed at reporting they are much more efficient in the field as they do not have to spend so much then-else’ rules, created BP’s Blocker field in east time retuning set points over and over. When from the knowledge of BP’s production Texas in 2000, when 350 wells were the system is deployed to all the US onshore engineers and field operators across North equipped with plungers and placed under its gas fields, we anticipate gaining at a America, using ‘fuzzy logic’. control. Almost immediately the benefits of minimum a 2-3% production increase – ‘Fuzzy logic is a set of mathematical the development began to be realised, with the first four fields using the system and algorithms that allow the system to make an initial 15% uplift in gas production, well plungers in east Texas are expected to decisions in shades of grey, rather than the above BP’s anticipated target of a 2% deliver an extra half billion cubic metres black and white outcomes of binary logic,’ increase. Last year, 800 more wells in the of gas. If you consider that BP’s overall gas says Sisk. ‘It mimics more closely the human Anadarko Basin in west Texas were added to output onshore in the US is measured in decision making process, and helps the the tally, demonstrating a significant millions of cubic metres every day, the controlling operator home in on the optimum decrease in the natural decline in gas rates expert system has more than paid for itself operating conditions.’ experienced in the region up until then. in increased revenues.’ ■ Frontiers April 2003 29
  7. 7. Copyright and legal notice Copyright in all published material including photographs, drawings and images in this magazine remains vested in BP plc and third party contributors to this magazine as appropriate. Accordingly neither the whole nor any part of this magazine can be reproduced in any form without express prior permission, either of the entity within BP plc in which copyright resides or the third party contributor as appropriate. Articles, opinions and letters from solicited or unsolicited third party sources appearing in this magazine do not necessarily represent the views of BP plc. Further, while BP plc has taken all reasonable steps to ensure that everything published is accurate it does not accept any responsibility for any errors or resulting loss or damage whatsoever or howsoever caused and readers have the responsibility to thoroughly check these aspects for themselves. Any enquiries about reproduction of content from this magazine should be directed to the Managing Editor (email: knott@bp.com).

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