Smart wells. Figure 1: Artist impression of a smart well with multiple branches, inflow control devices and reservoir imaging functionality.

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1 Smart wells Contribution to the Jaarboek of the Mijnbouwkundige Vereeniging, February 2001, by J.D. Jansen, Delft University of Technology, Department of Applied Earth Sciences, Section Petroleum Engineering, & Shell E&P Technology Applications and Research, Rijswijk, The Netherlands: Abstract Smart well technology involves down-hole measurement and control of well bore and reservoir flow. Drilling and completion techniques have advanced significantly over the last years and allow for the drilling of complex multi-lateral and extended reach wells, and the installation of down-hole inflow control valves, measurement devices for pressure, temperature and flow rate, and processing facilities such as hydro-cyclones in the well bore. Smart wells may allow us to go from passive/reactive production scenarios to active/proactive production control. This could e.g. be achieved through influencing the flow behaviour in the reservoir by imposing a pressure profile along the well bore based on results of down-hole measurements, and if necessary, continuously updated dynamic reservoir models. Full development of this potential requires a more systematic analysis of reservoir and well bore flow in terms of modern measurement and control theory. In parallel this should be combined with a revision of conventional production scenarios, and the development of computational tools to rapidly design and assess the value of smart well solutions. Figure 1: Artist impression of a smart well with multiple branches, inflow control devices and reservoir imaging functionality. Smart Wells, February /11

2 What are smart wells? What is smart anyway? Wells equipped with permanent down hole measurement equipment or control valves, and especially those with both, are nowadays known as smart or intelligent wells; see Figure 1. In the oilfield, just as in the real world, intelligence is not always a guarantee for success, and the key question in the development of smart well technology is when the added functionality also adds value. Dumb wells are sometimes the smartest solution. Processes Figure 2 shows a representation of oil and gas production as a feedback control process, involving measurement, modelling and control. The picture of course not only applies to the use of smart wells, but also to conventional production activities. However, it forms a good starting point for the analysis of the added value of smart wells. Two major feedback cycles occur, each on it s own time scale: Daily production: On a scale of days to weeks, typical input variables are well head choke settings, water injection pressures, or lift gas rates. Measured output from the process includes production variables such as pressures, and oil, gas and water rates. Control will often be driven by short time optimisation objectives, for example production targets or utilisation rates. Down hole measurement has the scope to improve routine process control (well surveillance) and production measurement (flow allocation), and down hole control will allow for rapid reaction e.g. in case of gas or water breakthrough. Extensive modelling will usually not be required, although some well bore flow and surface network simulation may be necessary for accurate flow allocation. Reservoir management: On a time scale of months to years, the production process essentially consists of draining the reservoir. In addition to the variables that control daily production, input includes production engineering activities such as water or gas shut off, re-completion, stimulation or even side-tracking or in-fill drilling. Measured output involves production histories, well tests and reservoir images obtained from time lapse seismic or other sources. Control is usually focused on maximising the asset revenues, which often translates into maximising ultimate recovery and minimising operating expenditure (OPEX). It is in this feedback process that the major value of smart well technology can be expected, through reduced well intervention costs, a reduced number of wells, accelerated production and, in particular, increased ultimate recovery. System modelling will often involve extensive reservoir simulation, in addition to well bore and surface flow modelling. Smart Wells, February /11

3 Input CONTROL System (reservoir & wells) Output MEASURE Control algorithms Sensors System model Measured output MODEL Figure 2: Oil and gas production represented as a feedback control process, involving measurement, modelling and control. Integration Smart well technology can be seen as a next step in the development from vertical wells, via horizontal wells to multi-lateral wells. As with all these developments, the value of the technology is not so much in the capability to drill and complete the wells, impressive as these achievements may be. As was shown above, the value is in improved asset management through reduced well intervention costs, accelerated production and, in particular, increased ultimate recovery. Although the majority of the value of smart wells can expected to be realised during the production phase of the petroleum life cycle, the decisions about the use of smart well technology have to be made during the development stage, in particular during field development planning (FDP). The key objective during FDP is maximisation of the net present value (NPV) within the constraints of the project. This involves comparison of a large number of development concepts, usually in combination with a number of subsurface models to reflect geological uncertainties. Early co-operation of reservoir engineers, production engineers and well engineers, supported by the appropriate integrated software, is essential to achieve the objective. Another integration aspect concerns routing of real-time data to modelling software. This involves data acquisition, transmission and storage in a data base, data brokering, quality control, filtering and transfer to modelling tools. Expertise in automated production operations has until recently mainly been gained for surface production equipment and needs to be extended to down hole tools and data transmissions systems. Hardware Before discussing some examples of the use of smart well technology, it is useful to review the present state of smart well hardware. The recent rapid increase in smart well applications have to a large extent been driven by the rapid development of down hole measurement and control equipment. Although costs are generally still high, the reliability of the equipment has improved dramatically over the recent years, thus bringing more and more economic applications within reach. Smart Wells, February /11

4 Measurement Single point measurement of pressure and temperature. Also known as permanent down hole gauges which were already in use long before the term smart well became fashionable. Most used are sensors using resonating quartz crystals: the resonance frequency of the electrically excited crystals is a function of pressure and temperature. Recent advances include the development of electric resonating diaphragms which have the advantage of having no electronics down hole, and fibre brag grating technology which does away with electronics altogether and uses fibre optics for measurement and data transmission to surface. Distributed measurement of pressure and temperature. A recent development is distributed temperature sensing (DTS). DTS employs a thin glass fibre optical cable running along the entire length of the well. Using the effect that light sent through the cable scatters with characteristics depending on the local temperature, it is possible to obtain a very accurate (0.1 degree) temperature profile along the entire well. An effective way of installation of DTS is through pumping it down through a U-tubed ¼ inch control line that was run with the completion. The value of DTS measurements to interpret reservoir inflow has yet to be confirmed. A next step in distributed sensing is likely to be distributed pressure sensing (DPS). Flow rate and composition meters for down hole use are still very much in a development stage. Given the difficulties to obtain accurate three-phase measurement at surface, the down hole developments make take a while before they reach the stage of routine application. An exception is the use of venturi meters, which can be used for liquid rate determination in wells with inclinations up to 30 degrees. Other flow metering concepts under development include fibre brag grating technology. Compositional meters under development make use of gamma ray absorption, capacitance or conductance measurements and electromagnetic helical resonators. Information on down hole flow rate and composition can, to a limited extent, be inferred from down hole temperature and pressure measurements in combination with surface measurements. Also, the use of down hole inflow control valves allows for the determination of flow rates from individual well intervals through closing all intervals but one and using surface measurements only ( well testing by exception ). Reservoir imaging In addition to direct or indirect down hole measurement of primary production variables (pressure and flow rates), there are several developments to obtain reservoir information from other sources during the producing life of a field. Most notably is the use of 4-dimensional (4D) seismic, also known as time lapse seismic, to achieve a picture of fluid front movements in the reservoir through observation of the differences in seismic images over time. Other developments, although much more in their infancy, are reservoir drainage imaging with the aid of continuous resistivity measurements in a well bore or between well bores, or through listening to micro-seismicity (cracking) around the well bore with down hole geophones. Yet another possibility is the use of down hole control valves to perform on-line well tests, i.e. to infer information from the reservoir response to deliberately disturbed inflow into the well bore. This is subject of a recently started PhD project in the section Petroleum Engineering (See below). Smart Wells, February /11

5 Control Down hole flow and pressure control can be achieved through the use of interval control valves (ICVs). Figure 3 displays the basic concept: A well is completed with a perforated casing and equipped with a tubing extending below the production packer (also referred to as an extended stinger). The well is divided in intervals with the aid of packers between the tubing and the casing, and each interval is equipped with a remotely controllable ICV. All the major service companies can provide this functionality, and various levels of sophistication and costs - can be achieved. At the high end of the scale are electrically controlled continuously variable ICVs with pressure and temperature measurements and valve position feedback at each valve. The typical cost of such a valve is in the order of 0.5 million $. Cheaper solutions employ valves that have a limited number of discrete valve opening settings, or can just switch between open and closed (on/off valves). In addition to electrically powered system, hydraulic systems are available. Figure 3: Well with three perforated intervals completed with interval control valves (ICVs). ICVs can also be applied to wells completed with a slotted liner or a sand screen instead of a cemented casing, although this will usually lead to communication behind the casing between the intervals. Furthermore, ICVs installed in the main well bore of a multi-lateral well can be used to control inflow from branches. Obviously, the concept can also be used to control outflow from injections wells, or even cross flow between different zones in a single well bore. Down hole processing The biggest development effort in down hole processing is currently in down hole water separation with the aid of cyclones. In combination with an inverted electric submersible pump (ESP) this allows for down hole re-injection, with the potential for a dramatic reduction in water production to surface. No full-field implementations have been performed to date, but several pilot tests are ongoing around the world. Another potential future application of down hole processing is down hole gas compression. Communications and power supply Further smart well hardware developments are in the field of power and data transmission. Signals from down hole measurement devices to surface and vice versa are, at present, sent mainly electrically or optically (via glass fibre). Recently, several experimental systems for cable-less communications have emerged. Power to down hole control equipment is currently provided electrically or hydraulically. Experimental developments are in the area of batteries which can sustain down hole temperatures, and down hole power generation (e.g. micro turbines driven by the production flow). Smart Wells, February /11

6 Current applications Water or gas shut-off A first example of the use of smart well technology is depicted in Figure 4. A reservoir with water drive and strong horizontal barriers is drained with a single well with perforated intervals in each separate reservoir layer. Water breakthrough in the layers does not occur simultaneously because of permeability differences. Using a completion with an on-off ICV in each interval, well segments can be shut off when water breaks through, thus reducing the amount of water to be processed at surface and preventing early lift-die out of the well. Detection of the water could be done, in theory, by using the results from pressure and temperature sensors at the ICVs. In practice, it will probably be sufficient to assess the effect of closure of each ICV on the water production of the well at surface. A similar solution could of course be used to shut off early gas influx. In terms of measurement and control, this example relates to daily production optimisation, as well as to asset management. Figure 4: Control of water break-through in a layered reservoir. Commingled production A second example is the use of ICVs to allow commingled production from zones with different pressures, through choking the inflow from the highest pressured zone with a continuously variable ICV, to avoid cross-flow to the lowered pressured zone; see Figure 5. The alternative, conventional, scenario would be to sequentially produce the two zones, through shifting of a sleeve on wire line or coiled tubing, or through work over and reperforation of the well. The major value of the smart well solution is in this case the accelerated production, or, if production is restricted at surface, the maintaining of a constant production plateau. Additional benefits are the absence of a work over, which is particularly attractive for sub-sea wells, and the possibility to produce commingled in cases were Ronal pressures are equal, but where government regulation require accounting of production from different zones. In the latter case some means of flow measurement, either directly or inferred, is of course necessary. Smart Wells, February /11

7 Figure 5: Commingled production from two stacked reservoirs. Gas dump flooding Figure 6 shows an example where a smart well is used to connect an oil reservoir with weak gas cap drive to an underlying gas reservoir with a higher pressure. Pressure sensors and a continuously variable ICV at the injection interval allow control of the gas dump flood. In this example, a second well is used to drain the oil. Alternatively, the oil could be produced trough the same well as used for the internal gas injection, using a concentric or parallel dual completion solution. Gas re-injection for pressurization Oil production Figure 6: Pressure maintenance in an oil reservoir through controlled gas dump flooding. Smart well research in the section Petroleum Engineering Themes As shown in the examples above, current applications are often extensions of conventional completion techniques such as sequential production from different zones along the well bore. However, smart wells may allow us to go from passive/reactive production scenarios to active/proactive production control. This could e.g. be achieved through influencing the flow behaviour in the reservoir by imposing a pressure profile along the well bore based on results of down-hole measurements, and if necessary, continuously updated dynamic reservoir models. Full development of this potential requires a more systematic analysis of reservoir Smart Wells, February /11

8 and well bore flow in terms of modern measurement and control theory. In parallel this should be combined with a revision of conventional production scenarios, and the development of computational tools to rapidly design and assess the value of smart well solutions. The current research program into smart wells in the Section Petroleum Engineering therefor focuses on the following three themes: Application of measurement and control concepts to reservoir engineering: Development of conceptual smart well solutions for improved reservoir drainage. Development of computational methods for smart well modelling. We will discuss these themes in somewhat more detail below. Application of measurement and control concepts to reservoir engineering Figure 7 is a more detailed version of Figure 2, and represents the oil production process as a model-based control problem. In the modelling phase a box has been added to emphasise the role of identification, i.e. the activity of building and updating a model using measured data. Some topics that are currently being investigated or are planned to be addressed in the near future include: Development of system models of the behaviour of reservoirs, wells and surface facilities, and in particular of a model-based control framework for reservoir engineering, including the time-varying and non-linear aspects. Development of system identification techniques to estimate reservoir model parameters from down-hole measurements. This involves low-order models focused on direct identification and control, as a well as large scale reservoir models. Development of model reduction techniques and control algorithms for the systematic optimisation of production parameters. Use of down hole measurement and control equipment to perform frequent down hole well tests. Development of techniques to systematically take into account the effects of uncertainties in the entire cycle of system response, measurement, modelling and control. Input CONTROL System (reservoir & wells) State variables MEASURE Control algorithms Sensors System model Parameter identifier Measured output MODEL Figure 7: Model based control. Smart Wells, February /11

9 Conceptual smart well solutions for improved reservoir drainage Figure 8 displays the results of a first attempt to improve ultimate recovery in heterogeneous reservoirs through the use of smart wells. This particular example simulates the drainage of a reservoir that incorporates a high permeable streak, using a pair of horizontal production and water injection wells with ICVs. An intuitive optimisation algorithm was used to control the ICV settings to optimise recovery [1], [2]. This study forms the basis for a more formal optimisation approach currently under development. Injector Producer Figure 8: Improved water flooding of a reservoir with a highly permeable streak. Left: top view of the reservoir with a pair of parallel horizontal injection and production wells. Middle: Displacement pattern at the moment of water-breakthrough using conventional wells; black = water; white = oil. Right: Displacement pattern at the moment of waterbreakthrough using smart wells, revealing a much higher recovery. Another area of interest is the use of smart wells to counteract the effect of pressure drop in horizontal wells. Figure 9 (top left) illustrates the occurrence of a very uneven inflow along the axis of a horizontal well, caused by frictional pressure drop in the well bore resulting in a higher draw down at the heel than at the toe. This typically occurs for large-diameter, highrate wells producing from highly permeable reservoirs. As a result the well is prone to early water or gas breakthrough at the heel, and the effectiveness of the well near the toe is strongly reduced. Figure 9 (top right and bottom left) display two conceptual solutions to counteract this effect. The first one, the smart stinger completion (SSC), employs an extended stinger with one continuously variable ICV at the heel to flatten the draw down profile, and thus the inflow profile [3]. The second method, the inflow switching process (ISP), uses a number of on/off ICVs to regularly move the point of highest draw down along the well bore. Once water or gas has broken through, that particular interval is shut off and the water or gas cone is allowed to recede before re-opening of the interval [4]. Figure 9 (bottom right) illustrates that both methods result in an oil production behaviour almost identical to that in case of an ideal well without pressure drop. Computational methods for smart well modelling Usually, the grid block size in reservoir simulators is far to big to accurately represent the detailed near-well bore flow. This is often accounted for through the use of a semi-analytical correction method, often referred to as the Peaceman model. For advanced, multilateral, wells sometimes a more accurate description is required, and recently research in the section Petroleum Engineering addressed some aspects of improved inflow modelling [5], [6]. Other work in the area of computational modelling involved the well bore flow in extended stinger completions such as the SSC discussed above [7]. Smart Wells, February /11

10 Inflow / unit length Inflow / unit length well axis Variable choke well axis 2.00E+04 Inflow / unit length t = 1 t = 2 well axis Oil rate [sbbl/day] 1.50E E E+03 Basecase ISP Frictionless SSC Kv/Kh = 0.1 and Kh = 2000mD 0.00E Time [years] Figure 9: Smart well solutions to combat frictional pressure drop in horizontal well bores. Top left: a conventional horizontal well, displaying decreasing inflow from heel to toe because of pressure drop along the well bore. Top right: the smart stinger completion (SSC). Bottom left: the inflow switching process (ISP). Bottom right: Cumulative oil production as a function of time. The solitary line represent production for a conventional completion. The three lines close together represent production using the SSC, the ISP and production from a conventional well without pressure drop (i.e. the ideal situation). Conclusion Although the expression smart wells may be likely to disappear as suddenly as it came into fashion, the concept of using measurement and control to optimise oil and gas production is here to stay. Hardware is developing fast and in many directions, and in particular optical techniques and cable-less communication are likely to lead to a dramatic increase in down hole measuring capabilities over the coming years. Lagging behind the hardware developments are the capabilities to use the equipment for creation of value. This is to a large extent a matter of asset management, and the major steps to take are the development of improved concepts for smart reservoir management, the handling of large amounts of data, and increased integration between disciplines. Research in the section Petroleum Engineering should focus on concepts, and not on hardware; not on what is possible with smart well technology today, but on what will be possible whenever the hardware becomes available. Smart Wells, February /11

11 Acknowledgements Research into smart wells in the section Petroleum Engineering of the Department of Applied Earth Sciences of the Delft University of Technology (DUT) is supported by Shell International Exploration and Production (SIEP). Shell sponsors two PhD positions, and furthermore, the author of this paper is jointly employed (50%-50%) by DUT and SIEP. The author acknowledges permission from Shell to publish the material and to use Figures 1 and 4 to 6, which were taken from internal Shell publications. Glossary DTS DUT ESP E&P FDP ICV ISP NPV OPEX SIEP SSC 4D Distributed Temperature Sensing Delft University of Technology Electric Submersible Pump Exploration and Production Field Development Plan(ning) Inflow Control Valve or Interval Control Valve Inflow Switching Process Net Present Value OPerating Expenditure Shell International Exploration and Production Smart Stinger Completion 4-dimensional (3 in space, 1 in time) References [1] Brouwer, D.R., Jansen, J.D, Van der Starre, S., Berentsen, C.W.J. and Van Kruijsdijk, C.P.J.W.: Recovery Increase Through Waterflooding Using Smart Well Technology, Proc. SPE European Formation Damage Conference, The Hague, May 2001, paper SPE [2] Van der Starre, S.: Recovery Increase Through Waterflooding Using Smart Well Technology, MSc Thesis, Report CTG/PW/00-017, Centre for Technical Geoscience, Delft University of Technology, October [3] Wagenvoort, A.W.: Application of Smart Well Technology to Combat the Effects of Frictional Pressure Drop in Horizontal Wells - The Smart Stinger Completion, MSc Thesis, Report CTG/PW/00-019, Centre for Technical Geoscience, Delft University of Technology, December [4] Droppert, V.S.: Application of Smart Well Technology to Combat the Effects of Frictional Pressure Drop in Horizontal Wells - The Interval Switching Process, MSc Thesis, Report CTG/PW/00-020, Centre for Technical Geoscience, Delft University of Technology, December [5] De Koning, M.B.F.: Application of an Advanced Well Model in a Reservoir Simulator, MSc Thesis, Report CTG/PW/99-015, Centre for Technical Geoscience, Delft University of Technology, September [6] Jansen, J.D.: Expressions for the flow through grid block boundaries near wells in reservoir models with irregular grids, Report CTG/PW/00-002, Centre for Technical Geoscience, Delft University of Technology, September [7] Jansen, J.D.: Numerical modeling of the flow in extended stinger completions, Report CTG/PW/00-003, Centre for Technical Geoscience, Delft University of Technology, December Smart Wells, February /11