Smart wells.

Intelligent wells

WHAT ARE SMART WELLS?

• Wells equipped with permanent down hole measurement equipment or control valves, and especially with both, are known as smart or intelligent wells; see Fig.1.

• The development of smart well technology is effective when the added functionality also adds value..

SMART WELLS.

• Smart well technology involves down hole measurement and control of well bore and reservoir flow., and the installation of down-hole inflow control valves, measurement devices for pressure, temprature and flow rates, & processing facilities such as hydro cyclones in the well bore.

• Smart wells allow us to go from passive /reactive production scenario to active / proactive production control .

• Fig.

SMART WELLS.• This could be achieved through influencing the flow

behavior 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.

• Parallelly this should be combined with a revision of computational tools whicn can rapidly design and assess the value of smart well solutions.

Processes….• Daily production: On a scale of days to weeks, typical input

variables are well head choke settings , water injection pressures, and oil, gas and water rates. Control will often be driven by short time optimization objectives, for example production targets or utilization 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 modeling will usually not be required, although some well bore flow and surface network simulation may be necessary for accurate flow allocation.

Processes….• Reservoir management: On a long time scale (months to years ) the

production process 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 out put involves production histories, well tests and reservoir images obtained from time lapse seismic or other sources. Control is usually focused on maximizing the asset revenues, which often translates into maximizing ultimate recovery and minimizing operating expenditure (OPEX) .

• It is in this feedback process that the major value part of smart well technology can be expected, through reduced well intervention costs, a reduced number of wells, accelerated production and , in particular, enhanced ultimate recovery. System modeling will often involve extensive reservoir simulation, in addition to well bore and surface flow modeling

Integration..• Smart well technology is seen to progress in the development

from vertical wells, to 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.

• 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 realized 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)

Integration..• The key objective during FDP is maximization of the net

present value (NPV) within the constraints of the project.. This invloves 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, supported by the appropriate integrated software, is essential to achieve the objective.

• Another integration aspect concerns routing of real-time data to modeling software. This involves data acquisition , transmission and storage in a data base , quality control., filtering and transfer to modeling 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 transmission system.

HARDWARE.

• Some examples of the use of smart well technology , it is appropriate to review the present state of smart well hardware. The recent rapid increase in smart well applications to a large extent been driven by the rapid development of down hole measurement and control equipment.

• Though costs are high, the reliability of the equipment has improved dramatically over the recent years, thus bringing more and more economic applications within reach.

MEASUREMENT…• Single point measurement of pressure and temperature: Also known as

“permanent down hole gauges” which were already in use long before . • Recent advances include the development of electric resonating

diaphragms which have the advantage of having no electronics down hole, and fiber grating technology which 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 fiber optical cable running along the entire length of the well. 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. A next step in distributed sensing is likely to be distributed pressure sensing(DPS)

MEASUREMENT…

• Flow rate and composition meters for down hole use is still very much in a development stage. Given the difficulties to obtain accurate three-phase measurement at surface, the down hole developments may take a while before they reach the stage of routine application.

• Other flow metering concepts under development include fiber grating technology.

• Compositional meters under development ,make use of gamma ray absorption, capacitance or conductance measurements and electromagnetic helical resonators.

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 the hole geophones.

CONTROL…• Down hole flow and pressure control can be achieved through the use of

interval control valves (ICVs). Fig 2 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 level.

• The typical cost of such a valve is in the order of 0.5 million $.Cheaper solution 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. Fig -2:

• Well with three perforated intervals completed with interval control valves (ICVs)

CURRENT APPLICATIONS.• Water or gas shut-off.• A first example of the use of smart well technology depicted in Fig. 3. 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 breakthrough, 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 result 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 be used to shut off early gas influx. In terms of measurement and control, this example relates to daily production optimization, as well as to asset management. Fig. 3. Control of water break-through in a layer reservoir.

COMMINGLED PRODUCTION• commingled production • 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 fig. 4. 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 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 pressures are equal, but where government regulation require accounting of production from different zones. See Fig.4. commingled production from two stacked reservoirs.

GAS DUMP FLOODING.• Fig 5. 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 through the same well as used for the internal gas injection, using a concentric or parallel dual completion solution .

• See Fig. 5. Pressure maintenance in an oil reservoir through controlled gas dump flooding.

CONCLUSION.• In smart wells, the concept of using measurement and

control to optimize oil and gas production is the primary objective

• Hardware development is progressing in multifarious directions, and in particular optical techniques and wireless communication are likely to increase in down hole measuring capabilities in future.

• The capabilities to use the equipment for creation of value is Lagging behind the hardware developments. The major steps to take place are:

• the development of improved concepts for “smart” reservoir management.

• The handling of large amounts of data.

CONCLUSION.

• Increased integration between disciplines. • Further Research must focus on concepts, and

not on hardware.• Instead of focusing on what is possible with

smart well technology today, to focus on what will be possible as and when the hardware becomes available.

NODAL ANALYSIS

Nodal Analysis……

• Systems analysis to analyze the performance of systems composed of multiple interacting components.

• This approach introduced to oil and gas wells & the concept, is referred to as Nodal Analysis™ within the oil and gas industry.

• The objective of systems analysis is to combine the various components of the production system for an individual well to estimate production rates and optimize the components of the production system.

Nodal Analysis……• Necessity of examining flow through system• The flow of reservoir fluids from the subsurface reservoir to the

stock tank requires an understanding of the principles of fluid flow through porous media and well tubular.

• As the fluid moves through the production system, there will be pressure drop in the fluid flow. This pressure drop will be the sum of the pressure drops through the various components in the production system.

• Because of the compressible / incompressible nature of the fluids produced in oil and gas operations, the pressure drop is dependent on the interaction between the various components in the system.

• This occurs because the pressure drop in a particular component is not only dependent on the flow rate through the component, but also on the average pressure that exists in the component.

Nodal Analysis……• As a result, the final design of a production system

requires an integrated approach, since the system cannot be separated into a reservoir component or a piping component and handled independently.

• The amount of oil and gas produced from the reservoir to the surface depends on the total pressure drop in the production system, and the pressure drop in the system depends on the amount of fluid flowing through the system.

• Consequently, the entire production system must be analyzed as a unit or system.

Nodal Analysis……

• Depending on the terminal end of the production system, there is a total pressure drop from the reservoir pressure to the surface, as depicted in Fig. 1.

• If the separator represents the end of the production system, the total pressure drop in the system is the difference between the average reservoir pressure and the separator pressure:

Fig. 1—Production System and associated pressure losses. [2]

Nodal Analysis…… ………………………………..1)

• This total pressure drop is then composed of individual pressure drops as the reservoir fluid flows to the surface. These pressure drops occur as the fluid flows through the reservoir and well completion, up the tubing, through the wellhead equipment and choke, and through the surface flowlines to the separator. Thus, the total pressure drop of Eq. 1 can be represented by Eq. 2.

• . …………………………(2)• These individual pressure drops can be divided into yet additional pressure drops

to account for restrictions, subsurface safety valves, tubing accessories, etc.• Systems analysis is based on the concept of continuity. At any given point in the

production system, there is a particular pressure and production rate associated with that point for a set of conditions. If there is any change in the system, then there will be an associated change in pressure and/or production rate at that same point.

• This concept allows the production system to be divided at a point of interest for evaluation of the two portions of the system. This evaluation determines the conditions of continuity of pressure and production rate at the division point, which is the estimated producing condition for the system being evaluated.

Nodal Analysis……• These individual pressure drops can be divided into yet additional pressure drops

to account for restrictions, subsurface safety valves, tubing accessories, etc.• Systems analysis is based on the concept of continuity. At any given point in the

production system, there is a particular pressure and production rate associated with that point for a set of conditions. If there is any change in the system, then there will be an associated change in pressure and/or production rate at that same point. This concept allows the production system to be divided at a point of interest for evaluation of the two portions of the system. This evaluation determines the conditions of continuity of pressure and production rate at the division point, which is the estimated producing condition for the system being evaluated.

• The approach provides the flexibility to divide the production system at any point of interest within the system to evaluate a particular component of the system. The most common division points are at the wellhead or at the perforations, either at the reservoir sand face or inside the wellbore. The terminal ends of the system will be the reservoir on the upstream end of the system and the separator at the downstream end of the system or the wellhead if a wellhead choke controls the well.

Nodal Analysis……• The components upstream of the division point or node comprise the inflow

section of the system, while the components downstream of the node represent the outflow section.

• Once the system is divided into inflow and outflow sections, relationships are written to describe the rate-pressure relationship within each section. The flow rate through the system is determined once the conditions of continuity are satisfied:

• Flow into the division point equals flow out of the division point. The pressure at the division point is the same in both inflow and outflow

sections of the system. After the division point is selected, pressure relationships are developed for

the inflow and outflow sections of the system to estimate the node pressure. The pressure in the inflow section of the system is determined from Eq. 3, while the outflow section pressure drop is determined from Eq. 4.

• ……………….(3)

• ……………….(4)

Nodal Analysis……• The pressure drop in any component, and thus in either the inflow or outflow

section of the system, varies as a function of flow rate. As a result, a series of flow rates is used to calculate node pressures for each section of the system. Then, plots of node pressure vs. production rate for the inflow section and the outflow section are made. The curve representing the inflow section is called the inflow curve, while the curve representing the outflow section is the outflow curve. The intersection of the two curves provides the point of continuity required by the systems analysis approach and indicates the anticipated production rate and pressure for the system being analyzed.

• Fig. 2 depicts a systems graph for a sensitivity study of three different combinations for outflow components labeled A, B, and C. For outflow curve A, there is no intersection with the inflow performance curve. Because there is no intersection, there is no continuity in the system and the well will not be expected to flow with System A. The inflow and outflow performance curves do intersect for System B. Thus this system satisfies continuity, and the well will be expected to produce at a rate and pressure indicated by the intersection of the inflow and outflow curves. System C also has an intersection and would be expected to produce at a higher rate and lower pressure than System B, as indicated by the graph.

Nodal Analysis……

Fig. 2—Inflow and outflow performance curves for systems analysis

Nodal Analysis……• The outflow curve for System C has a rapidly decreasing pressure at low flow rates,

reaches a minimum, and then begins to slowly increase with increasing rate. This is typical for many outflow curves, which, in some cases, will yield two intersection points with the inflow curve; however, the intersection at the lower rate is not a stable solution and is meaningless. The proper intersection of the inflow and outflow curves should be the intersection to the right of and several pressure units higher than the minimum pressure on the outflow curve.

• The effect of changing any component of the system can be evaluated by recalculating the node pressure for the new characteristics of the system. If a change is made in an upstream component of the system, then the inflow curve will change and the outflow curve will remain unchanged. On the other hand, if a change in a downstream component is made, then the inflow curve will remain the same and the outflow curve will change. Both the inflow and outflow curves will be shifted if either of the fixed pressures in the system is changed, which can occur when evaluating the effects of reservoir depletion or considering different separator conditions or wellhead pressures.

Nodal Analysis……• Systems analysis may be used for many purposes in analyzing and designing

producing oil and gas wells. The approach is suited for evaluating both flowing wells and artificial lift applications. The technique provides powerful insight in the design of an initial completion. Even with limited data, various completion scenarios can be evaluated to yield a qualitative estimate of expected well behavior. This process is very useful in analyzing current producing wells by identifying flow restrictions or opportunities to enhance performance.

Typical applications include:• Estimation of flow rates• Selection of tubing size• Selection of flow line size• Selection of wellhead pressures and surface choke sizing• Estimation of the effects of reservoir pressure depletion

Nodal Analysis……• Identification of flow restrictions• Other typical applications are:• Sizing subsurface safety valves• Evaluating perforation density• Gravel pack design• Artificial lift design• Optimizing injection gas-liquid ratio for gas lift• Evaluating the effects of lower wellhead pressures or installation of

compression• Evaluating well stimulation treatments• In addition, systems analysis can be used to evaluate multiwell producing

systems. Systems analysis is a very robust and flexible method that can be used to design a well completion or improve the performance of a producing well.

Nodal Analysis Examples• Systems analysis examples• Examples 1 and 2 demonstrate the systems analysis approach.Example 1 considers the

effects of tubing size on gas well performance.Example 2 demonstrates the effects of reservoir depletion on the performance of an oil well.

Example 1 Analyze a gas well to select an appropriate tubing size. The gas well under consideration is

at 9,000 ft with a reservoir pressure of 4,000 psia. Solution The first step in applying systems analysis is to select a node to divide the system.

Initially, the node is selected to be at the perforations to isolate the inflow performance (reservoir behavior) from the flow behavior in the tubing. For this particular case, the well is flowing at critical flow conditions, and, consequently, the wellhead choke serves as a discontinuity in the system, which allows the use of the wellhead pressure as the terminal point for the outflow curve. Once the node point is selected, the pressure relations for the inflow and outflow sections of the system are determined. For this example, Eqs. 5 and 6 represent the inflow and outflow pressure relationships, respectively.

Nodal Analysis Examples• ……………………..(5)• ……………………….(6)• With these basic relationships, the flowing bottomhole pressure is

calculated for different production rates for both the inflow and outflow sections. Table 1 presents the inflow performance data while Table 2presents the calculated pressures for three different tubing sizes using a constant wellhead pressure of 1,000 psia. These data are used to construct the inflow and outflow curves in Fig. 3 to estimate the production rates and pressures for each tubing size.

• The intersection of the outflow curves with the inflow curve dictates the estimated point of continuity and the anticipated producing conditions for the analyzed system. For this example, the production rate increases with increasing tubing size, yielding 4,400 Mscf/D for 1.90-in. tubing, 4,850 Mscf/D for 2 3/8-in. tubing, and 5,000 Mscf/D for 2 7/8-in. tubing.

Nodal Analysis Examples

Nodal Analysis Examples

Nodal Analysis Examples1.

Fig. 3—Systems analysis graph with a bottomhole pressure node for Example

Nodal Analysis Examples• The same well could be analyzed with the wellhead as the system node. This allows the effect of

changes in wellhead pressure on well performance to be determined. The new inflow and outflow pressure relationships are

• . …………………………….(7) • for the inflow curve, and• . …………….(8)

• for the outflow curve. Table 2 shows the pressure-rate relationship for both the inflow and outflow curves. Because the wellhead is the node in this analysis, the outflow curve will be constant and equal to the anticipated flowing wellhead pressure.

• The data are plotted in Fig. 4 and yield the same producing rates and flowing bottomhole pressures that were determined when the flowing bottomhole pressure was used as the node. This is as expected because the choice of a division point or node does not affect the results for a given system. If the wellhead pressure is decreased to 250 psia, the producing rate will change also. This effect is readily determined by constructing a constant wellhead pressure line of 250 psia on the graph and selecting the points of intersection for each tubing size. As observed from the graph, the anticipated production rates increase to 4,950 Mscf/D, 5,200 Mscf/D, and 5,300 Mscf/D for the three tubing sizes by lowering the wellhead pressure.

Nodal Analysis Examples1.

Fig. 4—Systems analysis graph with a wellhead pressure node for Example

Nodal Analysis Examples• Example 2• Investigate the effects of reservoir depletion of an oil well to estimate producing conditions and consider the

need for artificial lift. The well under consideration is producing with a constant wellhead pressure of 250 psia and is controlled by the choke.

• Solution Isolate the reservoir performance to visualize the effect of changing reservoir pressure. The flowing bottomhole pressure at mid-perforations is selected as the node and, as the well is producing under critical flow conditions, the wellhead will serve as the terminal end of the system.

• The inflow and outflow rate-pressure data is generated with Eqs. 5 and 6.Table 3 provides the inflow performance data for average reservoir pressures of 2,500 psia and 2,000 psia. Table 4 shows the tubing-intake data or outflow performance data for a flowing wellhead pressure of 250 psia with 2 7/8-in. tubing. Fig. 5 plots this information, which is used to determine the producing conditions at the two reservoir pressures. At an average reservoir pressure of 2,500 psia, the curves intersect at an oil production rate of 380 STB/D and a flowing bottomhole pressure of 1,650 psia.

• However, there is no intersection or point of continuity between the inflow and outflow performance curves when the reservoir pressure declines to 2,000 psia. This indicates that the well will not flow under these reservoir conditions. On the basis of this analysis, the effects of lowering the wellhead pressure, reducing the tubing size, or installing artificial lift early in the life of the well to enhance its deliverability should be investigated.

Nodal Analysis Examples

Nodal Analysis Examples

Nodal Analysis Examples

Fig. 5—Systems analysis graph with a bottomhole pressure node for Example 2

Nomenclature

== Average reservoir pressure, psia Ps= Separator pressure, psia Pwf=bottom hole pressure, psia Pwh=wellhead pressure, psia Δp1=pressure loss in reservoir, psia Δp2=pressure loss across completion, psia Δp3=Pressure loss in tubing, psia

Nomenclature

Δp4 =pressure loss in flow line , psia Δpd =change in downstream pressure, psia Δpp =difference in pseudo pressures, psia2/cp ΔpT = total pressure loss, psia Δpu =change in upstream pressure, psia Δp2 = difference in pressures squared, psia2