DET TEKNISK-NATURVITENSKAPELIGE FAKULTET
BACHELOROPPGAVE Studieprogram/spesialisering:
Vårsemester, 2008
Petroleumsteknologi Student: Tommy Jokela ……………………………………... signatur Faglig ansvarlig: Erik Skaugen Veileder: Francisco Porturas, Reservoir Engineer Reslink Tittel på oppgaven: Betydningen av innstrømningskontroll anordning (ICD) teknologi i horisontale sandkontrollkompletteringer
Englesk tittel: Significance of inflow control device (ICD) technology in horizontal sand screen completions Studiepoeng: Emneord:
Sidetall: 56 Vedlegg/annet: 0 Stavanger, 30.05.2008
Significance of Inflow Control Device (ICD) technology in horizontal sand screen completions
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Table of Contents
1
Summary ........................................................................................................................................................................ 7
2
Introduction ................................................................................................................................................................... 7
3
Horizontal well completion options and challenges .............................................................................................. 9 3.1
Introduction ................................................................................................................................................... 9
3.2
Completion options ...................................................................................................................................... 9
3.3
Well Clean up .............................................................................................................................................. 11
3.4
Cresting and Coning ................................................................................................................................... 12
3.5
Heel-Toe effect in a homogeneous reservoir ........................................................................................ 13
4
General information of the involved technologies ................................................................................................ 14 4.1
Introduction ................................................................................................................................................. 14
4.2
Sand Control ................................................................................................................................................ 14
4.3
Sand Screen ................................................................................................................................................ 14
4.4
Inflow Control Device (ICD) ...................................................................................................................... 17
4.5
Other available ICD designs ..................................................................................................................... 18
4.5.1
Nozzle type ICD without Screen .............................................................................................................. 18
4.5.2
Channel-type ICD....................................................................................................................................... 19
4.5.3
Tube-type ICD ............................................................................................................................................ 20
4.5.4
Orifice-type ICD ......................................................................................................................................... 20
4.5.5
Autonomous Inflow Control Device ........................................................................................................ 21
4.6
Integration with Annular Isolation ........................................................................................................... 21
4.7
Integration with Artificial Lift .................................................................................................................... 21
4.8
Integration with Gravel Pack .................................................................................................................... 22
5
Principles of the ICD technology ............................................................................................................................. 22 5.1
Introduction ................................................................................................................................................. 22
5.2
Pressure loss............................................................................................................................................... 24
5.3
Pressure loss in the formation ................................................................................................................. 26
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5.4
Bernoulli’s equation ................................................................................................................................... 26
5.5
Pressure loss through the ICD ................................................................................................................. 27
5.6
Production index, PI ................................................................................................................................... 29
5.7
Candidate Recognition .............................................................................................................................. 30
6
Simulation and analysis tool ..................................................................................................................................... 31 NeToolTM Simulation Program ................................................................................................................... 31
6.1 7
Field example from the North Sea ........................................................................................................................... 33 7.1
Introduction ................................................................................................................................................. 33
7.2
Qality control of data ................................................................................................................................. 33
7.3
Reservoir parameters ................................................................................................................................ 34
7.4
Results from the producer well evaluation ............................................................................................ 40
7.4.1
Non-Collapsed Annulus ............................................................................................................................ 41
7.4.2
Collapsed Annulus Scenario .................................................................................................................... 47
7.4.3
Water Breakthrough (Collapsed Annulus) ............................................................................................. 47
7.5
Converting the producer well into an ICD in injection mode .............................................................. 51
8
Conclusions ................................................................................................................................................................. 53
9
Recommendations ..................................................................................................................................................... 53
10
Acknowledgements ................................................................................................................................................... 54
11
Nomenclature ............................................................................................................................................................. 54
12
References .................................................................................................................................................................. 55 12.1
Written references ..................................................................................................................................... 55
12.2
Oral references ........................................................................................................................................... 56
12.3
Software....................................................................................................................................................... 56
Figures
Figure 1 Different completion options .............................................................................................................................. 11 Figure 2 Cresting of oil and gas contact in a horizontal wellbore [5] .......................................................................... 12 Page 4 of 57
Figure 3 The ICD technology reduces permeability variations in heterogeneous reservoirs................................. 13 Figure 4 The ICD technology eliminates the heel-toe effect in a homogeneous reservoir ..................................... 13 Figure 5 Flow of reservoir fluid through the sand screen ............................................................................................. 15 Figure 6 Location of sand screens in a horizontal well ................................................................................................. 16 Figure 7 Wire Wrapped ResFlow™ Screen with ICD..................................................................................................... 17 Figure 8 Wire Wrapped ResInjectTM Screen with ICD [6] .............................................................................................. 17 Figure 9 ICD with nozzles from supplier 1 [13]................................................................................................................. 18 Figure 10 Channel-type ICD [10] ........................................................................................................................................ 19 Figure 11 Labyrinth-type ICD [20] ...................................................................................................................................... 19 Figure 12 Tube-type ICD [19] .............................................................................................................................................. 20 Figure 13 Orifice-type ICD [10] ........................................................................................................................................... 20 Figure 14 Open Hole Packers prevent annular flow and isolate zones with different ............................................. 21 Figure 15 Principle of the ICD-technology depicted as a garden hose with large holes [6] ................................... 23 Figure 16 Principle of the ICD-technology depicted as a garden hose with tiny holes [6] ...................................... 23 TM
Figure 17 Standard completion versus ResInject [8] ................................................................................................... 24 Figure 18 Pressure loss illustrated as a network of resistors [6] ................................................................................. 24 Figure 19 ICD interaction in a heterogeneous reservoir [14] ........................................................................................ 28 TM
Figure 20 Modelling of the well with NETool [15] ......................................................................................................... 31 Figure 21 Display of the simulation grid together with the proposed well trajectory. ............................................. 34 Figure 22 Attribute display showing the horizontal permeability ................................................................................. 35 Figure 23 KV/KH along the well trajectory .......................................................................................................................... 35 Figure 24 Oil saturation along well trajectory.. ............................................................................................................... 36 Figure 25 Attribute display of the water saturation ........................................................................................................ 37 Figure 26 Attribute showing porosity along well trajectory.. ........................................................................................ 37 Figure 27 Permeability variations along well trajectory.. .............................................................................................. 38 Figure 28 Pressure variations along well trajectory.. .................................................................................................... 39 Figure 29 Saturations profile along the well trajectory ................................................................................................. 40 Figure 30 Summary display of conventional completion: .............................................................................................. 41 Figure 31 Summary display of the ICD completion.. ....................................................................................................... 42 Page 5 of 57
Figure 32 Pressure comparison between a conventional completion and one with ICD’s. .................................... 43 Figure 33 Oil flow rate: conventional completion and one with ICD’s......................................................................... 44 Figure 34 Oil flux: Conventional completion (blue) and one with ICD’s (pink) ........................................................... 45 Figure 35 Oil flow rate: Conventional and one with ICD’s with 3 OH packers. .......................................................... 46 Figure 36 Oil flow rate after water breakthrough ........................................................................................................... 47 Figure 37 Water flow rate after water breakthrough ..................................................................................................... 48 Figure 38 Oil Flux Reservoir•Well: after the water breakthrough. ............................................................................... 49 Figure 39 Pressure Comparison between a conventional completion and one with ICD’s .................................... 50 Figure 40 Summary plot: ICD injection mode................................................................................................................... 51 Figure 41 Water flux: Conventional completion and one with ICD’s.. ......................................................................... 52
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1
SUMMARY
The increasingly popular horizontal wells suffer from unbalanced influx and injection profile. This can be greatly improved by introducing Inflow Control Devices (ICD), which choke the inflow or outflow through the ICD, thus balancing the production or injection profile along the well-bore. Simulations with NEToolTM were performed to compare the performance of conventional Stand Alone Screen (SAS) versus screens with ICD’s. The ICD completion minimizes the annular flow effectively and balances the drainage profile. Further improvement in terms of reduced water cut and increased production was achieved by adding open hole (OH) packers. The water breakthrough simulation with ICD’s decreased water cut significantly compared to the conventional completion (SAS). Oil production for the ICD completion with OH packers was also significantly higher than for the conventional completion. The injection simulation showed a more balanced injection profile along the well-bore using ICD’s. The conventional completion had a high water flux into the high permeability/fractured zones, also called thief zones.
2
INTRODUCTION
Horizontal and multilateral completions have become increasingly popular as the operating companies are striving to maximise the oil production and minimise the number of wells. StatoilHydro’s TROLL field in the Norwegian sector with its thin oil layer is a prime example of the application of this technology. Optimising or balancing the inflow performance in long horizontal open hole completions can be challenging. The main short-comings with this type of completion are: •
Poor well clean-up during production kick-off
•
Heel’s region over-production, gas/water premature breakthrough
•
Toe’s region under or lost production, oil bypassed/unswept regions
•
Severe heel-toe effect during production in homogenous formations
•
Internal cross-flow and under-production in heterogeneous formations
Ineffective removal of the mud cake during the clean-up will restrict the flow of oil into the well-bore. Horizontal oil producers are susceptible to gas coning or water cresting during the well life due to the heeltoe effect. Small differences in permeability and/or relative permeability and frictional losses along the well bore often leads to early gas or water breakthrough. Page 7 of 57
Conventional water injectors suffer from the inability to achieve even distribution of water into all zones. Water – like any fluid – takes the path of least resistance leading to excessive flooding of high permeable zones while the tighter zones (zones with lesser permeability) or the reservoir sections toward the toe of the well are receiving little or no water at all. The risk of ineffective sweep of oil and early water breakthrough in the adjacent producing wells is very real. Should this happen in conventional wells, time consuming and expensive interventions would be required to rectify the negative development. The time it takes to plan and execute the required interventions is often several months. In the mean time the well is not producing or providing pressure support and sweeping the oil as designed. Unless the problem is fixed in timely manner the non-optimized production or injection will not only have an adverse effect on the production, but also on the recoverable reserves. The inflow control device (ICD) was introduced as a solution to these difficulties in the early ‘90s. In recent years ICDs have gained popularity and are being applied to a wide range of field types. Their efficiency to equalize the flux along the well path as well as the outflow has been confirmed by a variety of field monitoring techniques. The benefits of the ICD technology are: •
Better Initial Well Clean-up
•
Delay of Water/Gas Breakthrough
•
Decrease Water cut
•
Zonal draining strategies for efficient reservoir management
•
Better NPV / accelerated cumulative oil production
This thesis describes the inflow control device (ICD) technology, challenges, areas of applications, principles of the technology and the tools and methods to perform the analysis. The advantages will be illustrated by running analysis on real field data.
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3
HORIZONTAL WELL COMPLETION OPTIONS AND CHALLENGES
3.1
Introduction
This section describes the completion options and the production and injection related challenges in the horizontal wells 3.2
Completion options
In the recent years, significant advances have been made in drilling horizontal wells. Geo-steering and advanced measurement logging tools, form part of the today’s drill string, allowing real time steering and very accurate placement of long horizontal wells. This offers significant benefits as the pay zone section of the well-bore is to be placed within optimum distance from the oil gas contact (OGC) and the oil water contact (OWC), to delay gas- and water breakthrough. Horizontal and multilateral completions are today being applied to a wide range of field types. They have proven superior to conventional solutions in many reservoir situations. The optimal completion technique for a candidate well is determined by the reservoir properties, geological setting, rock mechanics, development plan, and completion design [12]. An important part of the planning of a horizontal well is the selection of the appropriate completion technique and design. The most common horizontal completion types are depicted in figure 1. •
Open Hole Completion are inexpensive, but it is limited to consolidated rock formations. Open hole offers no production or injection control. Additionally this type of well is difficult to stimulate.
•
Slotted or Pre-Perforated Liner offers a guard against hole collapse in unconsolidated formations. The completion method is inexpensive and it also provides a path for intervention tools. The premilled liner provides limited sand control by sizing of the slot width. As there is no zonal isolation (open annular space) effective stimulation in this type of liner is difficult. Similarly selective production and injection is not achievable. Coning, annular flow and hot spots are also known problems.
•
Slotted Liner with open hole packers provide zonal isolation. This, in addition to the above benefits, allows more effective stimulation and better possibility for selective production and injection control
•
Cemented and Perforated Liner provides good zonal isolation. Perforations designed to open channels through the damaged section of the reservoir contribute to the productivity or injectivity. This completion type offers better possibilities for selective production, injection and stimulation.
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•
Stand Alone Screen Completions provide good sand control, but due to lack of zonal isolation selective production, injection and stimulation are not possible. Coning, annular flow and hot spots are also known problems.
•
Stand Alone Screen Completion with open hole packers provides good sand control and zonal isolation. This, in addition to the above benefits, allows more effective stimulation and better possibility for selective production and injection control.
•
Stand Alone Screen Completions with open hole packers and gravel pack provides enhanced sand control and zonal isolation. Selective production, injection and stimulation are also possible to some degree.
Please note that selective production, injection and stimulation, where referred to in above completion options, require interventions, such as logging, cement and acid squeezes, straddling and/or plugging of zones. This is both time consuming and an expensive activity.
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Figure 1 Different completion options 3.3
Well Clean up
One of the main challenges in long open hole completions is the formation damage caused by ineffective well clean-up. Drilling a well causes formation damage and thus reduced effective permeability. Removal of drill fluid, solids and mud cake from a long well-bore is not a trivial process. One of the main factors effecting the hole clean-up is the completion design. Today it is common practice to run the screen liner in the reservoir drilling fluid (RDF). The mud is conditioned prior to screen liner deployment to remove mud solids which would plug the screens during deployment and flow back of the RDF. During well clean-up, the RDF mud cake is Page 11 of 57
designed to lift off cleanly and be back produced to surface leaving a clean undamaged formation through which to produce. 3.4
Cresting and Coning
Wells are often completed in zones which are underlain by a water zone and overlain by a gas cap. When a well is put into production, a pressure sink is created around the well. The pressure sink can extend all the way down to the water zone, and cause water or gas to enter the wellbore. This is called cresting (water) and coning (gas), due to the shape of the interface (see fig. 2). If the water/gas, both being more mobile than oil, penetrate the open hole interval, the gas and oil will block the production of oil from the rest of the open hole section. Increased production of water or gas results in higher costs and a declining oil production [3, 4].
Figure 2 Cresting of oil and gas contact in a horizontal wellbore [5]
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A variable permeability distribution along the well-bore (heterogeneous formation) also contributes to an unbalanced fluid influx (See fig. 3). The ICD technology reduces the permeability variations by equalizing the pressure drop along the interval. This will improve the sweep efficiency and prolong the wells production time due to delayed water/gas coning.
Figure 3 The ICD technology reduces permeability variations in heterogeneous reservoirs
3.5
Heel-Toe effect in a homogeneous reservoir
Horizontal wells increases reservoir exposure and well-bore length; however, it comes at a cost. The heel-toe effect occurs as a result of frictional pressure drop from fluid flow in horizontal sections. The frictional pressure drop along the producing conduit creates a higher drawdown pressure in the heel section of the well, causing an unbalanced fluid influx (see left hand side fig. 4). The ICD technology equalizes the pressure drop along the interval and hence balances the influx along the entire well-bore [10].
Figure 4 The ICD technology eliminates the heel-toe effect in a homogeneous reservoir
4
GENERAL INFORMATION OF THE INVOLVED TECHNOLOGIES
4.1
Introduction
This section describes the tools and techniques used in horizontal sand screen completions. 4.2
Sand Control
The goal of sand control is the production of reservoir fluids while preventing the production of formation sand (load bearing particulates which make up the reservoir rock). Unconsolidated sands typically have high permeability and porosity but low compressive strength. The sand particles in unconsolidated sands are easily dislodged when the well is put on production (due to the drag forces exerted on the solids as fluids flow past through the reservoir matrix). Also as the reservoir pressure decreases changes in the in-situ stresses may initiate formation failure. The inability to control sand production over the life of the well can be extremely costly as the sand produced with hydrocarbons will: •
Cause erosion of down hole completion components and topside surface facilities
•
Deposit in the well-bore and surface facilities necessitating costly sand removal operations and cleanouts
•
Cause reduction in production or, in worst case, stopping it completely
Typical sand control methods are: •
Restrictive Production Rate
•
In Situ Consolidation
•
Resin Coated Gravel
•
Gravel Pack
•
Screens - Natural Sand Packing (OH)
•
Fracturing for sand control
Even wells with successful sand control measures in place can / will produce small quantities of sand. For offshore installations (especially subsea) where several wells produce into a common production system this is critical. Sand must be first separated from the produced fluids and all oil removed prior to disposal. 4.3
Sand Screens
A sand screen is a tubing joint (also called base pipe) with a filter wrapped or attached onto it. The base pipe is perforated in standard screens. If an ICD is added to the screen the base pipe is not perforated as the flow
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from the formation is directed through the IDC nozzles. There are two main filters; Wire Wrapped Screen (WWS) and Dutch weave or sintered mesh laminate types (also known as Premium Screen). The purpose of the sand screen is to retain or filter the formation solids, thus preventing the entrance of the sand particles into the well-bore. The flow of the reservoir fluids is directed, using screen hanger and open hole packers, through the filtering system of the sand screen (see fig. 5 and 6). The formation sand is carefully analyzed and testing is performed to obtain the optimum sizing of the filter for a given reservoir sand.
Solids Deposits Filter Perforated Base Pipe Production Conduit
Figure 5 Flow of reservoir fluid through the sand screen
There are several different sand control techniques. On the Norwegian Continental Shelf the sand screens are run as part of the lower completion. The lower completion is run into the open hole section of the well-bore (see figure 6). In some cases the void between the screen outer diameter and well bore is packed with gravel to obtain better filtering of the produced fluids. This is called gravel packing. Open hole packers, such as inflatable, Mechanical External Casing Packers (ECP), Constrictors or Swell Packers (SP) are used to isolate sections of the reservoir and to prevent the annular flow. The entire open hole section is located in the reservoir section of the well.
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Figure 6 Location of sand screens in a horizontal well
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4.4
Inflow Control Device (ICD)
An inflow control device (ICD) is a device with nozzle or channels that restrict or choke the inflow of fluids from the screen section. The size and the number of the nozzles are designed to balance the inflow profile along the well-bore. ICDs are installed as an integral part of the sand screens. Figure 7 shows the Reslink’s ResFlow™ ICD screen. Reslink’s ICD can have 2 to 4 nozzles per unit joint and can be mounted with different nozzle sizes. Also outflow (injection) can be controlled and balanced by using a slightly different design. Reslink’s ResInject™ (see fig. 8) helps to balance the distribution of injected water. The red arrows illustrate the flow path through the sand screen and ICD assembly. ICD
Nozzle
Sand Screen
Figure 7 Wire Wrapped ResFlow™ ICD Screen [6]
Figure 8 Wire Wrapped ResInjectTM ICD Screen [6]
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4.5
Other available ICD designs
The ICD shown in figure 7 and 8 (Nozzle-type ICD) is one of four ICD designs available today. The three other designs are Tube ICD, Channel-type- and Orifice-type ICD. All these designs create a flow resistance, and they can be mounted on a screen joint. This thesis will focus on the Nozzle-type ICD. 4.5.1
Nozzle type ICD without Screen
Supplier 1 offers an ICD with a slightly different design than Reslink’s ResFlow™ screen (see fig.7). On each coupling (see fig.9-2) there are up to 8 nozzles (see fig.9-3). The nozzle size is predetermined to create a given pressure drop at a given flow rate. The centralized OD of the coupling (see fig. 9-4) provides a minimum standoff of the ICD from the Casing / open hole wall, allowing fluid to produce through all the nozzles [13]. The drawback with this design is that it does not allow filtering of the fluids. Formation particles will erode out and plug the nozzles..
Figure 9 ICD with nozzles from supplier 1 [13]
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4.5.2
Channel-type ICD
The channel-type ICD (see fig. 10) was developed by supplier 2. Instead of nozzles, this device uses a number of helical channels with a preset diameter and length to impose a specific differential pressure at a specified flow rate. Fluid flows from the formation through a limited annular space into multiple screen layers mounted on an inner jacket. After entering the screen fluid flows along the solid base pipe of the screens to the ICD chamber, where the chosen number of channels impose the desired choking. The last step in the process is fluid entering holes of a preset diameter. Fluid can also enter a slotted mud filter. The filter prevents the screen from being contaminated by kill mud during any future, well killing operation. The channel-type ICD causes a pressure drop to occur over a longer interval than the nozzle and orifice-type ICD’s, an advantage that will reduce the possibility of erosion or plugging of the ICD ports. One disadvantage is that the device depends on friction to create a differential pressure, and this implies that the actual pressure drop created will be more susceptible to emulsion effects [10].
Figure 10 Channel-type ICD [10] Supplier 3 offers an ICD using labyrinths (see fig. 11) instead of channels. Like the channel-type ICD, the labyrinth-type causes pressure drop to occur over a long interval which will reduce the possibility of erosion or plugging of the ICD ports. The labyrinth ICD is designed to provide the required inflow control at flow velocities below erosion limits [20].
Figure 11 Labyrinth-type ICD [20]
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4.5.3
Tube-type ICD
The tube-type ICD (see fig. 12) ,developed by supplier 4, consists of an annular chamber on a standard oilfield tubular. When a screen is applied, the reservoir fluid is produced from the formation through the sand screen and into the flow chamber. The requiered pressure drop is created by a set of tubes. After flowing through the tubes, the flow proceeds into the pipe through a set of ports. Tube lenght and inside diameter are designed to produce the differential pressure needed for optimum completion efficiency [19].
ICD Tube
Sand Screen
Standard oilfield tubular
Figure 12 Tube-type ICD [19] 4.5.4
Orifice-type ICD
The orifice-type ICD (see fig. 13) was developed by supplier 5. Multiple orifices produce the required differential pressure for flow equalization. Each ICD consists of a number of orifices of known diameter and flow characteristics. The orifices are part of a jacket installed around the base pipe within the ICD chamber as opposed to the nozzle-type ICD. By reducing the number of open orifices one can achieve different values of pressure resistance. The flow characteristics are expected to be similar to the nozzle-type ICD [10].
Figure 13 Orifice-type ICD [10] Page 20 of 57
4.5.5 Autonomous Inflow Control Device Supplier 2 has developed an enhancement of the existing ICD design, the Autonomous Inflow Control Device (AICD). As gas flows into a particular region of the well, the density decreases in the production fluid. This triggers the AICD valve to close or restrict flow from this zone. This density-sensitive valve has been designed to compliment the ICD. The system allows each screen joint to work independently, and coupled with open hole packers AICD provides an autonomous system, which controls gas influx.The valve design is totally mechanical and does not require an eletrical or hydraulic power source. The AICD could also be configured to shut off water, hence reducing the risk of water coning [21]. 4.6
Integration with Annular Isolation
One main advantage with the ICDs is the reduction of annular flow. Annular flow leads to the redistribution of fines along the screen open hole annulus, leading to a low permeability pack in the near well-bore area around the screens, impairing well productivity due to higher skins. However, ICD’s will only eliminate annular flow as long as there exist a highly homogenous permeability distribution along the length of the horizontal well-bore. This ideal situation is not always in place. Variations in permeability and hole size can trigger annular flow even when ICDs are installed. To exploit the full potential of the ICDs one has to integrate the ICDs with annular isolation (see fig.14). Most effective annular isolation in open hole completions is achieved by use of open hole packers. The purpose of the open hole packers is to isolate zones with different permeability, prevent annular flow and to direct the flow through the screens and ICDs. An effective combination with ICDs and open hole packers will contribute to an effective influx and reduced possibility of annular flow. Annular isolation systems being offered in the oil and gas industry, are: Inflatable or Mechanical External Casing Packers (ECPs), Swell Packers (SPs), Constrictors and Expandable Packers [10].
Figure 14 Open Hole Packers prevent annular flow and isolate zones with different permeability 4.7
Integration with Artificial Lift
A system that adds energy to the fluid column in a wellbore with the objective of initiating and improving production from the well is referred to as an artificial-lift system. Operating principles being applied in the oil/gas industry include rod pumping, gas lift and electrical submersible pumps. These technologies are Page 21 of 57
usually implemented to revive dead wells or to enhance the productivity of existing producers by lowering the well bottom hole pressure and boosting the vertical lift energy. A disadvantage with this technology in horizontal wells is that it will further aggravate the influence of pressure drop along the well-bore, hence, encouraging increased coning of water or gas. To reduce this phenomenon one can use a combination of ICDs with artificial-lift [10]. 4.8
Integration with Gravel Pack
Gravel Pack is a sand-control method used to prevent production of formation sand. To reduce the potential of sanding problems and to delay water/gas breakthrough, a combination of gravel pack and ICD’s would be effective. ICD’s together with annular isolation eliminate annular flow, a primary cause of sand particles becoming dislodged from the sand face and being transported along the annulus. Sand particles could cause screen erosion, plugging and sand production related problems at the surface. Field experience with gravel pack in horizontal wells has proven their ability to eliminate or minimize sand production [10].
5 5.1
PRINCIPLES OF THE ICD TECHNOLOGY Introduction
This section describes the principles of the ICD technology and the applicable mathematical equations.
The main benefit of the ICD technology is its ability to balance the in- and outflow profiles along the long horizontal well-bore. To illustrate this in simple terms, we take a garden hose, which represents a horizontal water injection well, and put a plug at the end of it (see fig. 15). Holes of the same diameter are made at even intervals along the length of the hose. When the water is turned on most of the water is jetted out through the first set of holes and very little or no water comes out from holes located nearer the end of the hose. There is just not enough energy / pressure left to push water further out towards the toe of the hose. In this case most of the injected water would go into the zones close to the heel, while the zones at the toe would not receive any pressure support. This would lead to an early water breakthrough in the zones that are receiving too much water and ineffective sweep in zones that receive little or no water.
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Figure 15 Principle of the ICD-technology depicted as a garden hose with large holes [6] If we change the large holes to very small ones, the same energy / pressure can evenly distribute the water along the entire length of the hose (see fig. 16). The very same principle has been used for many years in agriculture for irrigation, especially in regions where water is not found in abundance.
Figure 16 Principle of the ICD-technology depicted as a garden hose with tiny holes [6]
This same behavior is illustrated in figure 17. The drawing depicts a layered reservoir with variable reservoir permeability and characteristics. The standard completion represents a well without ICDs, where injected water will take the path of least resistance, i.e. into the high permeable zones, resulting in inefficient sweep of oil. The completion with correctly sized ResInjectTM ICD nozzles distributes the water evenly, resulting in a uniform sweep of oil (see fig. 17).
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Standard Completion
ResInject™ ICD
Figure 17 Standard completion versus ResInjectTM [8] 5.2
Pressure loss
During production of reservoir fluid, the pressure will decline compared to original pressure. It is preferable to produce as much oil as possible for a minimum loss of pressure. To choose the optimal completion options it is important to understand the pressure losses from the formation and through the production conduit. Before entering the tubing the fluid has to pass through several obstacles (see fig.18) [8]: •
Pressure loss in the formation
•
Pressure loss in annulus
•
Pressure loss in the completion
•
Pressure loss in the tubing
Figure 18 Pressure loss illustrated as a network of resistors [6] Page 24 of 57
Fluids in the formation always have a certain pressure, caused by the overburden pressure and the hydrostatic pressure. To be able to control the flow of fluids from the formation, there has to be a pressure difference between fluid in the well and fluid in the formation. These pressures are:
Ps = Static reservoir pressure Pwf = Flowing pressure in the well
Static reservoir pressure (Ps) has to be greater than flowing pressure in the well (Pwf). Pressure drop from the reservoir and into the well is then:
∆Pr = Ps - Pwf
[8]
(Eq. 5.2.1)
The pressure drop in the reservoir depends on the following factors: •
The flow rate (q); greater flow rate gives greater pressure drop (∆Pr)
•
Permeability (k); reduced permeability gives a greater pressure drop (∆Pr)
•
Viscosity (µ); well fluid with a high viscosity gives a greater pressure drop (∆Pr), than a well fluid with lower viscosity (µ)
•
Formation damage (S), resulting in reduced permeability (k) and a greater pressure drop (∆Pr)
•
Completion options; pressure drop (∆Pr) depends on the choice of completion: -Well diameter. If we increase the well diameter, pressure drop will decrease because the well fluid will enter the well at an earlier stage, and we get a larger flow area (increased radial flow region) -Variations in the perforations. The height of the perforated interval and the depth of the penetration -Sand control equipment. Gravel packing, screens or a combination of these -ICD’s. Regulate the pressure drop by using different nozzle sizes
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5.3
Pressure loss in the formation
Pressure loss in the formation is best described using Darcy law for the linear, horizontal flow of an incompressible fluid:
∆
∆
[7]
(Eq. 5.3.1)
Where: P: Pressure V: Velocity µ: Viscosity A: Cross-sectional area of the filter medium in flow parallel direction L: The length of the filter medium in flow parallel direction K: Proportionality coefficient (permeability) Q: Fluid flow rate
5.4
Bernoulli’s equation
To be able to size the ICD nozzles one needs to understand the law that explains the flow through a nozzle or orifice. Bernoulli’s equation states that the static pressure ps in the flow plus the dynamic pressure, one half of the density times the velocity V squared, is equal to a constant throughout the flow. The constant is called the total pressure pt of the flow. Restrictions governing the use of Bernoulli’s equation: non-gelling liquid, steady flow, incompressible fluid, no heat addition and negligible change in height [1].
[1] Where: Ps: Static pressure Pt: Total pressure V: Velocity ρ:Density
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(Eq. 5.4.1)
5.5
Pressure loss through the ICD
A completion with only screens will create little to no flow resistance from the annulus to the base pipe. The ICD provides a significant resistance by influencing the flow from the sand-face to the base pipe (production conduit), and thus influencing the flow from the reservoir to the sand-face. The pressure loss through the ICD is generated by flowing fluid through nozzles. Static energy in the fluid is being converted into kinetic energy and absorbed in the fluid downstream of the nozzle. The pressure loss through the nozzles is best described using a part of the Bernoulli equation (Eq. 5.4.1) [8]:
∆
[8] (Eq. 5.5.1)
Where: A: Cross-sectional area q: Fluid flow rate V: Velocity ρ: Density
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Figure 19 shows the pressure drop graphically with the horizontal well-bore length along the x-axis and the pressure in P (psi) along the y-axis. The reservoir is heterogeneous, hence different nozzle diameters are used to regulate the permeability variations. The blue dashed line illustrates the average annulus pressure based on the different nozzle settings. In high permeability zones a smaller nozzle diameter is used to choke the inflow, hence stimulating the contribution from low to moderate permeability zones. This can be seen in figure 19 where the ICD has increased the pressure drop in the heel section and reduced the drawdown pressure from the reservoir. The technology is self regulating and viscosity independent (nozzle-type ICD). From equation (5.5.1) one can see that increased velocity will give increased pressure drop, which causes greater resistance. This principle implies that the ICD reduces flow from high permeability zones and increase flow from zones with lower permeability. Without the ICD’s there would be a higher drawdown pressure in the heel section. This combined with the high permeability would result in a high contribution of oil from the heel section and a limited contribution from the toe section. Heterogeneity / Permeability (mD)
Measured Depth, MD (ft)
Pressure (psi)
Reservoir Pressure, Pres Reservoir Drawdown, ∆PF1 ICD Design Pressure Drop ∆PN1
Heel
∆PF7
At SandFace Average annulus Pressure, Pann
∆PN7
Tubing Pressure, Ptbg
Typical Long Horizontal Well Completions Pressure profile
Toe
Figure 19 ICD interaction in a heterogeneous reservoir [14]
Page 28 of 57
Measured Depth, MD (ft)
5.6
Production index, PI
The production index (PI) shows the relationship between production rate and pressure loss between reservoir and well. It is a measure of the wells production potential of well fluid [9].
For oil:
[9]
(Eq. 5.6.1)
Where: 3
PI: Production index in m /d/bar or bbl/d/psi (and d = 24-hour period) q0: Production rate of oil in m3/d or bbl/d qw: Production rate of water in m3/d or bbl/d ps: Static reservoir pressure in bar or psi pwf: Flow pressure in the well in bar or psi
When Reslink’s ResFlow nozzle ICD is introduced into the system we have
∆
[17]
(Eq. 5.6.2)
Where:
q:
Rate of oil
PDrawdown:
Total pressure drop from reservoir to tubing in bar or psi
PReservoir:
Reservoir pressure in bar or psi
FBHPScreen:
Pressure drop between the filter and the base pipe before entering nozzles in bar or psi
ΔPNozzles:
Pressure drop through nozzles in bar or psi
Page 29 of 57
5.7
Candidate Recognition
Current applications in both horizontal and/or deviated production wells to minimize coning of water and/or gas. Homogeneous, heterogeneous, multilayered and thin oil column reservoirs are well suited for ICD application. Injection wells, either in horizontal and/or deviated injection wells to evenly distribute or balance the injection along the well- bore in homogeneous and heterogeneous reservoirs. Here the main objective is to efficiently add energy to the reservoir and to achieve uniform sweep of oil without exceeding or reaching fracture gradient pressures, commonly occurring with conventional completions.
ICD technology adds value in reservoirs with declining production by injecting CO2 and water or both. Water provides pressure support and the CO2 will fluidize remaining hydrocarbons, hence increasing the recovery factor.
Page 30 of 57
6 6.1
SIMULATION AND ANALYSIS TOOL NeToolTM Simulation Program
NEToolTM analysis software [11] is used to select the correct nozzle combination. NEToolTM is a program based on equations of pressure loss in the reservoir, annulus and tubing. It is a toolbox for improved reservoir management. The program can simulate different kinds of completion equipment in the well, and analyze the results. Modelling from NEToolTM looks at the reservoir flow and the completion hydraulics. To get a full model, data from upper completion will have to be imported. The flow from the near well-bore nodes (i.e. reservoir gridblocks) into the well completion are represented by a specified number of nodes which can be connected in a number of different ways in order to simulate flow through the annular space, through any completion equipment such as ICD’s or through the tubing [10]. A limitation with NEToolTM is that it only creates a freeze-frame of the production in the well, and not the production over a period of time. The program also anticipates stationary flow. To set up the lower completion, data of the wells trajectory, and reservoir parameters like reservoir pressure and permeability will be needed. The skin-factor can be set manually or be calculated from data on the reservoir damage. Fluid properties like relative permeability and PVT will also have to be included. NEToolTM allow inputting different ranges for the parameters that can be changed by the user to evaluate different scenarios. Figure 20 shows the modelling principles of the NEToolTM simulation program[11].
Figure 20 Modelling of the well with NEToolTM [15] Page 31 of 57
Diagram 1 illustrates the simulation flow diagram for NEToolTM analysis software. Parameters can be changed to simulate different scenarios.
Diagram 1 Simulation flow diagram for NETool
Page 32 of 57
TM
7
FIELD EXAMPLE FROM THE NORTH SEA
7.1
Introduction
This section describes a simulation with real field data using NEToolTM. The simulations were performed with four different objectives: 1.
To compare the performance of a conventional Stand Alone Screen (SAS) with a completion hardware using ICD’s
2.
How zonal isolation (SP’s), Blank Pipe or other alternatives add value to the completion
3.
After establishing the best case, evaluate how ICD’s will delay water breakthrough
4.
Finally an example with ICD in injection mode will be shown to analyze the distribution of injected fluids should a need for well stimulation arise
For all the scenarios a constant oil flow rate at 1500 Sm3/D is applied. Both non-collapsed and collapsed annulus environments were considered.
7.2
Qality control of data
The reservoir grid was provided by Marathon Oil Corporation together with an alternative well trajectory. The data set is from a field in the North Sea. Real field parameters will give more relevant and deterministic simulations. Well trajectory data and PVT-data were imported to NEToolTM to create the fundament for the simulations. Table 1 shows the reservoir and completion data.
Table 1 Reservoir and completion data Page 33 of 57
7.3
Reservoir parameters
Figure 21 depicts the simulation grid. Upper section shows the horizontal projection of the well with pressure distributions. The lower display section shows the vertical projection profile together with the well trajectory. The pressure in the darkest red areas is about 227 bar, while the darkest blue grids have a pressure of about 206 bar.
Well trajectory
Figure 21 Display of the simulation grid together with the proposed well trajectory and pressure distribution attribute.
Page 34 of 57
Figure 22 shows the horizontal permeability variations along the well trajectory. Notice the grey, which do not contain data
Well trajectory
Figure 22 Attribute display showing the horizontal permeability variations. The permeability along the well trajectory varies from approximately zero Darcy in the darkest blue areas to 3,2 Darcy in the lighter blue areas In figure 23 vertical permeability (KV) relative to horizontal permeability (KH) is shown along the well trajectory. The darkest red areas have a KV/KH ratio close to one. Blue grids have a KV/KH ratio varying between 0,00004 and 0,2, which implies a high horizontal permeability.
Well trajectory
Figure 23 KV/KH along the well trajectory Page 35 of 57
Figure 24 displays the oil saturation, where deep red colours indicate high oil saturation. Oil saturation in the red grids varies from 0,7 to 0,9. The well is placed approximately 7 meters over the water contact showed by the blue colour (very low oil saturation). The well trajectory is depicted through the grey horizontal line. As can be seen from the grid some saturation data is missing from the toe section of the well (grey area without grids). This is a source of error when performing simulations for different scenarios, and has to be taken into consideration when evaluating the data.
Oil water contact
Figure 24 Oil saturation along well trajectory. OWC approximately 7 m below the well trajectory.
Page 36 of 57
Figure 25 display the water saturation. Dark red colours indicate high water saturation. In the blue grids the water saturation ranges between 0,07 and 0,35. A very high resolution grid is used.
Above water contact
Below water contact
Well trajectory
Figure 25 Attribute display of the water saturation Figure 26 display the porosity along the well trajectory. Porosity average is approximately 23%. Over the interval 4305 m to 4325 m the well is traversing a very low pay zone. This needs to be considered when designing the well completion.
Figure 26 Attribute showing porosity along well trajectory. Red circle indicating low pay zone. Porosity varies from 11,6% (dark blue grids) to 30,6% (dark red grids). Page 37 of 57
Figure 27 shows the permeability along the well trajectory. The permeability is showing variations along the completion. The red colour is from the high resolution log and the light blue is the one that is up-scaled. The permeability input is not the one extracted from the grid. High resolution log was selected in order to better evaluate the performance of the completion (each section of the completion length is 12 m). Permeability is varying along the completion trajectory from low to moderate to very high (0Æ7,5 D). In general the permeability increases towards the toe, therefore the challenge for the completion is to stimulate production from the toe section. The high resolution log reveals some zones with very high permeability values. For instance at 4443 m the permeability reaches 7,5 D.
Figure 27 Permeability variations along well trajectory. High resolution log marked with pink colour and the up-scaled log in blue.
Page 38 of 57
Figure 28 shows the reservoir pressure along the well trajectory. The pressure profile is extracted from the reservoir grid, and that is why it shows a blocky response. The pressure averages about 207,50 bar and it ranges between 207,35 and 207,66 bar.
Figure 28 Pressure variations along well trajectory. The x-axis show measured depth (MD) and the yaxis show pressure in bar.
Page 39 of 57
Figure 29 show the saturations of oil and water along the well trajectory. The saturations are extracted from the grid. The green bars show the oil saturation and the blue bars the water saturation. The oil saturation varies from 0,8 to 0,5. The complement is the water saturation. There is no data at the grey zones, except at 3280 m where a section of cemented blank pipes is placed in the completion. The challenge in the completion is to handle the saturation differences, and to achieve a balanced flux from the reservoir into the well. Water cut reduction and early water breakthrough is one of the main challenges of the successful ICD completion.
Figure 29 Saturations profile along the well trajectory showing variability (could be due to previous oil production, mature reservoir)
7.4
Results from the producer well evaluation
The first objective was to compare the performance of a conventional completion with SAS (Stand Alone Screen) with a completion using ICD’s. Zones with cemented blank pipes (CBP) where kept at original positions as per the Marathon well data (3280 m, 3765 m and 3765 m). A non- collapsed annulus (NCA) was selected as the general comparison scenario. Two nozzle settings are used for the ICD simulations, 0,4137 cm (diameter) from heel to 3280 m and 0,5402 cm to the toe of the well. The two ICD sizes were selected based on permeability, saturations and reservoir environment. Consequently, pressure readings will be higher over the first section of the well and lower towards the toe because of differences in nozzle sizes.
Page 40 of 57
7.4.1
Non-Collapsed Annulus
Non-collapsed annulus is a case where the formation sand has not collapsed onto the pipe or screens, leaving an open annulus between pipe/screen and the formation.
a)
b)
Reservoir pressure Annular and tubing pressures
Cemented blank pipes
c)
d)
QO tubing QO annulus Cemented blank pipes
e)
f)
Figure 30 Summary display of conventional completion: a) Permeability profile along the completion, b) Reservoir Pressure (red) conventional tubing and annular pressure with very low dynamic range (overlapping colour pink and blue), c) Oil flux rate, where the conventional completion show high volume in the tubing and in the annulus, d) Gas flow rate, similar response to the oil flow rate, e) Water flow rate, notice a high volume of water circulating in the annulus, may cause screen erosion and hot spotting if the well is completed with only screens, and f) Oil and water saturations.
Page 41 of 57
a)
b) Annular pressure Tubing pressure
c)
QO tubing QO annulus
d)
e)
f)
Figure 31 Summary display of the ICD completion. Highlighted in red, the interval where annular flow is slightly higher, it is because of the larger nozzle size. However this flow will be further minimised by introducing OH packers. a) Permeability profile along the completion, b) Reservoir Pressure (red) ICD completion annular (pink) and tubing (blue) pressure c) Oil flux rate, where the ICD completion show high volume in the tubing and low in the annulus, d) Gas flow rate, similar response to oil flow rate, e) Water flow rate, notice the low volume of water circulating in the annulus, and f) Oil and water saturations.
Pressure differences are minimal being 2 bar for conventional and 2,5 bar for ICD. The ICD show a slightly lower water rate and very similar water cut (about 19,5%). The standard completion has high annular flow. ICD’s minimizes the annular flow and stabilizes the drainage profile. Annular and tubing pressures are separated using the ICD, only disrupted in the areas where we have cemented blank pipes. From about 3800 m to the toe the base case ICD completion still show increase in annular flow (highlighted in red), which will require further optimization (OH Packers).
Page 42 of 57
Reservoir pressure
a)
Conventional: Annular and tubing pressure
ICD: Annular pressure ICD: Tubing pressure
b)
c)
ICD
Cemented blank pipe
Cemented blank pipe
Conventional
d)
Figure 32 Pressure comparison between a conventional completion and one with ICD’s along the entire well length. Notice: The highlighted red circle showing lower drawdown for both completions. a) Tubing and annular pressure for both conventional and ICD completion, b) Reservoir pressure along the completion, c) Drawdown pressure for both the ICD and conventional completion, d) Notice the pressure drop along the completion with ICD’s are higher than in the conventional completion. Therefore the ICD will enhance production at the toe part of the well, where conventional completions usually are very passive.
The pressure plot show nearly a constant drawdown for the conventional completion, from 2,28 bar to 1,74 bar in the toe. An insignificant pressure drop along the completion. The ICD completion have a uniform drawdown pressure in the different permeability zones.
Page 43 of 57
ICD Completion
Conventional completion: Tubing
Cemented Blank Pipe
Conventional: annular flow
Interval to be further optimised
ICD annular flow
Figure 33 Oil flow rate: conventional completion and one with ICD’s. Notice the difference in annular flow for the two completion options There is a better oil flow rate with ICD’s than just with a standard completion, because ICD’s minimize annular flow. From 2750 m to around 4300 m the ICD completion has a considerable higher oil flow rate. The red circle indicates the area to be further optimized. Toward the toe of the well the ICD still show annular flow, hence the flow rate lies under the standard completion. Annular flow could lead to severe erosion and/or screen plugging. One single nozzle size acts differently in the reservoir because the permeability profile shows mainly two zones. Therefore the simulation should try to equalize the flow in the heterogeneous reservoir, by stimulating the low to moderate permeability intervals to produce more. At the same time to stimulate the toe part to contribute to the production.
Page 44 of 57
ICD Completion
Conventional
Interval to be further optimised
Figure 34 Oil flux: Conventional completion (blue) and one with ICD’s (pink)
Figure 34 show the oil flux with a conventional (blue) completion and one with ICD’s (pink). Between heel section of the well to about 3750 m ICD oil flux is higher than conventional and vice versa towards the toe part. The ICD has two nozzles size settings. Notice that these tests are processed using a Non-Collapsed Annulus (NCA) option, furthermore the completion geometry of a conventional and ICD completions have different flow dynamics along the well.
Page 45 of 57
ICD Completion
Conventional Completion: Tubing Conventional: Annular flow
Interval further optimised ICD: Annular flow
Figure 35 Oil flow rate: Conventional and one with ICD’s with 3 OH packers located at 4055 m, 4435 m and 4645 m. Notice how the performance of the ICD’s is enhanced and the annular flow (light blue) is almost eliminated by introduction of the 3 OH packers.
As can be seen in figure 35 the annular flow output after installing 3 OH packers in the completion has significantly reduced annular flow and enhanced oil recovery. The ICD completion with 3 packers (green line) has now a larger oil flow rate than the conventional completion along the entire well. The water rate has decreased with 12 Sm3/d and water cut has been further reduced by 0,55%. Table 2 shows the results of the non-collapsed annulus scenario.
Option: Non-Collapsed Annulus (NCA) Oil rate Gas rate [Sm3/d] 1499.9384 1500.25221
[MMSm3/d] 0.160193423 0.160226938
Conventional ICD base case ICD BC packers 1499.96287 0.160196037
Water rate
GOR
WCUT
LGR
Q res. total
BHP
[Sm3/d] 374.275916 373.210219
[Sm3/Sm3] 106.800002 106.800002
[%] 19.9697502 19.9208809
[Sm3/Sm3] 0.0116996957 0.0116925559
[Rm3/d] 2321.93425 2321.46966
[Bar] 205.1665871 204.5214831
19.4545272 0.0116248566
2310.04788
204.4199563
362.293092 106.800002
Table 2 Results of the non-collapsed scenario
Page 46 of 57
7.4.2
Collapsed Annulus Scenario
Collapsed annulus simulation shows similar trend as the non-collapsed annulus stimulating low to moderate permeability zones to produce more. The production profile shows a slightly lower oil flow rate for the ICD, however the water breakthrough test will show higher performance.
Option: Collapsed Annulus (CA) Oil rate Gas rate Conventional ICD BC packers
Water rate
GOR
WCUT
LGR
Q res. total
[Sm3/d]
[MMSm3/d]
[Sm3/d]
[Sm3/Sm3]
[%]
[Sm3/Sm3]
[Rm3/d]
[Bar]
1499.5718 1498.51081
0.16015427 0.160040958
362.599816 369.066479
106.800002 106.800002
2309.74853 2315.08373
204.7396453 204.2925893
19.4718797 0.0116273616 19.761778 0.0116693709
BHP
Table 3 Results from the collapsed annulus scenario
7.4.3 Water Breakthrough (Collapsed Annulus) A random interval was selected simulate early water breakthrough. The objective is to lift dry oil and extend the production life of the well. The interval from 3885 m to 3925 m was selected for the simulation. Permeability greater than one was selected for the interval. Saturations were changed to 0,3 for oil and 0,7 for water. Figure 36 show the oil flow rate for both ICD and conventional completion.
ICD Completion with 3 packers
Conventional Completion
Figure 36 Oil flow rate after water breakthrough: Conventional completion and one with ICD’s with 3 OH packers at 4055 m, 4435 m and 4645 m . Page 47 of 57
Conventional Completion
ICD Completion with 3 packers
Figure 37 Water flow rate after water breakthrough: Conventional completion and one with ICD’s with 3 OH packers at 4055 m, 4435 and 4645 m
The ICD with a smaller size (0,4137 cm) delays the water efficiently in the first half of the well (see fig. 37), while in the second half the larger ICD size (0,5402 cm) is enhancing oil production (see fig. 37). A compromise had to be made. The ICD completion increases oil production from the toe section, but at the same time it increases the water cut. Compared to the conventional completion, the ICD set up has decreased water flow rate significantly. Water rate has decreased from 544,8 Sm3/d for conventional completion to 403,3 Sm3/d for the ICD completion. Oil flow rate is 1096 Sm3/d for the ICD completion with OH packers and 955 Sm3/d for the conventional completion. Figure 38 shows a reduction in water cut from 36% to 27% in favour of the ICD completion.
Page 48 of 57
a)
ICD Completion
Conventional Completion
b)
Conventional Completion 36%
c)
ICD Completion 27%
d)
e)
Figure 38 Oil Flux Reservoir to Well: after the water breakthrough. a) Oil flux for ICD and conventional completion, b) Gas flux for ICD and conventional completion, c) Water flux for ICD and conventional completion. Notice the reduction of water flux in the water breakthrough area, d) GOR along well trajectory, e) Water cut along well trajectory
Page 49 of 57
a)
ICD annular pressure Conventional: annular and tubing pressure
ICD tubing pressure
b)
ICD
c) Conventional
d)
Figure 39 Pressure Comparison between a conventional completion and one with ICD’s after the water breakthrough. a) Annulus and tubing pressures for ICD and conventional completion, b) Reservoir pressure along well trajectory, c) Draw down pressure for ICD and conventional completion, d) Pressure drop across the completion for ICD and conventional. Notice the pressure drop for the conventional completion is 0 bar
As a curiosity the reservoir pressure was already showing a lower trend in the WBT (water breakthrough) area.
Option: Water Breakthrough Oil rate Conventional ICD BC packers
Gas rate
Water rate
GOR
WCUT
LGR
Q res. total
[Sm3/d]
[MMSm3/d]
[Sm3/d]
[Sm3/Sm3]
[%]
[Sm3/Sm3]
[Rm3/d]
[Bar]
955.153824 1096.15866
0.10201043 0.117069747
544.80438 403.298903
106.800002 106.800002
1789.52838 1828.58439
205.6592684 205.1852942
36.3213041 0.014703969 26.8963198 0.0128082412
Table 4 Results from the water breakthrough scenario (collapsed annulus)
Page 50 of 57
BHP
7.5
Converting the producer well into an ICD in injection mode
The completion layout was converted into an injector to evaluate the injection mode. Reservoir properties and the hardware with ICD’s are kept at the original settings. Water injection rate of 1000 l/min was used in the example. The injection pressure has to be below the formation fracture pressure. The fracture pressure is nearly the same along the well trajectory. This helps to achieve more uniform distribution of the injected fluids.
a) KH KV
ICD tubing pressure
b)
Conventional: annular and tubing pressure ICD annular pressure
Reservoir pressure
c)
Figure 40 Summary plot: ICD injection mode. a) Horizontal (red) and vertical (brown) permeability, b) ICD tubing pressure (brown), ICD annular pressure (green), conventional annular and tubing pressure (pink and blue) and reservoir pressure (turquoise), c) Water flow rate for ICD (red) and conventional (blue).
Figure 40 shows a summary plot for the injection simulation. At 4450 m the permeability is very high and the section acts as a thief zone when injecting using conventional completion (SAS). Notice how the annular pressure decreases when using ICD in this zone (see fig. 40 b). This shows the self regulating effect of the ICD. The annular and tubing pressures for the conventional completion are equal along the well-bore.
Page 51 of 57
As figure 41 shows, the ICD completion gives a more uniform injection distribution. This results in a better injection performance. The conventional completion has a high water flux in high permeability zones and/or fractured zones.
Conventional completion Balanced
injection
and better injection conformance ICD completion
Figure 41 Water flux: Conventional completion and one with ICD’s. If the well have scale potential deposition, a well treatment using the same configuration will distribute the anti-scale inhibitors evenly thus extending the life of the well. The added benefit of ICD’s is the performance in producing and injection mode without adding extra costs.
Option: Injection
Conventional ICD BC packers
Water rate [Sm3/d] 1499.92916 1500.00426
Q res. total [Rm3/d] 1522.13377 1522.19949
Table 5 Injection parameters
Page 52 of 57
BHP [Bar] 208.2261854 208.4124388
8
CONCLUSION
The increasingly popular horizontal wells suffer from unbalanced influx and injection profile. This can be greatly improved by introducing Inflow Control Devices (ICD), which choke the inflow or outflow through the ICD, thus balancing the production or injection profile along the well-bore. The ICD completion design shows higher performance in terms of reservoir inflow balance and efficiently delaying early water breakthroughs, thereby reducing the water production over time. Two nozzle size setting handles the differences in permeability and reservoir properties along the entire well, thus stimulating the low to moderate permeability intervals to produce more. The well will have a longer production life due to more uniform drainage. The optimum completion design – ICD’s with OH packers – offers tangible benefits in terms of accelerated production and increased oil recovery. This thesis does not consider the life cycle economics, but the simulations suggest a high potential for better NPV compared to the conventional completion. NEToolTM only provides a snap shot of the well performance. As stated in the recommendations, full well life or even field life simulation using a dynamic reservoir model is required for more complete evaluation of well/field performance and the economics. Having said this, the NEToolTM simulations offer guidance in selecting the right type and size of completion. The benefit of the NEToolTM is that the simulations can be run much more quickly than the ones with dynamic models. TM
Simulations were performed with NETool to compare the performance of conventional Stand Alone Screen (SAS) versus screens with ICD’s. The ICD completion minimizes the annular flow effectively and balances the drainage profile. Further improvement in terms of reduced water cut and increased production was achieved by adding the open hole (OH) packers. The OH packers eliminate the risks related to the annular flow; erosion and/or plugging of the screens. The water breakthrough simulation with ICD’s decreased water rate significantly compared to the conventional completion (SAS). The water rate decreased from 544,8 Sm3/d (conventional completion) to 403,3 Sm3/d (ICD completion). Oil production for the ICD completion with OH packers is 1096 Sm3/d versus 955 Sm3/d in the conventional completion. The injection simulation showed a more balanced injection profile along the well-bore using ICD’s. The conventional completion had a high water flux into the high permeability/fractured zones, also called thief zones. This added benefit of using ICD’s can become important if stimulations are required later in the well life.
9
RECOMMENDATIONS
Further work could include: a.
Evaluate ICD design with different Total Reservoir Rates (tested only with 1500 Sm3/d).
b.
Alternative nozzle locations, e.g. every second joint if cost minimization is an issue. Page 53 of 57
c.
The best case defined in this thesis, could be the input for the dynamic simulator.
d.
ICD in injection mode sensitivities with variable anti-scale inhibitors (tested only with 1000 l/m).
10
ACKNOWLEDGEMENTS
This thesis was written in cooperation with Schlumberger ResLink. Reslink is a Ålgård and Houston based design and manufacturing company of screens and ICD’s. Reslink’s in-house reservoir department performs simulations and evaluations of the ICD technology.
I want to thank Reslink for giving me the opportunity to write the thesis and especially Reslink’s Reservoir Engineer Francisco Porturas, who has been my mentor throughout the process. His guidance and many valuable advices have been of paramount importance. I also want to thank Professor Erik Skaugen at the University of Stavanger for mentoring.
Special thanks to Senior Completion Engineer Tor Ellis, Marathon Oil for kindly providing the reservoir data used in the simulations
11
NOMENCLATURE
ICD
Inflow Control Device
SP
Swell Packer
SAS
Stand Alone Screen
NCA
None Collapsed Annulus
CA
Collapsed Annulus
NPV
Net Present Value
ECP
External Casing Packer
WBT
Water Breakthrough
WCUT
Water Cut
BHP
Bottom Hole Pressure
OH
Open Hole
OWC
Oil Water Contact
CBP
Cemented Blank Pipe Page 54 of 57
GOR
Gas Oil Ratio
LGR
Liquid Gas Ratio
BC
Base Case
RDF
Reservoir Drilling Fluid
AICD
Autonomous Inflow Control Device
WWS
Wire Wrapped Screen
12
REFERENCES
12.1 Written references 1.
National Aeronautics and Space Administration. [Online]. Bernoulli’s Equation. Address: http://www.grc.nasa.gov/WWW/K-12/airplane/bern.html. [Downloaded 01/14-08] 2008.
2.
Efluids bicycle aerodynamics. [Online]. Bernoulli’s Equation. Address: http://www.efluids.com/efluids/bicycle/bicycle_pages/Bernoulli.jsp. [Downloaded 01/16-08] 2008.
3.
Tor Austad and Jostein Kolnes. Reservoir Engineering – Part 2.
4.
Frank Jahn, Mark Cook and Mark Graham.Hydrocarbon exploration and production. Developments in petroleum science 46.Aberdeen, TRACS international ltd.1998.
5.
Schlumberger. http://www.glossary.oilfield.slb.com/DisplayImage.cfm?ID=498. [Downloaded 01/2208] 2008.
6.
Reslink Power Point presentation. “Next Gen of Flow Control with Sand Screens”. Workshop 5-6 September 2007.
7.
Anatoly B. Zolotukhin, Jan-Rune Ursin. Introduction to Petroleum Reservoir Engineering. Høyskoleforlaget. 2000.
8.
SPE 106018. ICD Screen Technology Used To Optimize Waterflooding in Injector Well. A.G Raffn, SPE, Reslink, S. Hundsnes, SPE, Statoil; S. Kvernstuen, SPE, T. Moen, SPE, Reslink. 2007.
9.
Erland Jørgensen. “Produksjonsteknikk 1”. Vett & Viten AS. 1998.
10. SPE 108700. Inflow control device: Application and value quantification of a developing technology. F.T. Alkhelaiwi, SPE, Heriot-Watt University and Saudi-Aramco, and D.R. Davies, SPE, Heriot-Watt University. 2007. 11. DPR Power Point presentation. FORCE AWTC Seminar, 21-22 April, 2004. Advanced Wells - Lessons Learned (application experience) and Future Directions/Opportunities. Page 55 of 57
12. R.D. Fritz, M.K. Horn, S.D. Joshi. Geological Aspects of Horizontal Drilling. The American Association of Petroleum Geologists, 1991. 13. Flotech products. [online]. http://flotechltd.com/data/FloMatik_C.PDF [Downloaded 04/30-08] 2008. 14. Reslink Power Point presentation. 03/26-08. “Advance Completions Application of Passive Inflow Control in Horizontal Well Production”. 15. Institutt for petroleumsgeologi og anvendt geofysikk. Statoil ASA, and. Bergen. Eksperter I team, Gullfakslandsbyen. “Kompletteringsløsning på GF B-17AT2”. Andreas Mathiassen, Atle Storaker, Tor Erik Askeland og Trygve Adolfsen. Trondheim 9. Mai 2007. 16. SPE 112471. Inflow Control Device and Near Well Bore Interaction. T. Moen. SPE, Reslink AS and H. Asheim, SPE, NTNU. 2008. 17. Completion – ICD: Modelling Workshop Saudi Aramco. Francisco Porturas.Reslink – Norway. September 2007. 18. Optimising production in Horizontal & Multilateral wells 2008. The Ardoe House Hotel, Aberdeen, U.K. 29/30 January 2008. ICD Completions. Round Table Discussion. Tor Ellis, Senior Completion Engineer, Marathon Oil. 19. RedTech. Enhancing the capabilities and economics of complex completions. [online]. Address: http://www.halliburton.com/public/divisions/pubsdata/PO/RedTech/notes/Sand-ScreensPodCast.pdf?linkType=Sand-Screens-PDF. [Downloaded 22.05.08] 2008. 20. Ziebel. Inflow Control Technology. [online]. Address: http://www.ziebel.biz/icd/ICD_Overview.pdf. [Downloaded 23.05.08] 2008. 21. SPE 102208. Means For Passive Inflow Control Upon Gas Breakthrough. S.L. Crow, SPE, M.P. Coronado, SPE, and R.K. Mody, SPE, Baker Oil Tools. September 2006.
12.2 Oral references 22. Francisco Porturas, Reservoir Engineer in Reslink 23. Timo Jokela, completion specialist in Schlumberger 12.3 Software 24. Microsoft Excel (2007) 25. Microsoft Word (2007) 26. Microsoft Power Point (2007)
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27. NEToolTM (version 2.9), a steady-state completion hydraulics and near-well-bore numerical simulator for accurate calculation of well performance.
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