SPE-159634-PP

Increased oil production at Troll by autonomous inflow control with RCP valves Martin Halvorsen, Geir Elseth, Olav Magne Nævdal, Statoil ASA

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Troll is a large subsea development offshore Norway. Oil is produced to Troll B and Troll C platforms

from 120 long horizontal subsea wells completed in a thin oil column. Oil production is optimized

within the gas handling capacity at the platforms and the challenge is to drill and complete the wells in

a way that gas does not have an easy access into the well. Troll has focused on developing and

implementing inflow control devices that limits gas coning. An autonomous inflow control device, the

RCP valve, has been developed by Statoil and implemented at the Troll field. The purpose of the RCP

valve is to restrict gas compared to oil. The valve adjusts the choking of the fluids depending on which

phase (oil or gas) being produced. Currently three wells have been completed with RCP valves.

Reservoir simulations as well as production experience show a significant increase in oil production. It

is observed that a well completed with RCP valves has a significantly lower gas oil ratio development

compared to other Troll wells.

Introduction Horizontal wells with one or more branches have been used to maximize reservoir contact by Statoil and other oil companies

for more than a decade. The use of inflow control in wells can be even more important today as reservoirs mature. Examples

of recent work are listed in [1-4].

Troll is a large subsea development offshore Norway, see Figure 1. Oil production from Troll started in the fall of 1995. Oil

is produced to Troll B and Troll C platforms from 120 long horizontal subsea wells completed in a thin oil column overlayed

by a thick gas cap. Troll field is further described in [5-7]. The thin oil layer was between 22 and 26 meters in the Troll West

oil province (TWOP) and 11 and 13 meters in the Troll West gas province (TWGP). The challenge is to drill and complete

the wells in a way that gas does not have an easy access into the well. In order to start profitable oil production from this thin

oil layer, it was necessary to develop advanced drilling and production technology. Hence, the oil production wells drilled in

Troll were horizontal wells. The main reservoir driving mechanism is gas expansion and horizontal production wells are

located close to the oil-water contact to maximize oil production. Historically, length of horizontal production sections has

increased. Wells drilled in 1998 had reservoir sections of about 1500 meters, while recent wells are drilled with reservoir

lengths of more than 3500 meter. Most of the wells are controlled by inflow control devices, which are friction inducing

elements distributed along the well for improving the well performance [8]. The technology is regarded as standard

2 SPE SPE-159634-PP

technology by the industry and classified as passive inflow control, since the geometry of the devices are fixed or preset prior

to installation.

Figure 1: Presentation of the Troll field

The main reservoir is the Late Jurassic Sognefjord Formation. The Sognefjord Formation was deposited in a shallow marine

setting as a stacked sequence of sandstone and siltstone units with a total thickness of around 160 m. The most important

reservoir facies type is a medium to coarse grained clean and high-permeable sandstone (c-sand). The porosity ranges from

30-35% and the permeability from 1D to more than 20D. These units alternate with very fine to fine grained micaceous and

SPE-159634-PP 3

low permeable sandstones (m-sand). The porosity in the m-sands ranges from 20-28% and the permeability from 0.1mD to

around 1D. A third lithological component is calcite cemented zones. These may be several meter thick and laterally

extensive, and represent local barriers to fluid flow.

Reuse of well slots by redrilling new wells in between old producers is the main contributor to IOR at Troll. There are

contact movements, both gas/oil and oil/water contacts, throughout the field and geosteering is actively used to position new

wells close to the oil/water contact. The vertical distance from the horizontal well path to the gas oil contact is uncertain and

it is a challenge to complete the horizontal well in a way that avoids an early gas breakthrough in parts of the well.

There is a limited gas handling capacity at the Troll platforms and oil production is optimized within these limits. The

infrastructure at the Troll field is illustrated below in Figure 2.

O2

O1

N2

N1

M1

M2

S1 S2

Q1Q21

D

E

F

H

B1

Z1

Z2

I1 I2I32

J1 J2

L1

L2

K1 K2

P1

P2

Troll B

Troll C

T1

T2

U2

U1

A2

B1B2

A1

Fram

16’’

Mongstad

Mongstad

2x36’’

16’’

20’’

16’’

OilGasWater

G

Troll A

Troll pilot WI

- Subsea template:4 - 6 well slots

- Manifold

- Single welhead

Figure 2: The Troll infrastructure

Drainage and completion at the Troll oil field

Horizontal wells are characterized by an uneven drainage profile from the heel of the well to the toe, even when equipped

with conventional passive ICDs. Frictional pressure drop and variation in permeabilities and mobility will naturally lead to a

non-uniform inflow profile along a well. At Troll this can eventually result in a gas breakthrough, which may reduce the well

performance and recovery significantly. The breakthrough typically occurs in the heal region of the well, regions with high

reservoir permeability or sections with a short distance to the gas/oil contact. Passive inflow control is applied to delay the

unwanted gas breakthrough, but will not reduce or stop the breakthrough. Production phase and GOR development after gas

4 SPE SPE-159634-PP

breakthrough is also very important since gas breakthrough is usually observed after only some months of production.

Understanding completion and drainage of thin oil zones in long reservoir sections with varying reservoir permeability is

very important in order to optimize oil recovery. A sketch of a well in two different reservoir sections is presented in Figure

3. Four main areas to consider are:

Completion inflow control

Reservoir permeability contrast

Annulus flow and packers

Remaining oil along the horizontal section

Figure 3: Well completion in reservoir sections with different permeability

Completion inflow control

Inflow profile along horizontal section is strongly influenced by pressure friction loss in tubing due to low drawdown into the

Troll wells. High focus on inflow control devices (ICD) to even out production is important to maximize oil production.

ICD’s are installed in all wells drilled since almost the beginning of field development.

Reservoir permeability contrast

Almost all wells are drilled in alternating ‘c-sand’ and ‘m-sand’ intervals. The c-sands are within permeability range from 1

to 30 Darcy. The m-sands are characterized by permeability lower than c-sand and may be as low as 0.1 mDarcy. Most of the

wells have about 60 – 70 % c-sand. Simulation results indicate that these permeability contrasts in wells will influence inflow

from reservoir to annulus at the low drawdown seen in the Troll wells. The lowest permeability m-sands do not contribute to

production. The higher permeability m-sands contribute to some degree. Simulations indicate also that higher Darcy c-sand

intervals contribute more than lower Darcy c-sands. The higher the permeability, the larger the contribution is from that

section of the horizontal part into the annulus.

Annulus flow

Rock mechanics studies indicate that collapsed reservoir sand will not fill the annulus space and a high flow capacity in

annulus is maintained. NETool simulations indicate that high permeability sections may be produced also through ICD’s

located in neighboring lower permeability sections due to annulus flow. Installing swellable annulus packers at the main

borders of different permeability levels and using ICD’s, will result in different annulus pressures in sections between

packers. The positive effects will be a lower drawdown in sections with high permeability and higher drawdown in sections

with lower permeability. Since 2006 annular swell packers have been installed to reduce annular interaction between

production sections (typically 20 – 30 swell packers in each branch).

Remaining oil along the horizontal section

New infill branches are currently being drilled in between old producers with a distance down to 100 meters from old

branches. The main challenge is to quantify where along the horizontal section of historical wells the production have

SPE-159634-PP 5

occurred. Subsequently, how much oil is remaining along the horizontal section of new wells and how to install ICD

completion to optimize oil recovery with an uncertain and varying remaining oil column. Reservoir evaluations and

observations indicate remaining oil column typically in the range of 4 – 7 meters in infill wells at Troll.

The new autonomous inflow control device (AICD) developed by Statoil [9] will, in addition to delay the gas breakthrough,

reduce the consequences of the gas breakthrough. The AICD valve chokes the flow of low-viscous fluids and favours the

viscous fluid. With this technology the well performance and production can be higher after a gas breakthrough compared to

conventional inflow control.

The RCP valve

The static ICDs can be selected and installed with optimal inflow control properties at the beginning of the production life

time of the well, the properties of the well will change over time in a manner that is difficult or impossible to foresee. Since

the ICDs are static, there is no easy way to adjust the inflow performance after the initial installation. Hence, the drainage

characteristics that were correct and optimal during the first part of the production lifetime, becomes more and more off with

time as the well starts to mature. Another important drawback with a conventional fixed opening ICD is that this technology

has no ability to close off the internal flow area or flow opening in the event of water or gas breakthrough.

The described autonomous inflow control device is developed by Statoil, and is called the Rate Controlled Production (RCP)

valve. The technology is patented [10] in all relevant countries.

In Figure 4 an example of a well installation is shown. The fluids are flowing from the reservoir through the screen and then

into the inflow chamber where the RCP is installed. Typically, one RCP valve is installed at each screen joint but for certain

applications up to four valves may be installed at each joint.

In Figure 5, a picture of the RCP valve is shown, whereas a schematic sketch is given in Figure 6. The flow path is marked by

arrows. The outer diameter of the RCP valve is typically 80 mm and the valve consists of only one movable part, the free

floating disc. In Figure 6 the disc rests at the seat allowing maximum flow area for the passing fluid. The valve is

autonomous, i.e. the valve operates entirely without the need for human interventions and it does not require electric or

hydraulic power. The position of the disc depends on the fluid properties and the flow conditions. The performance of the

RCP valve is based on the Bernoulli principle. By neglegting elevation and compressible effects the Bernoulli equation can

be expressed as:

lossfriction

2

22

2

11 Δp ρv2

1 p ρv

2

1 p (1)

The equation states that the sum of the static pressure, the dynamic pressure and the frictional pressure losses along a

streamline is constant. This phenomenon is utilized in the RCP valve.

The RCP valve restricts the flow rate of low viscous fluids. When gas is flowing through the valve, the disc will move

towards the seats and reduce the flow area. The pressure will be lower at the flowing side of the disc (Bernoulli effect) due to

the large gas velocity (dynamic pressure). The higher pressure behind the disc will press it towards its seat, due to the

pressure difference between the two sides. Fluids with different viscosities will tend to follow different streamlines as

indicated in Figure 7. Hence the stagnation pressure in the stagnation zone will be much larger for gas flow compared to oil

flow. High stagnation pressure will give high pressure behind the disc and press it towards the seats and the valve will close.

This will reduce the flow area and the gas flow.

The situation with strong choking for gas flow is illustrated in Figure 8, where a cross section of the valve and the pressure

profile for the disc in closed position is presented. The pressure along the line AA’ is sketched. The pressure at point A

(centre of the disc) is the pressure on the reservoir side (not necessary equal to the reservoir pressure), PR. Between the inner

seat and the outer seat the pressure acting on the disc is the pressure on the well side or the back pressure, PB. At point A’ the

pressure is the stagnation pressure, PST. This stagnation pressure will act on the back side of the disk and the resulting force

will be in the opposite direction compared to the pressure acting on the disc from the reservoir side. When the valve close

there is a (metal) contact between the movable disc and the outer seat. It is very important to design the valve in a way that

ensures optimized gas choking. The seat to disc contact contributes to maintain the stagnation pressure in the stagnation

chamber, at least for a short time period, since a certain leakage takes place at this contact, which again results in a reduced

stagnation pressure. When the stagnation pressure decreases below a certain pressure (opening pressure) the force on the disc

6 SPE SPE-159634-PP

backside becomes too low and the valve opens. The time it takes for the stagnation pressure to decrease to the opening

pressure is equal to the opening/closing frequency of the valve.

In Figure 8 there are two pressure profiles sketched in the contact zone between the movable disc and the outer seat. The

green curve represents one extremity of the pressure profile, which occur when the sealing is nearest the centre on the inner

seat and nearest the stagnation point on the outer seat. The red curve represents the other extremity, where the seal is nearest

the outlet at both the inner and outer seat. By integrating the pressure profiles under the curves the pressure force is found.

The pressure is obviously most favourable for the red curve. To ensure this profile, cones at the inner and outer seat have

been included, thus optimizing the gas choking effect.

The more viscous the fluid becomes the higher the flow rate through the RCP valve. The friction loss increases and the

pressure recovery of the dynamic pressure decreases. The pressure on the rear side of the disc will decrease resulting in a

reduced force acting on the disc towards the inlet. Thus the disc moves away from inlet and the flow area and the flow rate

increases. As a result, heavier oils will flow through the valve with less rescistance compared to lighter oils [6]. A fixed

geometry device like a nozzle or an orifice will have an opposite behaviour.

Figure 4: Statoil’s RCP valve conneted to the base pipe in a sand screen joint in the well.

Inlet: From reservoir

Outlet: Into well Outlet: Into well disc

Inner

seat

Outer

seat

SPE-159634-PP 7

Figure 5: Statoil’s RCP valve Figure 6: Schematic sketch of Statoil’s RCP valve

8 SPE SPE-159634-PP

Figure 7: Sketch of the RCP-valve with typical streamlines.

Figure 8: Cross section of valve and pressure profile at disc in closed position.

PST

Inner

seat Outer

seat A A’

Movable disc

PR

PB

PR

PST

PB

Movable disc

SPE-159634-PP 9

Statoil’s RCP valve has been subjected to several tests and a full internal qualification programme. The narrow gap between

the seats and the free floating disc can represent a potential challenge with respect to sand erosion. If the expected conditions

in the well include significant sand production it might be necessary to reinforce the disc and the seats with an erosion

resistant material such as tungsten carbide. However, at Troll the conditions are favourable with respect to low sand

production and low drawdown from reservoir to well.

Field implementation of RCP valves at Troll

Troll has focused on developing and implementing inflow control devices that limits gas coning. So far three Troll wells have

been completed with RCP valves. The first RCP well was Troll Q-21 BYH. One of the objectives was to verify the valve

performance, which was determined through flow loop tests at Statoil’s Multiphase Test Facility in Porsgrunn.

A full scale laboratory test with realistic recombined fluids were carried out. Several experimental series with oil, gas and

water are performed to validate the performance of the RCP valve, see Figure 9. From the figure it is observed that the valve

throughput of water at constant pressure drop is slightly less that oil. Whereas the throughput of gas is less than 3 times the

throughput of oil for constant pressure drop. This is significantly less than for a fixed geometry orifice.

Based on the experimental data a function for the RCP has been developed. The functions for individual fluid phases are

shown in Figure 9. The RCP model has been implemented in the reservoir simulation tool Eclipse. The RCP model is a

general expression for differential pressure across the valve as a function of fluid properties and volume flow. The function is

expressed by:

x

AICD qafP , (2)

where f(ρ,μ) is an analytic function of the mixture density and viscosity, aAICD is a user-input 'strength' parameter, q is the

local volumetric mixture flow rate and x is a user input constant. RCP valves will have different design for different oil fields.

The model constants x and aAICD are dependent on the RCP design and the fluid properties. Based on the experimental data

the flow constant and calibration properties in the RCP model can be defined. Typically, the value for x varies between 3 and

4.

The function f(ρ, µ) is defined as:

y

mix

cal

cal

mixf

2

, (3)

where y is a user-input constant and ρcal and µcal are the calibration density and viscosity respectively.

The mixture density and viscosity are defined as:

gasgaswaterwateroiloilmix

gasgaswaterwateroiloilmix

(4)

where α is the volume fraction of the phase. The function is validated against several experimental data series performed with

different oils with a range of viscosities.

10 SPE SPE-159634-PP

RCP-G - Troll

0,0

2,0

4,0

6,0

8,0

10,0

12,0

14,0

16,0

18,0

20,0

0 200 400 600 800 1000 1200 1400

Fluid rate [Al/h]

Dif

fere

nti

al p

ressu

re [

bar]

Oil-Exp

Water-Exp

Gas-Exp

Oil - Function

Water - Function

Gas - Function

Figure 9: Experimental valve performance and curve-fit functions for reservoir simulation (Eclipse) input

Well Q-21

Q-21 BYH, see completion schematics presented in Figure 10, was completed with two long horizontal branches (2633 m

and 3242 m producing intervals) with a total of 436 RCP valves. Branch control valves were installed to allow for individual

well tests of the two branches and three downhole pressure and temperature gauges were installed to monitor the individual

branches and the commingled flow. A total of 30 annular swellable packers are installed in each horizontal producer to

sectioning the annulus in the reservoir.

The pressure drop between the reservoir and the tubing will be equal to the pressure drop across the formation plus the

pressure drop across the RCP valves. In a simplified approach the pressure drop across the RCP valves (PRCP) will therefore

be determined based on the measured downhole pressure (Pgauge), estimated reservoir pressure (Pres), liquid rate and

productivity index (PI) for the branch.

)()()( ReRe kPI

QPPPPPP

liquid

gaugesfmgaugesRCP

k is additional pressure drop across formation related to gas breakthrough. k is unknown and is set equal to zero in the

simplified calculations. The frictional pressure drop between top screen and pressure gauge is assumed negligible compared

to the pressure drop across the RCP valves.

Based on the open hole logs the productivity index is significantly higher in branch Y2H compared to Y1H and the

productivity is expected to be at least 4000 Sm3/d/bar for branch BY2H. The best approach is to evaluate the valve

characteristics based on the branch BY2H since the uncertainty in the DP across the formation will have least impact in the

calculated DP across the RCP completion.

SPE-159634-PP 11

Troll Olje 31/3-Q-21

Abandonment Status

1 of 1 SHEET

REV 0

DRAWNT. Elseth

DATE15 Sept 2008

SIZEA4

CompletionDHSV @ 419 mMD

20” Csg Shoe @ 709 mMD / 706,8 mTVD

10 3/4” Liner Hanger @ 1369 mMD

13 3/8” Csg Shoe @ 1558 mMD / 1389,7 mTVD

SLB XMP-CR Production Packer @ 1687 mMD

Schlumberger XMP-CR Isolation Packer @ 1948 mMD

BOT HMP GLV @ 1761 mMD

Excluder Screen(Gas inlet) @ 1785 mMD

SMG and perf: 1811 - 1840 mMD

BOT HCM-A@ 2048 mMD

9 5/8” x 10 3/4” XO

7” tubing

9 5/8” Csg Shoe @ 2308 mMD / 1575,1 mTVD

5 1/2” - 4 1/2” XO

4 1/2” - 3 1/2” XO3 1/2” - 4 1/2” XO

7” - 5 1/2” XO

2 x 12 mm holes in 10 3/4” csg

30” Conductor @ 439 mMD

BY2H TD @ 6060 mMD / 1553,6 mTVDScreen @ 5869,6 mMD

BOT S-HCM-A@ 2063 mMD

+

Double float & perf pup jnt

Double float & perf pup jnt

Screen with tracers3441 & 4192 mMD

Pup jnt with tracer6322 mMD

Screen with tracers3802,6 & 5210,5 mMD

Pup jnt with tracer5744,1 mMD

Roxardual gauge

Roxarsinglegauge

Roxar dual gauge @ 2073 mMD

Figure 10: Troll Q21 BYH Well completion

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

Dif

fere

nti

al p

ress

ure

(B

ar)

Date

Q-21 BYH DP across RCP completion

Drawdown formation

Figure 11: Pressure difference between the estimated reservoir pressure and the measured tubing pressure in BY2H

12 SPE SPE-159634-PP

The reservoir in the area of Q-21 BY2H is depleted by 2.7 bar pr year. In addition the downhole pressure gauge in BY2H

provides shut-in pressures every time the branch is closed. Due to the high permeable sands in the Troll reservoir, the shut-in

pressure equals the reservoir pressure quite soon after shut-in.

The pressure differences between the estimated reservoir pressure and the measured tubing pressure in BY2H is shown in

Figure 11. The pressure differences are splitted into DP across completion (RCP valves) and the drawdown of the formation.

The drawdown of the formation is calculated based on an estimated liquid productivity of 4000Sm3/d/bar for BY2H and is

small compared to the DP across completion.

The following simplified approach has been selected to evaluate the valve characteristics:

Minimum number of gas filled RCP valves:

)/()(.#

gasFVFyGasCapacit

eGasFlowRatGasRCPMin

Minimum number of liquid filled RCP valves:

)/()/()(.#

oilwater FVFyOilCapacit

eOilFlowRat

FVFityWaterCapac

ateWaterFlowRLiquidRCPMin

Gas Flow is the measured or allocated gas flow rate at downhole conditions. Oil and water flow rate is the measured or

allocated flow rates at downhole conditions. RCP gas capacity and liquid capacity is found from the RCP valve

characteristics for gas, oil and water and the estimated DP across the RCP completion.

The minimum number of fluid filled RCP valves should be lower than the actual number of RCP valves installed in the

branch.

BY2H (N6 Sognefjord)

0

50

100

150

200

250

300

Nov

-08

Dec

-08

Feb-0

9

Apr-0

9

May

-09

Jul-0

9

Sep-0

9

Oct

-09

Dec

-09

Date

# R

CP

Sum

Liquid

Gas

215 (RCPs in BY2H)

Figure 12: Field verification of valve performance

SPE-159634-PP 13

Well tests are shown as triangles while lines are based on allocated rates. The calculations above indicate that it is possible to

produce the measured/allocated flow rates through the completion assuming that the RCP valves have a flow characteristics

as found from the experimental tests in Statoil Multiphase Test Facility in Porsgrunn.

It is verified that the valve characteristics can be according to the charcteristics obtained from the flow loop test. It is also

seen that we are producing from all parts of the completed branch. This is also verified by chemical tracers in the heel,

middle and toe sections of the branches.

Based on the available measurements and production history, it can not be concluded that the oil production in Q-21 BYH

was better than it would have been without the RCP valves. The water cut and GOR was high and this is most probably due

to reservoir quality and thin oil column in the area.

Well P-13

The next step was to verify that a RCP completed branch is better than a conventional branch with ICD. The approach was to

identify a planned two branch well with parallel branches through the same reservoir sands. P-13 BYH was selected as a

good candidate. The well paths are shown in Figure 13. The average distance between the branches is 191 meters. The high

permeable c-sands are shown in colors with the lower permeable m-sands in between in white.

Figure 13: Troll P-13 BYH well paths

The GOR development in the two branches are different, see Figure 14 and Figure 15, and it is likely that this is due to the

installation of RCP valves in BY2H. The RCP valves are evening out the inflow along the horizontal producer in a way that

are delaying the gas breakthrough and the RCP valves are restricting the production from zones with higher GOR compared

to other zones in the RCP branch.

14 SPE SPE-159634-PP

Figure 14: Troll P-13 BYH – Gas oil ratio development as function of production time

0

200

400

600

800

1000

1200

1400

1600

GO

R (

Sm3 /

Sm3 )

Cumulative oil (Sm3)

P-13 BYH - GOR vs Cumulative oil

Y2

Y1

Y1 choked to 27%

Y1 choked to 27%

Figure 15: Troll P-13 BYH – Gas oil ratio development as function of cumulative oil production

It is observed that there is a significant and increasing gas breakthrough in branch BY1H while there is a moderate GOR

increase in the BY2H, the branch completed with RCP valves. The liquid production from each branch is in the same order of

magnitude and is not causing the extra GOR increase in BY1H. In april 2012 the GOR in well branch BY1H is

approximately three times the GOR in well branch BY2H. Examination of the cumulative oil production show that branch

BY2H has produced approximately 20% more oil than branch BY1H.

SPE-159634-PP 15

Well P-21

Based on the results of Q-21 BYH and the initial production history of P-13 BYH, it was decided to install RCP valves in the

well P-21 BYH. The RCP valves are installed to increase oil recovery in the area and the well was planned and completed in

the same way we expect future RCP wells to be completed. Production history and especially oil production is the focus in

evaluating the performance of this well.

The development of the oil rate and the gas oil ratio are presented in Figure 16. The P-21 BYH oil production is high

compared to other recent Troll wells and currently P-21 BYH is the best producer at Troll C. The oil production has been

maintained at a high level for a significantly longer time than is normally seen in Troll wells.

0

100

200

300

400

500

600

700

800

900

1000

0

500

1000

1500

2000

2500

6.6.2011 26.7.2011 14.9.2011 3.11.2011 23.12.2011 11.2.2012 1.4.2012 21.5.2012 10.7.2012

Gas

Oil

Rat

io (

Sm3

/Sm

3)

Oil

flo

w r

ate

(Sm

3/d

)

Date

P-21 BYHOil rate GOR

Figure 16: Troll P-21 BYH – Development of oil rate and gas oil ratio

The GOR development in P-21 is moderate. Other Troll wells with a slow GOR increase will typically experience an increase

in water cut which results in a decline in oil flow rate. The P-21 BYH show an abnormal production history in a positive way.

After 10 months of production the well P-21 has produced the same cumulative oil as a typical Troll well is expected to

produce during its entire lifetime.

Based on the production history of the first three RCP wells, it has been decided to continue the implementation of RCP

valves in Troll wells. The combination of long horizontal wells drilled along the oil/water contact, autonomous inflow control

devices (RCP valves), annulus swell packers, branch control and down hole pressure gauges are considered to be a robust and

efficient design for IOR wells at Troll.

16 SPE SPE-159634-PP

Reservoir simulations

The RCP valves are implemented in Eclipse reservoir simulations using a multi-segmented well with one branch for each

inflow control device. The pressure drop in the segments on these branches are modeled with the WSEGAICD keyword,

which uses the equation and parameters derived from RCP test results.

Jun.2

01

1

Jul.201

1

Aug.2

011

Sep.2

011

Oct.20

11

No

v.2

011

De

c.2

011

Jan.2

01

2

Feb

.201

2

Ma

r.201

2

Apr.

20

12

Ma

y.2

01

2

Jun.2

01

2

Jul.201

2

Aug.2

012

Sep.2

012

Oct.20

12

Pro

du

cti

on

ICD simulation RCP simulation Allocated production

Figure 17: Simulated and allocated production for P-21 BYH

Figure 17 shows a comparison of cumulative oil production for P-21 BYH. Simulation results, prior to drilling the well,

indicates that a completion with RCP has higher oil production than 3.2 bar ICDs previously installed at Troll field.

Allocated production to date is in line and above the simulated RCP production.

Simulation studies for new wells indicate increased oil production in the order of 0-15 % compared to a 3.2 bar ICD

completion. The simulated 3.2bar ICD case is not necessarily an optimized nozzle or ICD design.

Conclusions

This paper highlights production experiences with new inflow technology tested at the Troll field.

Statoil’s autonomous inflow control technology, the RCP valve, has been evaluated through extensive testing in a multiphase

flow laboratory. Valve performance for individual fluid phases (oil, gas and water) as well as two and three-phase mixtures at

realistic reservoir conditions has been obtained. The valve characteristics are implemented into the reservoir simulator.

Reservoir simulations carried out prior to installation showed improved oil recovery using RCP valves compared to other

inflow control devices. Reservoir simulations indicates an increased oil production up to 15% by selecting the optimum RCP

valve completion.

RCP valves have been successfully tested and implemented in three wells at the Troll field; Q-21, P-13 and P-21. The RCP

valve performance has been verified by field testing and the valves have been in operation in well Q-21 without any failure

since November 2008.

The production experiences from the branch completed with RCP valves in P-13 and in addition from the well P-21with

RCP in both branches, are very encouraging. As of April 2012, after almost 1,5 years of production, the GOR in the branch

completed with RCP valves is 1/3 of the GOR in the branch completed with ICD’s. The cumulative oil production is

approximately 20% higher in the branch completed with RCP valves. The wells completed with RCP valves are producing at

a high oil rate for a longer period of time prior to gas breakthrough compared to typical Troll wells, and are thereafter

SPE-159634-PP 17

producing at a lower GOR compared to other Troll wells. Prognosed oil volumes are produced in less time than expected and

it is anticipated that the wells will continue to produce at lower GOR and improve oil recovery from the area.

Completion with inflow control must be carefully designed from a case by case evaluation. The RCP valve completion must

provide a certain liquid rate capacity, bottom hole pressure must be kept above a minimum level to avoid lifting problems

and robust zonal and annulus isolation must be in place.

Acknowledgements

The authors are grateful to the Troll license partners Petoro, Shell, Total, ConocoPhillips and Statoil, for allowing this work

to be published.

References [1] Dimitrios Krinis, Drew Hembling, Naseem Al-Dawood, and Sadiq Al-Qatari Saudi Aramco; Sam Simonian and

Giovanni Salerno FloTech LTD.; “Optimizing Horizontal Well Performance in Non-Uniform Pressure

Environments Using Passive Inflow Control” OTC Houston, Tx. May 2009

[2] Crow, S.L, Coronado, M.P and Mody, R.K, Baker Oil Tools Means for Passive Inflow Control Upon Gas

Breakthrough, SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 24-27 September 2006

[3] Alkhelaiwi, F.T, Heriot-Watt University and Saudi Aramco and Davies, D.R, Heriot-Watt University Inflow Control

Devices: Application and Value Quantification of a Developing Technology, International Conference and

Exhibition, Mexico, 27-30 Juni 2007

[4] Fernandes, P., Z. Li, and Zhu, D. Understanding the Roles of Inflow-Control Devices in Optimizing Horizontal-

Well Performance, in SPE Annual Technical Conference and Exhibition. 2009: New Orleans, Louisiana

[5] J. Kr. Mikkelsen, T. Norheim and S. I. Sagatun, SPE, Norsk Hydro ASA; “The Troll Story” OTC 17108, Houston,

Tx. May 2005

[6] T. Madsen and M. Abtahi, Norsk Hydro ASA; “Handling the Oil Zone on Troll” OTC 17109, Houston, Tx. May

2005

[7] Jan Hauge and Terje Horn, Norsk Hydro ASA; “The Challenge of Operating and Maintaining 115 Subsea Wells on

the Troll Field” OTC 17111, Houston, Tx. May 2005

[8] K.H. Henriksen, SPE, Baker Oil Tools; E.I. Gule, SPE, Hydro ASA; and J. Augustine, SPE, Baker Oil Tools ” Case

Study:The Application of Inflow Control Devices in the Troll Oil Field” SPE Europec/EAGE Annual Conference

and Exhibition held in Vienna, Austria, 12–15 June 2006.

[9] Mathiesen V., Aakre H., and Elseth G. The autonomous RCP Valve - New Technology for Inflow Control In

Horizontal Wells SPE-145737, Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, UK 6-8

September 2011

[10] Aakre, H and Mathiesen, V., (2006), Methods for Flow Control and Autonomous Valve or Flow Control Device,

WO 2008/004875 A1