20 Re-evaluation of Scale Strategy in a Maturing Field- Gigi a Sand

8/18/2019 20 Re-evaluation of Scale Strategy in a Maturing Field- Gigi a Sand

1/15

1

Re-evaluation of the Scale Management Strategy in a maturing fieldGigi Alexandra Sand, Øystein Sæther, Anne Silset.

AbstractThis paper describes the re-evaluation of the current Scale Management Strategy in the Kristin Field.The approach is taken in order to re-evaluate, update and optimize the scale strategy. This iswarranted due to challenges and risks observed in some of the wells that are treated, and in order tooperate with the necessary number of annual scale treatments.

The Kristin field is a high pressure and high temperature condensate field at an initial reservoir pressure of 911 bar and a reservoir temperature of 170 C. Kristin was developed as subsea fieldwith four subsea templates tied back to the Kristin semi-submersible production platform processingfacility through six 6 km long production pipelines. The drainage strategy is by pressure depletion

from twelve producers covering three reservoir zones, namely Garn, Ile and Tofte. The field is at thetail end of production. The pressure has been depleted in some areas by as much as 650 bar. The pressure and rate decline has challenged the operator to re-evaluate the scale management strategy aswas proposed in the planning and development phase of the field.

During the planning and development phase, MultiScale simulations showed a high potential forcalcium carbonate scale (CaCO 3) in the wells with formation water production. Halite (NaCl)

precipitation was not expected to be a major problem in the wells even though the salinity in theKristin formation water is relatively high. Extensive studies of the scale potential led to theinstallation of a purpose built chemical storage and injection unit on Kristin Semi. Dedicatedchemical injection lines are linked to the templates, without the need of boat interventions. Theinitial scale management strategy suggests a treatment frequency of as many as ten operations peryear.

Lately, concerns have been raised to the benefits and disadvantages of the frequency of scale relatedoperations. At the current reduced pressure and rate the wells are more challenging to start up aftertreatments, the productivity is sometimes slightly impaired after treatment and the placement of thescale treatment chemicals can be challenging. Therefore, the scale potential in the Kristin wells has

been re-evaluated and balanced with the risks that scale operations impose, including the costreductions in limiting the scale mitigation program.

Introduction

The Kristin field is located in the Haltenbanken basin at approximately 240 km west of the Mid- Norwegian coast. The water depth is in the range of 340-380 m. The field was developed as a subseafield with Kristin Semi, as the processing facility, see Figure 1 . These four templates are located ataround 6 to7 km from the Kristin Semi, from which the gas is produced back to the process atKristin Semi through six production pipelines. The drainage strategy is pressure depletion from threegas bearing Jurassic sandstone formations: Garn, Ile, and Tofte. Production started in 2005. The fieldis now at the tail end of production, however further increase of the production potential has beenachieved by the recent implementation of low pressure production (LPP). The purpose of LPP is toreduce the separator pressure and the vertical lift requirement to boost the production rate and

prolong production from the depleting reservoir. This is achieved by installing a recompression stage


2/15

2

into the process downstream separation, to accommodate the pressure requirement of the exportsystem.

Throughout the planning and development of the Kristin field some of the main productionchallenges that were highlighted were calcium carbonate (CaCO 3) scale formation and sand

production. In response to the identified significant scale risk a purpose built chemical storage andinjection unit was installed on the Kristin Semi, with dedicated service lines for displacement ofmitigating chemicals to the exposed wells. This system and the process of chemical selection fortreatment of wells at HPHT conditions have been described previously ( R.Wat et al, 2008 ).

The ionic composition of the formation water does not vary significantly between the differentformations; see Table 1 . The barium content is rather high and the sulphate content very low, andthere is a high level of calcium present.

Table 1 – Ion composition of the formation water at Kristin, Exploration well 6406/2-5

Parameter Unit Garn Fm. Ile Fm. Tofte Fm.Sodium mg/l 27900 33900 32900Calcium mg/l 2536 2554 2215Magnesium mg/l 50 111 114Barium mg/l 1189 1618 1937Iron mg/l n.d. 3 0Strontium mg/l 442 534 551Potassium mg/l 1544 2096 2290Chloride mg/l 48200 56600 58200Sulphate mg/l n.d. n.d. 0Bicarbonate mg/l 857 975 686

Tot. dissolved solids mg/l 82718 98391 98893Specific gravity g/cc 1.056 1.063 1.068pH Ph 7,5 6,6 6,4

The hydrocarbon phase is a gas/condensate with CO 2 content initially ranging between 3.3 and 3.7mole%. The reservoir properties vary between formations. For the wells considered in this paper, themean permeabilities are low in Garn and higher in Ile and Tofte.

The completion in the Kristin wells is generally of two types. The wells located at the S-template arecompleted with stand-alone sand screens; the rest of the wells have been completed with cementedand perforated liners. Downhole pressure and temperature gauges were installed in the initial Kristinwells but have malfunctioned due to the challenges relating to high temperatures.

The downhole pressure and temperature is calculated on the basis of thermo-hydraulic models andrelated to the reservoir model. For the MultiScale simulations carried out the downhole inflowallocation is based on the reservoir model. The wells are produced towards an inlet and/or to a testseparator allowing for flexibility for testing and water sampling when required. Generally wellsshare production lines, and some low-rate wells are deduction tested to meet the flow requirementsof the test separator.


3/15

3

Figure 1 – Kristin Subsea Layout.

Scale in Kristin

Kristin wells were to be developed as dedicated Garn or Ile producers or commingled producers(Garn Fm. and Ile Fm.) in the north of the field. If reserves were proven in the Tofte Fm. then adedicated Tofte producer was also intended. Reservoir simulation indicated that the commingledwells would be the most prone for formation water production, dominantly from the Ile Fm.Breakthrough of formation water was simulated to take place after 1 to 3 years in the commingled

producers. An initial strategy was derived from this in which once formation water was detected inthe commingled wells the Ile Fm. could be plugged back in order to shut-off this water contributingzone.

In the field development phase scale simulations indicated that the worst scaling potential could beexpected in the commingled producers. The dedicated Garn Fm. producers were not expected to

produce water. Some formation water production was eventually to be expected in the Ile Fm. producers after 7-10 years of production and ~1.5 years after breakthrough the wells would be closedin. The initial scale mitigation strategy, in accordance with the inherently high potential for CaCO 3 formation, was to carry out two treatments per year in all water producing wells, or more if dictated

by the well response (productivity reduction, valve operability problems, etc.). Chemicals for one job should be ready at the land base for mobilisation, and pumping programs and practicalarrangements were to be in place for scale dissolver/squeeze operations on short notice. Further,arrangements for continuous scale inhibitor injection in all well christmas trees were implemented to

prevent formation of CaCO 3 in flowlines and risers, to be activated upon identification of a scalerisk. The location of the injection point for continuous inhibitor injection provides protection of the

production wing valve (PWV), the subsea choke and further downstream (see Figure 2 ).


4/15

4

Figure 2 – Simplified christmas tree overview.

A challenge identified concerning inhibitor squeezing is the controlled placement of the squeeze in

the commingled wells and in the target formation, since there is no permanent arrangement forcontrol of the outflow during a pumping sequence. One practical example was an intervention on thecommingled Garn/Ile producer P-3 H. The objective of the intervention was to shut-off water

production by installing a plug above the water producing zone in the Ile Fm. Challenges wereforeseen in this well relating to high inclination (70° well angle) and the high temperature. Tractorswere required and the high temperature caused telemetry problems in the equipment. Due to theconveyance risks associated with low clearance between the outer diameter of the plug and the innerdiameter of the liner, a dissolver operation had been performed weeks prior to the wirelineintervention in order to remove any possible scale restrictions in the tubing/liner. After the scaledissolver pump job a multi-finger caliper tool was run and a small scale bridge was seen above the

producing zone in the Garn Fm. This confirmed the difficulty of the placement of the dissolver, and

optimising treatment is often a challenge in a commingled well. Table 2 shows a summary of scale dissolver (SD) and scale inhibitor (SI) squeeze operations in thewells further discussed in this paper.


5/15

5

Table 2 – Overview of SD & SI treatments in Kristin

TreatmentNo.

P-2 H P-3 H S-4 H

DateType

treatment DateType

treatment DateType

treatment1 Aug.07 SD/SI Sep.07 SD/SI Sep.09 SD/SI2 Jul.08 SD/SI Jan.08 SD/SI Feb.10 SD/SI3 Mar.09 SD/SI Apr.08 SD/SI Jun.10 SD/SI4 Oct.09 SD/SI Jul.08 SD/SI Nov.10 SD/SI5 Feb.10 SD/SI Dec.08 SD/SI Jun.11 SD/SI6 Apr.11 SD/SI Apr.09 SD/SI Dec.11 SD/SI7 Mar.12 SD/SI Sep.09 SD/SI Jun.12 SD/SI8 Jun.13 SI Dec. 09 SD/SI Dec.12 SD/SI9 Nov.13 SD Jun. 10 SD/SI May.13 SD/SI

10 Nov. 10 SD/SI Jan.14 SD/SI11 Jul. 11 SD/SI Jan.15 SD/SI12 Jan. 12 SD/SI13 Jul.12 SD/SI14 Jan. 13 SD/SI15 Jul.13 SD16 Mar.13 SD/SI

In 2007 formation water breakthrough was detected on the first two commingled wells, P-2 H andP-3 H. Since then some wells have been observed to produce formation water at various rates, whilewater breakthrough has not been detected in the majority of wells in Kristin. At the subsea templatesthe streams from the different wells meet at the template manifold and there is a mixing of wellstreams with and without formation water. The topic of mixing of such flow at the template manifoldwill not be discussed here, although it can be assumed that at current production conditions the

mixture can be considered to be favourable with respect to scale risk in the production flowline. Thenon-formation water bearing well streams provide a net access to condensed water, diluting themixture ionic composition.

Scale simulations performed in the Kristin development phase indicated that there was not expectedto be a potential for precipitation of NaCl at low water cuts. However in practice, halite formationwas experienced in well S-1 H ( Wat et al, 2010) . It was found that salt deposited as the low-rateformation water influx evaporated into the under-saturated (heated) gas phase. The current pressurein the reservoir body surrounding the producer wells is generally depleted below the point whereJoule-Thomson heating is expected, although there are still wells for which this pressure is reachedduring inflow. These wells however exhibit higher formation water rates and are less susceptible to

significant dry-out. Calculations indicate that only small formation water inflow rates can carry arisk for halite formation since at higher rates the loss of water to evaporation does not increase theionic concentrations to saturation. Halite formation is no longer considered a major risk and thisincludes the well in which halite was previously observed.

The focus is thus on the potential for calcium carbonate formation, which has also been the mainfocus of mitigation efforts for several years. Since early production the reservoir pressure in all

producing segments has dropped, as no pressure support by injection is employed. This implies thatthe total pressure drop from reservoir to separator has also dropped over the course of the productionhistory. As will be shown below, high local pressure drop is related to increased potential for CaCO 3 formation, and by extrapolation it can be assumed that there is a possibility for reducing overall

precipitation potential with depletion – when only the pressure development is considered. It is also


6/15

6

evident from the results presented below, the high inherent temperature of inflow and well streamsand the local pressure drops even at depleted pressure remain efficient driving factors for calciumcarbonate formation.

Field experience (e.g. by analysis of flowback spent dissolver solution) has shown that even a low

oversaturation can cause precipitation at temperatures as high as in the Kristin reservoirs. From thisit can be deduced that even a moderate pressure drop through the near wellbore area can result incalcium carbonate formation, in particular for low rate water influx. The temperature profile throughthe near wellbore area is thus quite important, as a slight cooling may bring the saturation ratio (SR)

below 1, while a sustained temperature will bring SR>1.

There is a challenge in that there are no working downhole pressure/temperature sensors in the wells,and thus the values used in simulations depend on data calculated from thermo-hydraulic modelscorrelated to the reservoir model. Ultimately, assumptions have to be made concerning thedrawdown pressure and in particular the bottom hole temperature. This brings a level of uncertaintyinto the calculations, in view of the sensitive solution/precipitation balance imposed by the high in

situ temperature.The rate of inflowing formation water is obviously important in several respects. High rates correlateto high potential mass of calcium carbonate that can precipitate when there is oversaturation. Lowrates correspond to a risk of quantitative dry-out in less depleted stages of production and increasingionic concentrations through evaporation upon depressurization in general.

In simulations, Joule-Thomson (JT) heating can be seen to increase the temperature and water-absorbing ability of the hydrocarbon gas phase – when above a certain pressure over which JTheating can take place. As stated, this effect was mainly a factor of greater importance in the pastdue to the current degree of depletion. When applying a relatively low formation water inflow rate atsuch conditions, it has been found that the heated hydrocarbon gas phase strips a considerablefraction of, or entirely, the water from the formation water stream, resulting in precipitation of firstrelatively low soluble salts and later also remaining ions in various salts. The relevance is primarilythat when there is emerging formation water breakthrough in a well (i.e., low sustained rate) andthere is a capacity for JT heating during inflow, even high-solubility salts may precipitate. Atconditions not exposed to JT heating, i.e. at sufficient depletion, evaporation of water may stillincrease the ionic concentrations to saturation for the less soluble salts (such as CaCO 3), in particularwhen the formation water flow rate is low.

In the current scale simulations the hydrocarbon is actively saturated with pure water prior to inflow(i.e., at reservoir conditions, and assuming water saturation to equilibrium). This has two effects:

Heating is required to increase the hydrocarbon capacity to assimilate more water from theformation water; Precipitation of condensed water may dilute a co-flowing formation water stream and thus

reduce the SR.

In the case of the Kristin field the following observations have been made through simulation, thatfor some wells: The amount of water available for condensation is a function of the typical hydrocarbon flow

rates and usually not high when compared to common formation water rates; Thus, the dilution of formation water by condensing water is limited, and only reduces the SR

significantly when formation water rates are low.


7/15

7

It has been observed in other fields that the condensation of water has significantly diluted theformation water stream in areas of a well which would otherwise be exposed to scale formation if nodilution took place. Kristin wells P-3 H and S-4 H are examples of little effect of dilution, while inP-2 H condensing water efficiently reduces the ionic concentrations and the saturation ratio in thetubing.

Current calcium carbonate scale simulations

As will be shown in the following, although there has been a change in conditions, in particular thatrelated to reservoir depletion, the fundamental factors resulting in a calcium carbonate precipitation

potential are still in place:1. High temperature through the wells,2. High (sufficient) pressure drop from reservoir to wellhead, and most commonly3. Low effect of dilution by condensed water.

There is the issue of pressure drop across the subsea choke valve. This is particularly the case inS-4 H, where the well is heavily choked due to sand production and the pressure drop across thechoke is relevant when considering the scale risk. As stated above, the temperature remains high,even downstream the choke. This implies that some wells will have a higher scale potential acrossthe choke than just upstream, at the well head.

In this paper, three wells are presented, spanning different production characteristics, with varioushydrocarbon and water rates and different pressure drops through the near wellbore area and acrossthe choke. Error! Reference source not found.

Table 3 - Drawdown and pressure drop ( p) across the subsea choke.

S-4 H 2012 2014 2014 LPPDrawdown (bar) 14.2 12 10

p choke (bar) 126 111 132P-3 H 2012 2014 2014 LPPDrawdown (bar) 26* 48/20 * 73/45 *

p choke (bar) 3.6 3 10P-2 H 2012 2014 2014 LPPDrawdown (bar) 170/30 * 175/50 * 174/32 *

p choke (bar) 1.3 0.1 4.6*Two values are given indicating two-zone inflow from different reservoir pressure to a common BHP.

Table 4 - Rate and pressure development in S-4 H.

Rate 2012 2014 2014 LPPQo (Sm 3/d) 403 217 296

Qg (Sm 3/d) 610627 504000 425648

Qw (Sm 3/d) 1811 1538 1450

WHP (bar) 238 222 221

PDC (bar) 111 110 89


8/15

8

Table 5 - Rate and pressure development in P-3 H.

Rate 2012 Garn 2014 Garn 2014 LPP Garn 2012 Ile 2014 Ile 2014 LPP IleQo (Sm 3/d) 78.4 33.2 86.4 69.6 29.5 76.6Qg (Sm 3/d) 95304 39440 87836 107471 44475 99050

Qw (Sm 3/d) 26.8 33.2 30.4 1313 1627 1123WHP (bar) 91 95 78 91 95 78PDC (bar) 87 92 68 87 92 68

Table 6 - Rate and pressure development in P-2 H.

Rate 2012 Garn 2014 Garn 2014 LPP Garn 2012 Ile 2014 Ile 2014 LPP IleQo (Sm 3/d) 325 328 262 81 82 65Qg (Sm 3/d) 474690 420800 403477 118670 105200 100869Qw (Sm 3/d) 43.1 24.4 17.8 48.6 27.6 20.1WHP (bar) 84 94 60 84 94 60PDC (bar) 83 94 55 83 94 55

Calculation of the current scale potential

To explore the current calcium carbonate scale potential simulations have been performed withMultiScale 8.0. It is of particular interest to evaluate whether the start of low-pressure production in

2014 has changed the scale potential significantly. A second objective has been to identify any basisfor adjustments to the scale mitigation strategy.

The input data varies in terms of reliability. Total well rates are generated by well testing and may beconsidered as reasonably reliable. The well head and subsea choke pressure and temperature aremeasured by standard and reliable sensors. The zonal contribution for a Garn/Ile well is notmeasured, but rather reflects assumptions of the reservoir model concerning the distribution ofinflow and must be considered as a significant uncertainty. The reservoir pressure used is defined asa “local pressure” and will vary more than the pressure further away from the well. For the purposeof the current scale simulations there is assumed to be a common bottom hole pressure for bothzones in two-zone wells, which is a simplification that enables collection of the individual zone

streams in a common bottom hole node.

The hydrocarbon and formation water compositions are from exploration wells, however, someconsideration has been given to the possibility of compositional change over time. Work is ongoingto apply complete topside sample sets (oil, gas, water) to calculate compositions of single wellstreams. This will not be discussed here, however, the current composition of the S-4 H well (asdetermined by full characterization of all test separator exit streams) has been used in parallelsimulations with the original exploration well PVT analysis and it has been found that there is agood match between the two – both in terms of the production rates that are achieved at separatorconditions and the scale potential which is calculated with use of the two hydrocarbon compositions.


9/15

9

In the following section the results of simulations are presented and discussed for wells S-4 H, P-3 Hand P-2 H. The saturation ratios and related mass rates (i.e. the mass equivalent to the salt that must

precipitate to restore equilibrium, in kg/d CaCO 3) are calculated on the conservative basis of no lossof ions due to precipitation in the previous calculation node. This may result in over-prediction ofsaturation ratios at subsequent nodes, but still serves as a good indicator of the main trends. The

estimation of mass precipitation potentials should be considered as uncertain and indicative only.

Figure 3 explains the notation used in subsequent figures - the main calculation nodes and thecalculated SR with associated mass potential in the wells examined.

The lower right hand node “SR=1” signifies the alkalinity equilibrium between rock, water andhydrocarbon instilled through long contact between calcite minerals, the ionic water andhydrocarbon containing CO2, and implies that the water is saturated in terms of calciumcarbonate at the local conditions.

The next node represents the saturation at bottom hole (BH) conditions, which originate from thereservoir model and are regularly confirmed by thermo-hydraulic simulation. In the two P-wells,the inflow of each zone is calculated from their respective reservoir conditions to a commonBHP, and a saturation ratio is calculated as the inflow endpoint for both streams. At theseconditions the two streams are mixed and a new saturation ratio is calculated for the mixture atsame conditions.

The third node is at the well head, for which pressure and temperature is measured.

The fourth node is downstream of the subsea well choke. The drop in pressure between the wellhead pressure and upstream of the choke has been seen to be minimal. The primary interestrelating to this node is when choking is applied and a more significant pressure drop results.

Figure 3 – Description of nodes.


10/15

10

S-4 H

S-4 H is a one-zone well, with contribution from the Tofte Fm. The formation water rate is high inKristin terms and has been reasonably constant for all years simulated here.

Figure 4 - Development in the scale potential in S-4 H from 2012 to 2014 and to low-pressure production.

The drawdown is 10+ bar and drops slowly from 2012 to 2014, reflected in a modest SR at BHconditions of 1.05 in 2012 to 1.03 in 2014 after low pressure production has started. Notably, themajority of the effect of reduced separator pressure is countered by increased choking, as sand

production risk restricts the available drawdown. Whether an SR value of the order 1.02 to 1.05will result in scale formation depends on the kinetics of precipitation. Due to the very high fluidtemperature, kinetics can be expected to be fast, and precipitation cannot be ruled out.

The WHP reduces slightly from 2012 to 2014, and combined with a lower formation water ratethe SR also drops somewhat, from 1.7 to 1.5. This level is, however, sufficient to cause CaCO 3

precipitation at significant mass rates of about 100 kg/d. The potential increases from the bottomhole towards the well head.

The pressure drop across the choke decreases from 2012 to 2014 as the reservoir pressure falls,then increases significantly upon start of low pressure production. This is reflected in a slight SRincrease, but the SR and mass precipitation potential is high during all years due to the sustainedchoking.

In summary, although there may be some uncertainty as to the location of the onset of CaCO 3 precipitation/deposition it is clear that the production tubing and downstream flowline requireefficient inhibition. Thus, mitigation by scale inhibitor squeezing is maintained. The inclusion ofa scale dissolver pre-treatment is evaluated during planning of each operation. Injection ofadditional scale inhibitor at the well head may also assist in protection downstream of the well,in particular towards the end of squeeze lifetime.


11/15

11

P-3 H

P-3 H has two-zone inflow from Garn and Ile Fms. These are different in properties, which is at least partly reflected in the difference in pressure development and drawdown. The formation water rate islow and largely stable in the Garn zone, whilst higher and more variable in the Ile zone.

Figure 5 - Development in the scale potential in P-3 H from 2012 to 2014 and to low-pressure production.

The drawdown varies between 26 and 73 bar from 2012 to 2014 low pressure production (Garnzone), which in turn is reflected in the SR at the bottom hole node. The SR in the Garn zoneincreases from 1.1 to 1.3, but a modest rate of precipitation of less than 1 kg/d is due to the lowformation water rate. In Ile the formation water is undersaturated until the start of low pressure

production and the related drawdown increase. The reason for undersaturation is an assumptionrelating to cooling under bottom hole conditions. This is an uncertainty, and the SR can reach 1.2upon entering the completion if no cooling actually takes place. This corresponds to of the orderof 10 kg/d of calcium carbonate precipitation at this point.

Due to the assumption regarding the temperature at bottom hole conditions, the mixture is alsoundersaturated, until a small oversaturation (1.02) is seen with 2014 LPP and increase indrawdown. The mass rate is of the order 4 kg/d.

The potential increases through the tubing and at the wellhead the SR varies from 1.4 to 2 with amass rate of the range 50 to 90 kg/d. As there is little choking, the SR and mass rates across thechoke are similar to those at the well head.

In summary, the P-3 H well is exposed to CaCO 3 precipitation from the near wellbore area to thetemplate manifold, and requires sustained inhibition by scale squeezing. The use of scaledissolver pre-treatment is also considered in planning of operations.


12/15

12

P-2 H

P-2 H is characterised by low formation water production and high drawdown. The formation waterto hydrocarbon rate is lower than for the previous two wells. Through the period the fluid flow ratesreduced with depletion.

Figure 6 - Development in the scale potential in P-2 H from 2012 to 2014 and to low-pressure production (LPP).

Although the reservoir pressure is gradually depleting, the sustained high drawdown gives a highSR during inflow from the less permeable Garn sand. The Ile sand is less exposed, yet may

exhibit oversaturation at flowing conditions. The associated mass potential is low or moderate.Upon mixture of the inflow streams the SR remains >1 some way into the lower part of thetubing, while higher in the tubing the effect of dilution by condensing water brings the SR below1.0 at some point in the tubing below the well head.

In summary, P-2 H is most exposed in the near wellbore area and in the lower part of the tubing,and will require continued protection by scale inhibitor squeezing. Scale dissolver pre-treatmentis also considered as part of operational planning.

The conclusion that can be drawn from these examples is that in terms of production, low pressureconditions are a success. It somewhat increases the risk related to calcium carbonate scale, but this

risk was already of a magnitude that required dedicated execution of the protect-by-inhibitor-squeezing strategy. It is possible that the decrease in formation water production may present anopportunity for a slightly reduced squeeze frequency, but this depends on the development of thewater rate and the success of future squeezes.

It can be seen that S-4 H, P-3 H and P-2 H (and other wells with formation water production) aresusceptible to calcium carbonate deposition and require efficient inhibition for sustained production.S-4 H and P-3 H have formation water rates that correlate to significant precipitation mass potential,which implies that a reactive strategy by regular scale dissolver treatment alone is not sufficient. InP-2 H the main potential for precipitation is in the near wellbore area during inflow and possibly inthe lower part of the well, which may indicate that scale dissolver pre-treatment is beneficial prior to

squeezing. The inclusion of scale dissolver is evaluated on a case-to-case basis.


13/15

13

For the foreseeable future, squeezing of inhibitor will be necessary to inhibit deposition of calciumcarbonate in susceptible parts of the wells. Where possible, it is considered beneficial to injectadditional inhibitor at the well head for protection of the production system downstream of the well.

Implications

The above considerations show that the dissolver/squeeze treatments are still beneficial andnecessary to maintain production. Further, it is shown that there may be a benefit in injectingadditional scale inhibitor (upstream the production wing valve) in some of the exposed wells, toensure efficient inhibition also downstream. Efficient monitoring of inhibitor bleed-back is requiredto ensure that concentrations are effective and to give early indication of need for squeeze treatment.Monitoring of productivity development may indicate precipitation in the near wellbore area/lowercompletion and the need for scale dissolver pre-treatment.

As the reservoir depletes the required lift performance upon back-production of a squeeze treatmentmay result in the need for further development in the squeeze design. This issue is under evaluation,and relevant technologies include e.g., foamed squeeze treatment and water shut-off.

Summary

The initial scale mitigation strategy was operationally extensive in accordance with the scale riskidentified at that time, involving a nominal two dissolver/squeeze operations per exposed well peryear. The current adaptation of the strategy is based on monitoring the effect of dissolver, inhibitorreturn, well performance and calculated risk relating to developing production conditions whichform the basis for initiation of dissolver/squeeze operations.

The current view on the scale risk, based on observation and simulations is:

- The risk associated with halite formation is almost entirely diminished, due to the pressuredepletion and the associated absence of Joule-Thomson heating.

- During low rate formation water inflow there may still be an increase in ionic concentrationssufficient to reach saturation for the less soluble salts, due to evaporation of water upondepressurization.

- It can be discussed whether there is a current and general potential for scale deposition in the

near wellbore area, as has earlier been confirmed by observation (productivity changes notattributable to other causes and mitigation by dissolution). It has been shown that at least somewells are still exposed and the use of scale dissolver is thus evaluated on a well-to-well basis. Ithas been seen that in these wells the formation water flow is diluted to undersaturation bycondensed water in the tubing.

- Simulations indicate that there is a considerable probability for scale precipitation in significantquantity in the tubing in wells with high formation water rates. The implication is that in order toefficiently protect the well, inhibition by squeezing remains the appropriate tool for mitigation.

- Further, it is shown that the subsea choke valve is exposed to scale when effectively choking theflow in formation water rich wells. Inhibitor bled back from the squeeze and possibly


14/15

14

supplemented by injection of inhibitor through the inhibitor line to the christmas tree can protecta choked valve.

Careful monitoring of residual inhibitor concentrations and productivity development is used todetermine the need for and timing of the scale squeeze operations. The use of dissolver is evaluated

on a well to well basis and the ionic contents of the scale dissolver return is analysed to confirmscale presence and dissolver efficiency. This approach enables a cost optimal and efficient executionof the scale mitigation in Kristin.

Acknowledgment

The authors would like to thank Statoil and the Kristin partnership (Statoil AS, Petoro AS,ExxonMobil E&P Norway AS, EniNorge AS & Total E&P Norge AS) for permission to publish thiswork.

Nomenclature

↑ = Increasing↓ = Decreasing~ = Unchanged p = Pressure drop across the choke

BH = Bottom holeBHP = Bottom hole pressureDD = Drawdown - pressure drop from reservoir to wellbore.

Fm. = FormationFW = Formation waterLPP = Low pressure production

NaCl = HalitePDC = Pressure downstream subsea chokeSD = Scale dissolverSI = Scale inhibitorSm 3/d = Standard cubic metre per daySR = Saturation ratioWC = Water cutWHP = Well head pressure

References

1. R.Wat, A.M. Bush Iversen, Y. B. Belsvik : “The diagnosis of decline and successful recovery ofPI in a ‘DRY’ HPHT gas well that has been affected by in -situ CaCO 3 scale and salt deposition” SPE 130521, presented at the SPE International Conference on Oilfield Scale, 26-27 May 2010,Aberdeen, United Kingdom.

2. R.Wat, K. Wennberg, R. Holden, B. Hustad, S. Heath, M. Archibald, K. Singdahlsen.: “The

Challenges Associated with Performing and Combining Scale Dissolver and Squeeze Treatments


15/15

15

in Kristin – A Subsea HP/HT Gas Condensate Field” SPE 114079, presented at the SPEInternational Oilfield Scale Conference, 28-29 May 2008, Aberdeen, United Kingdom.

3. N. Fleming, K. Ramstad, A. Nelson, G. Graham. “Impact of Successive Squeezes on TreatmentLifetime & Well Productivity: Laboratory & Field Eviden ce” SPE 113657, presented at the SPE

International Oilfield Scale Conference, 28-29 May 2008, Aberdeen, United Kingdom.4. M. Nergaard, C. Grimholt “An Introduction to Scaling, causes, problems and solutions”, Term

paper for the course TPG 4140 – Natural Gas

Documents

20 Re-evaluation of Scale Strategy in a Maturing Field- Gigi a Sand