EXPERIENCE WITH THE USE OF TETRAKISHYDROXYMETHYLPHOSPHONIUM SULFATE (THPS) FOR 'IRE CONTROL OF DOWNHOLE HYDROGEN SULFIDE

Jan Larsen Maersk Oil and Gas AS

50 Esplanaden, DK-1263, Copenhagen K Denmark

Peter F Sanders Oil Plus Limited

Hambridge Road, Newbury, Berkshire RG14 5TR United Kingdom

Robert E Talbot Albright & Wilson UK Limited

PO Box 80, Oldbury, West Midlands B69 4LN United Kingdom

ABSTRACT

TetrakisHydroxyMethylPhosphonium Sulfate (THPS) is used as a bactericide in the Skjold/Gorm oil production systems in the Danish sector of the North Sea. A reduction in H2S generation downhole due to THPS treatment resulted in savings on H2S scavenger consumption. In addition, use of THPS provides other benefits which are discussed in the paper.

THPS treatments are compared with conventional bactericidal treatments and it is demonstrated how downhole injection of THPS retards the growth rate of Sulfate Reducing Bacteria (SRB) and the rate o f H2S production. THPS treatment resulted in a change in the downhole bacterial population, evidenced by changes in the sulfur isotope ratio of the produced H2S.

Re-injection of produced water with low H2S concentrations increases the potential for iron sulfide (FeS) deposition, both in topsides and downhole. THPS changes both the physical form and the bacterial content of the FeS deposits. Removal of the deposits with acid is facilitated by TI-IPS which exhibits FeS dissolving capabilities. Field tests have verified the effect.

INTRODUCTION

The Skjold oilfield is located in the Danish Sector of the North Sea and is operated by Maersk Oil and Gas AS. Production of oil and gas commenced in 1982. Two wellhead platforms are installed in the Skjold field but control and operation is conducted from the nearby Germ Platform where Skjold production is processed.

Copyright @2000 by NACE International.Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The materiel presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in U.S.A.

Water injection, to maintain reservoir pressure, was commenced in 1985. The producing horizon is the Maastrichtian Age Chalk,

Sulfate reducing bacteria (SRB) are commonly encountered in produced waters from deep oilfield reservoirs. The growth and activity of such bacteria are responsible for souring of the crude oil. Many early studies" revealed the presence of mesophilic sulfate reducing bacteria (mSRB) within sour oil production facilities, especially in the colder parts of the system. Subsequently, more detailed surveys of North Sea oil production systems demonstrated that therrnophilic SRB (tSRB) are likely to be the most important group of sulfide generating organisms in systems above 60°C 2" 3. This was later confirmed by other workers 4' ~ who have also demonstrated the existence of a wide ranging population of sulfide generating bacteria which contribute to souring. In addition to the souring problems caused by (thermophilic) sulfate reducing bacteria, microbially influenced corrosion (MIC) is also enhanced in hot production systems 6.

A conventional bactericidal formulation has, in the Skjjold Field, been used to control bioproliferation in the water injection pipelines and topside production facilities but was unable to control downhole hydrogen sulfide (H2S) generation. Hence, produced H2S has been increasing steadily, necessitating the use of increasing quantities of H:S scavengers. In addition to increased corrosion due to HeS, iron sulfide deposits in Skjold produced water reinjection wells caused loss of production by restricting water injection rates.

An alternative bactericide product, tetrakishydroxymethylphosphonium sulfate (THPS) was field tested in six campaigns during the period 1994 to 1999 and has yielded reductions in H2S generation downhole in the areas treated. Similar reductions in H:S generation had previously been observed in other fields 7 and, furthermore, other beneficial effects of THPS have been noted, for example, it has made iron sulfide deposits more porous, thus increasing the effectiveness of acid dissolution. It is anticipated that future use of THPS will eliminate the need for acidising the wells as THPS dissolves iron sulfide s .

THE SKJOLD FIELD

Skjold is a dome shaped chalk reservoir with a very low matrix permeability (<1 roD) and a high, but variable, degree of naturally occurring fractures. All injection wells, except one, are completed in the water zone (beneath the oil layer) but, due to the fractured nature of the reservoir, injection water breakthrough times can be very short. As an example, in 1994, when the first study of THPS treatment was conducted, the breakthrough time between injector well Skjold-7 and producer well Skjold-12 (located in a more fractured part of the field) was 20 hours. Other wells have longer connection times depending on the local fracture pattern, for example injector well Skjold-3 and producer well Skjold-18 located in a more matrix dominated part of the field.

Gas lift is used in many of the Skjold wells and this can cause misleading long term interpretations of changes in souring rates if the H2S concentration is used as an indicator of H:S generation downhole. A further complication arose from a change in the mode of operation of the oil/water/gas separation system on the Gorm platform during 1996. This change resulted in 87% of the HzS being flashed from the liquid phases into the gas phase compared to 75% prior to the change. In order to take account of these variations, H2S data have been expressed as mass flow of produced H2S ( i.e. kg/day).

The first recorded H2S production was in September 1985, following the startup of water injection in April 1985. At that time, Skjold-2 showed 18 ppm H2S in the gas phase but this had become 10.5 ppm by November 1988 and, since that time, the H2S production has increased steadily. Seawater breakthrough was first detected in the Skjold field in late 1991.

In 1994 and 1995, backflow tests of injection wells showed conclusively that the near wellbore region was highly contaminated by a mixed bacterial population, including both mSRB and tSRB. H2S concentrations in the baclcflows were in the region of 15 to 65 rag/1.

From 1994 and onwards, produced H:S data has been expressed in terms of kg/day rather than ppm in the gas phase, avoiding misleading patterns due to changing ratios between gas, llftgas, oil and water. Figure 1 illustrates the increase, showing that produced H:S mass flow increased from I00 kg/day in 1994 to a maximum of 1000 kg H2S/day in early 1999. Fluctuations in the order of 200 kg/day are observed when closing-in swing producer wells with high water cut. A logistic growth model 9 was developed, describing, in time, how growth of SRB will develop if the system is constrained by itself. Logistic growth is a mathematical model that describes the growth in a biological population where the growth rate is not constant but decreases when the population grows. The growth rate is dependent on the number of bacteria. Laboratory studies (conducted under simulated reservoir conditions) showed that 120 mg/l dissolved sulfide was the maximum tolerable

limit for bacteria derived from the Skjold system, even when nutrient and sulfate were in excess l°' H. The logistic growth model is based on the assumption that the SRB activity will be inhibited by an H2S concentration in the region of 120 mg/l in the water downhole.

1000

800

.~ 600

ff

200

"

p I ~ I i

July-94 July-95 July-96 July-97 July-98 July-09

FIGURE 1 - Skjold H~S Production (1994 to 1999)

The potential for future H2S production has also been estimated based on the composition of the waters involved. In addition to sulfide toxicity, one significant factor for SRB growth is the availability of carbon sources, particularly volatile fatty acids (VFA's) such as acetate, propionate and butyrate. A comparison of the organic content of injection and produced waters shows that, for most Skjold wells, there is a correlation between the VFA (especially acetate) depletion and the H2S produced 12. This observation is entirely consistent with a microbial souring process which is the only known mechanism utilising VFA to produce sulfide. Adversely, this means that the potential for further souring will rise as re-injection of produced water, containing VFA' s, increases.

Wells in highly fractured regions produce more H2S than wells in matrix dominated regions. Changes in the production profile from these wells result in variations in the total field H2S production and these changes must be taken into account when predicting the profile for future H2S generation.

A conceptual model has been developed to define those regions in the Skjold reservoir that support SRB activity and to explain bacterial migration patterns in the rock (Figures 2 and 3). Analysis of Skjold cores indicates that bacteria are present in the matrix of the chalk. SRB are certainly tocated in the smallest fractures in the highly microfractured Skjold chalk. Major fractures between injection and production wells lead to short communication times for injected water, but matrix sweep is the main oil recovery mechanism. Water injection causes the fracture free water level to rise, displacing oil from the matrix. Oil is replaced with mixed formation and injection water, containing both mSRB and tSRB. The mixed formation and injection water provides both sulfate and nutrients to support H2S generation by these SRB. Matrix contamination and the rising fracture free water level, introducing new bacteria into the rock, lead to widespread and expanding regions of SRB activity in the formation.

After injection of a bactericide slug into the fracture system it is expected that the biological activity in the fracture system is significantly reduced and the H2S level in the water/oil within the fracture will equilibrate with the H:S level within the matrix. When an effective bactericide is injected downhole into the Skjold reservoir, reductions in H2S concentrations are rapid, with H:S in produced fluids increasing only slowly after bactericide injection has ceased. From well data it is estimated that the H:S level within the matrix around the water filled fractures between the oil water contact and the fracture free water level is in the order of 50% of the H2S level in the fractures during high biological activity.

j ~ Active tSRB

Active mSRB @ Dormant tSRB in hot wells

Dormant tSRB ~ ~ Active tSRB and active mSRB in cool

_ Introduced with wells Iniection Water

't ~- ~ . s # ~,ll///I./~*a{:{ ~ , \ \ \ \ \ \ \ \ \~ '~ ~illlJ I

. .

L.

i

mS~ ~ Open fracture Souring in advance of - , \ / main seawater \ breakthrough / o ° o \ ft.SRB t t O ~)~

I~rrnJmt Main flood ~aoterial Mi~rauon (Dorman~,~ I o t t t-SRB I I~.SRB t~ 0

ol o ° ~ I o ~o o I

t; t i --s ,,., ,:i,/ ,,Oo , I o l o. 1 - /

o O'o . } 'o i l Zone 5

Zone 3 Zone 4 Zone l Zone 2 / Low

Medium Low Low mSRB Souring: Medium ~ Medium t S ~ S o u ~ Med ium ~ At high pre------------ssures, Nutrients and t~t~a~ mSRB plug near 1 ~ " ~ HiS generati°n by :nax temp may not ~rom drilling/ perforations. Large I htgn, .tem__P_~*,~ ~'~'° I tSPd3which attach inhibit tSRB. Toxic completiordsquee.ze numbers of mSRB I .a__n.d.=m~c,re~a,~,unl~v t and grow if suitable levels of sulfide from present but activity I . ~ ~ , ~ ma,~ sulfate, Zone 3 may limit limked by nutrients and t ~ : / temperature: fa~y further sulfide biocides. Maximum 120 . . production rag/1 sulfide

Sulfide generation limited only by nutrients and sulfide toxicity.

FIGURE 2 - General Conceptual Model for Reservoir Souring in a Fractured Oilfield

treatments may gwe localised HaS generation. Sulfate and temperature may

~-S-ulfide generation limited IbY high temp and sulfide

Active SRB ~:~..._~:f"""

Dormant SRB

Injection Water ~ Injection Well Temp: 20-35°C i

Production Well

< ~ Indigenous H2S generating bacteria ( 0.1 lam) and i | Sulfate: i starved SRB (remaining inactive) migrate through matrix 2800 mg/1 ! Matrix Dominated Area j ( / i

<2 mg/l (seawater) i • . . . . . . . . . . • l • . o • . ' l • : ' . . . . . . . . . , . . . I/ 20-30mg/1 I . . . .M~ero* f~ac tu r e s • ' I ' . ' : - : 'TT" : - -~ : . : . : . ~ . : . " - : . : . ' . : f l ' . ' . ' . ' . " (seawater/produced I : - : • '.and:fis:su~.es: • ."%,~/ : . : . : \ f . : . : . ~. : . : . : - : • : . : • ~. : t / : . : . : . : " : ' i water mixture) .... ~ ........ L . ' . ' . ' . ' . ' . ." . ' . " " . ' . " ' . ' . ' . ' . ' . ' . " " " - ' . " . ' - ' . "

• f ,! " - , . ; . : . : . : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : / 1 " ~ , " . * * . " . ° , ° • * . * * • * • ' • * • * * * • * * " • * * • : ~ . . . . . ' " ' , .

N ~ .----~T-: . ' ~ . : ".~;:~ ;;'~.~. . . ' . ' . ' . ' . ' . ' . ' . " . ' . ' . ' . " : . : . : - : . : . : . : . . - : - : . : . : . : - : . : . : . : . : - : ' :

Area of bacterial activity - Vegetative SRB penetrate fractures micro-fractures and fissures

Produced Water Temp = 40-80°C

Sulfate: 600-2800 mg/1

Max a2s in water (total): 160 rag/1

VFA: 20-250 mg/l i(I0-90% water cut)

,4 Increased mSRB Activity

- - - - - > S o u r i n g in advance of injection water breakthrough

Increased tSRB Activity

FIGURE 3 - General Conceptual Model for Reservoir Souring in Fractured Reservoirs (Not Sulfate or Nutrient Limited)

DOWNHOLE CONTROL OF BACTERIA AND H2S PRODUCTION

Treatment Options

A number of treatment options have been considered, in addition to topside H2S scavenging. These included downhole scavenging, installation of a sweetening plant, operational changes to minimise partitioning of H2S into the gas phase and the use of bactericides to control downhole generation of H2S by SRB.

Field application in the Skjold system had previously confirmed that the conventional (aldehyde based) bactericide regime in use on the Gorm/Skjold fields was suitable for topside treatment but only partially effective for the control of downhole bacteria. Further trials of the conventional bactericide were conducted during 1998 at 200 to 300 ppm for 24 hours. No effect, on the produced HzS from Skjold, was observed during these trials.

Laboratory evaluations of a wide range of active bactericidal ingredients were therefore conducted to identify products suitable for application to the Skjold reservoir. During this evaluation, THPS was identified as a promising candidate for field use. Since 1994, THPS has been applied to the Skjold field, with treatments and product formulations varied in order to determine the optimum treatment package.

1 3 THPS was discovered to be a potent microbiocide during the early 1980 s and now has a history of successful 1 4 1 5 1 6 application to cooling systems and oilfields ' ' . The chemical structure of THPS is shown in Figure 4. Whilst the primary

use of THPS is as a water injection/topside bactericide, it has also been demonstrated to be active under reservoir conditions and to dissolve iron sulfide and is now widely employed in the oil production industry around the World.

CH2OH

! HOCH2"P-" CH2OH

I CH2OH

SO4

2

FIGURE 4 - Chemical Structure of THPS

THPS, unlike a number of other bactericides, is not inactivated by hydrogen sulfide and, consequently, remains active under downhole anaerobic conditions. Evidence has already been presented 7 to show that THPS, dosed to injection water, re-emerges in breakthrough water maintaining its bactericidal activity into the production system. This retained activity has proved useful in controlling topside SRB in the production equipment. Once the produced water is discharged, the THPS is quickly oxidised to an inert product thus rninimising risks to the environment.

T r i a l S c h e d u l e

Trials were conducted as shown in Table 1.

TABLE 1 SUMMARY OF TRIALS

Trial Detltls,

'THPs*was d0sed for ~i days to Skjold'7

Date

June 1994

January-March 1995

November1995- March 1996 July - December 1997

November1997

January - June 1999

starting at 1000 ppm and finishing at 300 ppm. 3 batch treatments, alternating between THPS* and conventional bactericide, were dosed to the Skjold reservoir. A typical THPS treatment regime was 200-250 ppm for 8-24 hours.

Batch treatment using THPS (200 ppm for 5-8 hours) without a surfactant biopenetrant. Batch treatments with THPS* followed by pulsed treatment consisting of two regimes (400 ppm for 6 rains every second hour then 400 ppm for 4 rains every hour).

Batch treatment of Skjold-3 with THPS" (800 ppm for 8 hours)

Batch Treatments with THPS: January- 200 ppm for 72 hours

March - 200 ppm for 72 hours

June 125 ppm for 105 hours

* Note: Except for the trial in November surfactant biopenetrant.

1995 -March 1996,

ouservea

50°,6 reduction in produced H~S at nearby producer Skjold-12. Long lasting effect (3-4 months). 35-40% H2S reduction in Skjold HP gas with a reduction from 100 ppm to 65 ppm at the end of the treatment period. H2S levels at individual wells reduced quickly but started to increase 3-5 days after treatment. H2S levels in Skjold liP gas was back to the initial level by June/July 1995. No effect on produced H2S.

High concentration batch treatment (200 ppm for 75 hours) gave an immediate reduction of produced H2S from 460 to 400 kg/day. Pulsed treatment provided additional control of H2S. Transient effect observed on nearby producer Skjoid-18 with a 20% H2S reduction after one week. H2S production returned to initial level after 2 weeks.

25% H2S reduction (gas phase) lasting 4 weeks before an upwards trend was observed. 15% H2S reduction (gas phase) lasting 4 weeks before an upwards trend was observed. No effect on produced H2S (THPS concentration too low). all trials used a THPS product containing a

First Trial, Long Term Batch Treatment, Skjold-7 (June 1994)

THPS bactericide was dosed into Skjold-7 (injector) at varying rates between 300 and 1000 ppm for 6 days as shown in Figure 5. This well is connected, via a fracture, to Skjold-12 (producer). The transit time between the injector and the producer well was 20 hours after which an immediate 50°/, reduction in produced H2S was observed. The H2S in the gas was reduced from 80-105 ppm to 50-53 ppm and the H2S in the produced water was reduced from 10.7-17.6 mg/1 to an average of 6.5 mg/l. The total produced H2S (all three phases) was reduced from an average of 30 kg/day to 15 kg/day.

THPS concentrations in the produced water were monitored by a simple field analytical method and it was found that the re-emergent THPS bactericide peaked at 540 mg/1 late on the second day of the trial.

Even after bactericide dosing was suspended, the produced H2S level remained low for 10 days then slowly increased over the next two months to 60-70 ppm which corresponds to an average total H2S production of 20 kg/day. This H2S profile confirmed that the THPS was not acting merely as a scavenger for H2S but was consistent with its acting as a bactericide downhole.

105

• 85

a. 65

45

-~ THPS Dose Level

Produced H2S

1000

80O

400

200

16-Jun-94 20-Jun-94 25-Jun-94 30.Jun.94 05-Jul-94 10-Jul-94

FIGURE 5 - First Trial - Effect on Produced H2S

Furthermore, prior to the THPS treatment, produced water from Skjold-12 consistently contained 10-100 tSRB/ml and 500-1000 tGAnB/ml. 12-24 hours after the THPS had broken through to Skjold-12, no bacteria could be detected in the produced fluids. However, once the THPS had been flushed from the well, tSRB became evident again and soon rose to their original levels. It is thought that these tSRB have arrived at Skjold-12 from another route (i.e. not from Skjold-7) as backflow data showed that the near wellbore of Skjold-7 remained free oft-SRB for a significant period after THPS dosing had stopped.

In addition, 834S measurements showed significant changes during the treatment. The technique is widely used to differentiate sulfur sources. 834S measures the ratio between the 34S and 32S isotopes in a sample, expressing the result as parts per thousand (%o) with respect to the international standard (Canyon Diablo Triolite). Different SRB types produce different 834S ratios. It has been established that the 834S ratio in H2S produced by Skjold mSRB is approximately -3 %0 whereas that produced by Skjold tSRB is approximately -8 %0. Before the THPS treatment, the ~534S ratio in the H2S produced at Skjold- 12 was --6.5 %o whereas after the THPS treatment it was -1%o. This appears to imply that more tSRB have been killed than mSRB. This is clearly not an effect due to bacteria in the near wellbore of Skjold-7 since this area was almost sterilised and is more likely to be due to THPS transiting the reservoir and killing tSRB deep in the formation.

There was no immediate effect on other producer wells around Skjold-7. The fast response observed in Skjold-12 is the result of communication through the fracture system and the neighbouring wells do not appear to have the same level of fiacture communication.

Backflow data are ex~trernely useful for evaluating the performance of a downhole bactericide. It is conventionally accepted that most downhole microbially generated H2S originates in the near wellbore of injection wells. In the near wellbore area there is a good supply of sulfate-containing water and, also, the temperature conditions are likely to be more favourable to support mSRB growth producing H2S more rapidly than similar populations oftSRB deeper into the reservoir where it may be hotter. Also, backflows of injector wells often show high sulfide concentrations and high bacterial counts. Obviously, the eventual target of downhole bactericide treatment is to reduce produced H:S concentrations. However, the effect of treatments in water injection systems are often difficult to identify from produced H~S measurements alone, since the H2S may have come from any of the injection wells supporting the producer.

Hence, a series of backflows was performed on injection well Skjold-7 and the results are shown in Figure 6. Backflow no 1 (before THPS treatment) showed an initial sulfide concentration of 30 mg/l at the perforations (i.e. after a backflow of one tubing volume), increasing to approximately 60 mg/I in the formation after a backflow of three tubing volumes. In contrast, the backflow following immediately after the THPS treatment levelled out at just over 20 mg/l; also the water was cleaner, had a more positive redox potential and the odour of H2S was noticeably weaker. One month after the THPS treatment, a third backflow was performed and this time the H2S plateaued out at approximately 30 mg/l indicating a slight recovery by the bacteria. These results confirmed that THPS was able to control downhole bacteria in the near wellbore a r e a .

A m

E

N

SO

40

First Backflow (before THPS ~ v

treatment)

N . / Third Backflow

. . . .

Second Backftow (immediately after THPS treatment)

-20 2O

i [ i

40 60 80 100

Back f iowVolume (rn ~) ARer Perforations

i ]

120 140 160

FIGURE 6 - Backflow Data for Skjoid-7

Figure 7 shows bacterial counts for the three backflows. It can clearly be seen that, immediately after the THPS dosing, bacterial levels were virtually zero. However, one month later, bacterial levels were starting to recover but had not attained pre-dose levels. Interestingly, the 634S result between the first two backflows did not change appreciably from the initial value o f - 6 %o. This confirms that, in the near wellbore area, all SRB groups had been equally affected by the bactericide. The change in ~534S in the production well (detailed above) must therefore have been due to selective kill of one type of SRB (i.e. the tSRB) further along the fractured communication path.

The conclusion from this trial was that THPS had obvious potential for the control of downhole H2S generation in the Skjold field.

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F5

o

3

2

0

Before THPS Treatment

[ - - - - - - -~ Immediately after THPS Treatment

• 1 month after THPS Treatment

t-SRB m-SRB t-General Anaerobic m-General Anaerobic Bacteria Bacteria

FIGURE 7 - Bacterial Counts Before and After Backftow of Skjold-7

Second Trial, Batch THPS and Conventional Bactericide (January-March 1995)

A combination of THPS and conventional bactericide was dosed to the Skjold injection water resulting in a 35-40% reduction in Skjold produced H2S with a reduction from 100 ppm to 65 ppm at the end of the treatment period. The H2S level in Skjold HP gas was back to the initial level in June/July 1995. The objective was to establish the most effective treatment regime for controlling topside and downhole SRB activity using both THPS and a conventional biocide. Since both bactericides were used in this triM, it was not possible to quantify the THPS effect separately.

Third Trial, Unformulated THPS, Skjold-7 (November 1995-March 1996)

The purpose of this trial was to evaluate the performance of unformulated THPS, i.e. with no surfactant biopenetrant. The THPS was batch dosed to Skjold-7 at 200 ppm for 5-8 hours. It was known that dosing THPS, with a surfactant biopenetrant, would achieve a measureable H2S reduction under these conditions. However, dosing the unformulated THPS resulted in no reduction in H2S, confirming that suffactancy was a neccessary component of the treatment package. Consequently, all subsequent THPS treatments incorporated a biopenetrant.

Fourth Trial, Extended Batch T r e a t m e n t and Pulsed T r e a t m e n t (July 1997)

This trial was conducted in three stages. The first stage was to dose the normal weekly THPS batch treatment regime (400 ppm for 7-10 hours) to the field injection water and to monitor the total H2S production from the Skjold field. Figure 8 shows that after each of the three THPS treatments there was a reduction of produced H2S (typically 10-15%) which lasted for 3-4 days, followed by an increase back to near its original level. The treatment therefore controlled the produced H2S but did not give an overall decline. It is likely that the relatively rapid H2S increase is due to H2S diffusion from the matrix.

During the THPS treatments, bacterial numbers (both SRB and non-SRB) were reduced to zero in the Skjold produced water.

500

450

-} • ~, 400

350

300

THPS treatment 400 ppm for 7 hrs

TI'IPS treatment THPS treatment THPS treatment 200 ppm for

400 ppm for 7 hts 400 ppm for 10 hrs 47 hrs 25 rains

I b I

Shutdown on 08-Jul

09-Jun-97 16-Jun-97 23-Jun-97 30-Jun-97 07-Jui-97

FIGURE 8 - THPS Batch Treatment

The second stage was to employ an extended treatment in an attempt to contact SRB in the matrix, but using a lower concentration of THPS (200 ppm THPS bactericide). Because of an impending shut-down on 8 July, the first treatment was 47.5 hours, with a second batch treatment performed from 13 July injecting 200 ppm THPS bactericide for 75 hours. The effects of the first extended 200ppm treatment were masked by the shut-down but, as shown in Figure 9, the second batch treatment gave an immediate reduction of produced H2S from approximately 460 kg/day to 400 kg/day.

The third stage was a Pulse" Treatment 17 initiated immediately after stage two, dosing 400 ppm for 6 minutes every 2 hours. The end result of the batch and pulsed treatments was a steadily declining H2S profile which bottomed out at approximately 335 kg/day. Due to operational changes it was not possible to optimise the pulsed treatment regime for the Skjold water injection system.

* Pulse ® is a registered trademark of Nalco-Exxon

5 0 0

4 5 0

m m

5~ 4 0 0 ¢ q

3 5 0

Start THPS pulsed treatment 400 ppm for 6 rains every 2 hrs 12.30

• hrs 16-Jul THPS treatment

400 ppm for 7 hours 09.00 hrs to 16.00 h.ts 15-Aug

~ Jl,,,.,,,at,,at Shutdown on -X,/ \ ./- \ h ,-sop

200 ppm for 75 hrs "'~. / X / V-~ sta.09.00~ 13-~ul ~ X / X

finish 12.00 hrs 16-Jul tt • • I

3 0 0 I I I + ', ~ I

09-Jul-97 16-Jul-97 23-Jul-97 30-Jul-97 06-Aug-97 13-Aug-97 20-Aug-97 27-Aug-97

FIGURE 9 - THPS Pulsed Treatment

From 30 July, there was a fluctuation in produced H2S due to a change between two swing producer wells. A further batch treatment of 400 ppm THPS bactericide for 7 hours was made on 15 August which continued the decline in produced H2S to 305 kg/day. Major shutdowns occurred on 1 and 3 September, and a further change between the same two swing producer wells, disturbing the flow dynamics in the field. However, Figure 10 shows that, after the system had stabilised, there was a period extending from early September to early January during which the pulsed treatment maintained the produced H2S at a constant level. On reverting to the conventional aldehyde biocide treatment regime, on 8 January, the rate of H2S production increased.

900

800

700

A

q ~

600

~ s o o

4O0

300

200

] t

Change between I Swing Producers I

(01-Sep) Trendlines i

l \ + i

i +

+

to Conventional Biocide i I

(08-Jan) i + i i i ' I

08-Aug-97 27-Sep-97 1 6 - N o v - 9 7 0 S - J a n - 9 8 2 4 - F e b - 9 8 1 5 - A p r - 9 8 0 4 - J u n - 9 8

FIGURE 1O - Effect of Changing fi'om THPS Pulsed Treatment to the Conventional Biocide

Conclusions drawn from this trial are as follows:

1. The initial batch doses of THPS (400 ppm for 7-10 hours) had a short term effect in reducing the H2S production but did not yield an overall reducing trend.

2. The subsequent long lasting THPS batch treatment (200 ppm for 75 hours) had a significant effect in reducing the H2S production.

3. Pulsed treatment maintained control of produced H2S but, on reverting to the conventional aldehyde based biocide treatment regime, the rate of H2S production increased.

4. Pulsed dosing had a beneficial effect on biofouling in the topside water injection facilities, with consequent reduction in the risk of MIC.

. THPS was transported through the reservoir from the injection wells to the production wells and achieved a biocidal effect in the production system. Effective control of sessile bacteria by this THPS breakthrough led to control of MIC in the topside production plant. This substantiated previous observations of this effect.

Fifth Trial Batch Treatment, Skjoid-3 (November 1997)

The production well Skjold-18 is a major H2S producer, located in a matrix dominated part of the Skjold field. The supporting injection well (Skjold-3) was batch treated with 800 ppm THPS for 8 hours in order to assess the possibilities for H2S reduction from this major source.

There was a transient effect involving a 20°,6 reduction in produced H2S over a period of 1 week, with H2S production returning to the initial level after 2 weeks (Figure 11). The effect of this THPS treatment on the H2S production from Skjold-18 is smaller than that observed in the Skjold-7/Skjold-12 well pair. Although the contact time was lower in Skjoid-3 than in Skjold-7, the results suggest that treatment of the matrix dominated parts of the reservoir with the aim to reduce H2S production is more difficult than in the more highly fractured regions.

120 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

100

8O ~3

60 31-Oct-97 07-Nov-97 14-Nov-97 21-Nov-97

FIGURE 11 - Produced Hydrogen Sulfide from Skjold-18

Sixth Trial, Extended Batch , Fie ldwide ( J a n u a r y - J u n e 1999)

By early 1999, H2S production in the Skjold field had risen to approximately 1000 kg/day. Figure 12 shows the effect of three THPS batch treatments. The first two, in January and March 1999 used 200 ppm THPS for 72 hours to the injection water for the Skjold field. The third treatment was at a lower concentration (125 ppm) for operational reasons.

Data from the first two THPS treatments showed three effects:

. A reduction in Skjold H2S production (gas phase) of 25% and 15%. The effect of a single THPS treatment lasted, typically, 4 weeks before the total Skjold H2S production changed from a downwards to an upwards trend.

2. A long term downward trend in H2S production over a period of 6 months (see trendline in Figure 12).

3. A significant drop in the bacterial activity (based on ATP measurements) in the Skjold water injection system was observed.

However, the third batch treatment, during June, was at a lower treatment level. Only 125 ppm of THPS was dosed, albeit for longer duration (105 hours). In this case no effect on produced H2S was observed since the THPS treatment level was too low to achieve control of the bacteria downhole.

1200

i 1000

soo

600

• ° e , • **~ Trendline wm ,.

• • 48, m ". - - " o I o

• • • ~ O O ~ m, All. O418, ~ ,D

• . . . • - r . • / - m r s

THPS injection THPS injection 14 to 18-Jtm-99 o 25 to 2K-Jan-99 16 to 20-Mar-99 G,

~ o

14-Jan-99 l l -Feb-99 l l -Mar-99 08-Apt-99 06-May-99 03-Jun-99 01-Jui-99 29-Jul-99

FIGURE 12 - Skjold Total Produced H2S Under Normal Operating Conditions (January to June 1999)

C ONT ROL OF IRON SULFIDE

Iron sulfide deposition has recently become a severe problem in the Gorm/Skjold injection system caused by increasing re-injection of produced water. The iron sulfide deposits build up in topside and well tubulars thereby restricting injection fiowrates and reducing oil production rates.

In order to solve the problem, deposit samples, recovered from the water injection system, were analysed and were found to consist mainly of iron sulfide particles and heavy (not waxy) oil. Figures 13 and 14 show the structure of these deposits, using Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Analysis (EDXA) analysis. A typical ratio of iron sulfide to oil would be in the range 80:20 to 50:50 by weight. The deposits also contained bacteria, but in low numbers.

/"

(

Area EDX analysis of this deposit shows that the dominant detectable elements are Fe and S, with minor CI, Ca and Mn.

There is a weak banding, defined by variations in texture between the dominant spongy material and denser bands. The textural variation corresponds to a chemical variation. The denser bands are relatively pure Fe + S with a high S content. The spongy material has a lower S content and also includes significant Ca and Mn.

Fe + C1 plates are present lining the scattered larger and vuggy pores.

C t e 600

500

400

Area EDX Analysis

3OO

200

IO0

m ,

oo

s

Lc~ ca Me

2.0

, , , , , , i , , , .... -

¢0 6.0 8.0 10.0 k e V

C t s Point EDX Analysis, spongy band

Fo

S

~CI ,.,_ u,, i Fe

O.O

C t s

)0

~o

~o

~0

0

0.0 ZO

2.0 4.0 k • V 6.o 8,0

Point EDX Analysis, dense band

Fe

4.0 keV ao

EDX @20kV

RO

FIGURE 13 - Analysis of Deposit 1 from Gorm-Skjold Flowline

10.0

10.0

\ %

Area EDX analysis of a Gorm-Skjold deposit with a strongly developed banding, defined by textural and chemical variations.

The dense band is notably S-rich. Material either side of this is a Ca-rich and Mn-rich + S-poor.

The dominant type of material is coarsely spongy. EDX shows that this comprises Fe + S with approximately equal peak heights.

Fe + CI plates line some pores.

Area EDX Analysis C t s

450~

4oo

35o

300

25o

200

15o

lOO

5O

0 0,0

CI Ca ..~

LI . I I = = I I I l l

2.0 4.0 6,0 8,0 10,0 k e V

Point EDX Analysis, Ca-rich band Cts

3o0

25o

9tlt3 - - - S E

150

IO0

5O

0 ~ OD 2.0 ¢0 ~0 8~ 1o.o

keY

Cts 400

Point EDX Analysis, S-poor band

iO

X~

tO

~0

iO

lO

0

0,0

Mn

2.0 ¢0 EO SO I~O k e y

EDX @20kV

FIGURE 14 - Analysis of Deposit 2 from Gorm-Skjold Flowline

It has been reported s earlier, that THPS would dissolve iron sulfide under certain conditions. A laboratory investigation was, therefore, made to evaluate the performance of THPS against samples of the actual deposits found in the Gorm injection system. Tests were conducted by contacting ferrous sulfide with 1% THPS solutions under anaerobic conditions. Contact times of 5 and 21 hours were used and temperatures of 20°C and 60°C. In addition, the tests were repeated using solutions containing 1% THPS and 0.1% ammonium chloride. The results, shown in Figure 15, clearly illustrate the marked influence of temperature, contact time and, in particular, the presence of ammonium ions on the dissolution. Thus for a 5 hour contact time, at 60°C, the presence of ammonium ions increased the iron uptake from 33 mg/1 to 200 mg/l. The dramatic effect of the presence of ammonium ions is due to the in-situ formation of a soluble iron complex formed between THPS, ammonium ions and ferrous iron (Figure 16). Details of the chemistry involved in this reaction have been submitted for publication TM.

400

300

E 200

!

~ loo

THPS plus NH4CI

THPS, alone

5 hr Contact 21 hr Contact 5 hr Contact 21 hr Contact

k. Y , J \ Y ..,2

20°C 60°C

FIGURE 15 - Iron Sulfide Dissolution by THPS -( PR2 R "P % _....OH2

Fe R "P "/~'~- / OH2

( I / PL2 - N

I

[SO4]

FIGURE 16 - THPS/Iron/Ammonia Complex

The potential for iron sulfide deposition in the Skjold and Gorm systems has been evaluated, using iron and sulfide concentrations from the various injection waters, as shown in Table 2.

TABLE 2 IRON AND SULFIDE CONCENTRATIONS IN INJECTION WATERS

Water Stream Iron (rag/l) Sulfide (ra8/l):i Gorm Prod Water 1.0 30 I Skjold Prod Water 0.12 20 i

Seawater 0.15 0.5 . i

Solubility (rag/I).i. " Potential(nag/l) 0.05 : 1.5 0.1 0.03 0.1 0.07

Iron sulfide has a high affinity for oil and deposits of iron sulfide tend to be deposited with agglomerated oil in the iron sulfide matrix. On the basis of the known composition of existing deposits isolated from the Gorm injection system and the iron sulfide deposition potential shown in Table 2, it is possible to calculate the potential future deposition. This equates to 13.8 kg/day for the Gorm wells and 1.2 kg/day for the Skjold wells. The actual figures will be higher since extra iron contribution from corrosion caused by SRB will increase the actual potential deposition. The deposition rate, although seemingly small, causes a disproportionately adverse effect on oil production since the fine iron sulfide particles readily block formation rock thus reducing injectivity. In addition, oil droplets from the produced water tend to plug the formation. During the last quarter of 1998, a significant decline in the Skjold and Gorm water injection rates was observed. In the Gorrn field the injection rate in the vertical wells declined some 12% whereas the injection rate in the horizontal wells declined some 2% indicating a degree of near wellbore formation damage. In the absence of any control of iron sulfide in the water injection system a thickness of up to 3 mm has been found topsides. Hence, THPS was investigated as a means of controlling this deposition.

As outlined, above, THPS and ammonium ions form a soluble complex with ferrous ions thus providing a mechanism for dissolution of FeS deposits. It was known that both Skjold and Gorm produced waters contain approximately 30 mg/1 ammonium ions and so this would not be a limiting factor. Offshore tests, by dosing THPS into the infiuent stream of a Gorm separator vessel, have confirmed the ability of THPS to dissolve FeS as shown in Table 3 (final column). As with the laboratory tests, THPS, in the presence of ammonium ions, dissolves FeS at significant rates. Again, this dissolution is markedly increased at higher temperature.

TABLE 3 DISSOLUTION OF IRON SULFIDE BY THPS*

• " I ' m ~ : THPSConcentnttion Iron Sulfide.Dissolution(rag/ tron). : ...... ' . . . . . . . .

8 0.34 0.56 0.9 12 0.52 0.84 1.6 20 0.86 1.4 2.0 50 2.15 3.5 100 4.3 7.0

* In the presence of 30 mg/1 ammonium ions.

The results clearly show that THPS confers the added benefit of FeS dissolution in addition to being an effective downhole bactericide. In fact, following the THPS trials outlined above, pipework inspection has shown that significant FeS removal has already occurred in pipes downstream of the THPS dosing point.

CONCLUSIONS

The trials reported in this paper have confirmed the ability of THPS to reduce dowrdaole generation of H:S when dosed to injection water. Control of produced H2S by THPS has reduced the requirement for H2S scavengers.

Various treatment strategies employing THPS have been used in the Skjold field. Batch treatments between 200 and 400ppm proved to be effective in reducing H2S in the short term, and pulsed treatment provided further control of H2S production.

THPS treatment of the matrix dominated areas of the Skjold reservoir, with the aim of reducing H2S production, is more difficult than in the more highly fractured areas

It is expected that the ability of THPS to transit the formation and remain bactericidally active will reduce the necessity for topside bactericide dosing to the production system. The ability of THPS to control iron sulfide deposits has been shown to be an additional benefit.

In summary, THPS has shown the following range of benefits:

* Reduction of produced H2S in various treatment regimes • Reduction in biofouling of water injection and production systems, thus helping to minimise the potential for

microbially influenced corrosion • Dissolution of iron sulfide deposits

ACKNOWLEDGEMENTS

The authors would like to thank Maersk Oil and Gas AS and DUC partners (Shell and Texaco), Oil Plus Limited and Albright & Wilson UK Limited for permission to publish this technical paper. We acknowledge that the Pulse* Treatment process is presently being patented by Nalco-Exxon 17 and is referred to, in this paper, with the full co-operation of Nalco- Exxon. EDX and SEM analyses were conducted by Dr Jeremy Rushton of Core Laboratories, Aberdeen

REFERENCES

1. B.N. Herbert, Reservoir Souring. In: Microbial Problems in the Offshore Oil Industry (1987). Eds. Hill, Sherman and Watkinson, Pub. J. Wiley and Sons pp. 63-72.

2. WJ. Cochrane, P.S. Jones, P.F. Sanders, D.M. Holt, and J.J. Mosley, "Studies on the Thermophilic-Sulfate-Reducing Bacteria from a Souring North Sea Oil Field". Society of Petroleum Engineers (SPE) European Petroleum Conference (1988). Paper SPE18368.

3. C.J, Bass, P.F. Sanders, H.M. Lappin-Scott, "Starvation and Survival of Thermophilic Sulphate-reducing Bacteria from North Sea Oil Reservoirs". In: Proceedings of the Sixth International Symposium on Microbial Ecology. Pub: International Committee on Microbial Ecology (ICOME) (1992). Paper C4-3-3.

4. J. Parkes, J. Maxwell, "Some Like it Hot (and Oily)". Nature(1993), 365, 694-695. 5. K.O. Stetter, R. Huber, E. Biochl, M. Kurr, R.D. Eden, M. Fielder, H. Cash, I. Vance, "Hyperthermophilic Archaea are

Thriving in Deep North Sea and Alaskan Oil Reservoirs", Nature (1993), 365, 743-745. 6. Sanders, P.F., Lappin-Scott, H.M, and Bass, C.J. (1994). "Corrosion Implications of Thermophilic Sulphate-Reducing

Bacterial Growth in Oil Reservoirs". In: Proceedings of UK Corrosion & Euroccorr 94. Pub: Institute of Materials, London Volume 4, pp 116-127.

7. C.D. Imrie, R.E. Talbot, M.A. Veale, "The Use of Chemical Bactericides to Control Downhole Bacteria", presented at UK Corrosion '98, Sheffield, United Kingdom, 20-21 October 1998.

8. T. Haack, R. Diaz, R.E. Talbot, "TetrakisHydroxymethylPhosphonium Sulfate (THPS): A New Oilfield Bactericide Providing Iron Sulfide Dissolution and Environmental Benefits", presented at Exitep 98, Mexico City, 15-16 November 1998.

9. J. Larsen, J. Monberg, unpublished work. 10. C.J. Bass, H.M. Lappin-Scott, P.F. Sanders, Study of Biofilms of Sulfidogens from North Sea Oil Production Facilities

Using Continuous-Flow Apparatus. Geomicrobiology Journal (1998). 15:101-120. 11. P.F. Sanders, unpublished data. 12. P.F. Sanders, Joint Industrial Project on Ultra Micro Bacteria (unpublished). 13. European patents 0139404 (1985) and 0215562 (1987). 14. B. Downward, T. Haack, R.E. Talbot, "TetrakisHydroxymethylPhosphonium Sulfate (THPS) A New Biocide for

Industrial Cooling Systems", presented at Corrosion 97. 15. N. Macleod, E. Bryan, A.J. Buckley, R.E. Talbot, M.A. Veale, "Control of Reservoir Souring by a Novel Biocide",

presented at Corrosion 95. 16. N. Macleod, E. Bryan, A.J. Buckley, R.E. Talbot, M.A. Veale, "A Novel Biocide for Oilfield Applications", presented at

SPE Conference, Aberdeen (1990). 17. European Patent Application No 95307205.5. 18. J. Jefferies, B. OdeU, R.E. Talbot, submitted for publication to "Chemical Communications".