SPE 154099

Oil Field Chemicals Synergy Upstream Arab Heavy Crude Handling Facilities Dr. Enow Achuo Kima, Saudi Aramco

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Conference and Exhibition on Oilfield Corrosion held in Aberdeen, UK, 28–29 May 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

The presentation key objective is to show how synergizing the use of corrosion inhibitor and demulsifiers has enhanced the performance and optimized the cost of Oil Field Chemical (OFC) treatment at Safaniya Onshore Arab Heavy wet crude handling facilities. The various steps involved in synergizing the use of oil field chemicals at Safaniya Onshore Arab Heavy wet crude handling facilities have also been discussed. The key performance factors used to assess the overall impact of the process including the total cost of chemical treatment, the effective mitigation of corrosion in the system, the oil in water content in the produced water system, other process parameters like emulsion and foaming tendency were addressed. Synergizing the use of OFC at Safaniya Onshore Arab Heavy wet crude handling facilities has resulted in chemical treatment cost savings of approximately $2.0 MM per year, better treatment of produced water system and improved corrosion mitigation efficiency of 99.6%.

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Contextual Data The Oil and gas industry like most industrial organizations today is a knowledge-based industry and its success and survival depends on creativity and innovation. The results is that the industry is forced to create an institutional frame work in which creativity and innovation is nourished and accepted as basic norms in the mist of technological and other changes (E. C. Martins and F. Terblanche, 2003). Innovation in this context involves the implementation of new and problem-solving ideas, industrial practice or products which is regarded as new by the relevant unit of adoption and through which change is brought about (martins, 2000).

Background During extraction of oil and gas products, the greatest part of the crude occurs as a water-oil emulsion. Oilfield emulsions (water-oil emulsions) are stable mixtures of immiscible components formed when produced water mixed intimately with produced crude is stabilized by natural occurring emulsifiers and other produced sediments. And as the demand for the delivery quality crude oil with low salt and water content increases, there is an absolute need to treat the crude to meet the market criteria and to treat the water and oil in order to maintain the integrity of the production facilities. The composition of the crude produced depends on the ratio of oil and water present. As new wells are developed, and production conditions change at older fields, there is constant need to a rapidly separate of the crude produced into oil and water, as well as the minimal residual of salt and water mixture. The separation of residual oil is necessary in oil field water purification and treatment for ecological and technical reasons. This is very essential, especially when the water is used for secondary enhancement of production or water flooding. Any residual oil left in the water will tend to increase the injection pressure and subsequently the injection rates. The presence of water-in-oil often leads to the growth of microorganism in the wetted part of the pipeline and storage facilities resulting to severe corrosion. Crude oil containing high salt content leads to breakdown and corrosion at downstream facilities or refineries. Improving the quality of the water will substantially reduce the shut-in time needed to restore injectivity into the water disposal or injection wells. It will also reduce the cost of stimulating or chemical cleaning of the wells, maintain operational capacity of the plant, and eliminate the need to develop additional disposal wells to meet the requirements for wastewater disposal. An initial study carried out in Safaniya Plant 369 was to optimization of the individual chemicals used in Safaniya Arab Heavy Wet crude Handling Facilities but the cost of the chemicals and synergetic effects were not considered. During the study it was observed that the produced water separated from the wet crude handling facilities contained various amount of oil contaminant and suspended solids and carbon dioxide. The concentration the solids ranged from 15 mg/l to 100 mg/l in the produced water system and 30 mg/l in the crude (see table of analysis results below). Three water injection wells, 701, 702 and 703 are used to dispose the produced water from the wet crude treating facilities. The oil contaminant and the suspended solids present in the plant disposal water affects the injectivity of the disposal or injection wells. Both wells have been on a scheduled work-over program during which the well bore are acidized and re-perforated to remove wellbore damage induced by the poor water quality. Improving the quality of treated oil and disposal water will reduced the rate of plugging of the disposal wells and sustain the maximum operation requirement for the plant. Traditionally, the practice has always been to select oil field chemicals based on their individual purpose and performance. Within the paradigm, the industry’s facility engineering group (whose primary responsibility is to oversee the integrity of facilities) generally selects corrosion inhibitors based on their protective efficiency while the production operation team (whose goal is to get the best quality of crude oil to the market) typically selects the best emulsion treating chemicals or demulsifier that suits their needs. The tendency has always been for these groups to operate independently of each other

SPE 154099 3

The initiation of OFC Synergy is designed to shift the paradigm of both teams and lead to a better way of effectively deploying oil field chemicals, in such a way as to reduce the total transaction and ownership cost as well as adequately mitigates corrosion in the system and reduces the oil in water content in the produced water system.

Introduction This field study to synergize the use of corrosion inhibitor and demulsifiers was initiated in order to enhance the performance and optimize the cost of Oil Field Chemical (OFC) treatment at Safaniya Arab Heavy Wet Crude Handling Facilities. The principle that led to the initiation of the project is based on the properties of both corrosion inhibitors and demulsifiers. The objectives of OFC Synergy was to select a better way of deploying oil field chemicals (corrosion inhibitors and demulsifiers) that are currently used at Safaniya Arab Heavy wet crude handling facilities in such a way as to improve the corrosion mitigation process and reduce the total cost of chemical treatment.

Description of the Facility

Safaniya Plant 369 Arab Heavy Wet crude Handling Facilities is an onshore GOSP or central production facility that receives and process approximately nine hundred thousand (900,000 bbl.) of wet crude from Safaniya offshore platforms; SG-4, STPs 3, 7, 17 and 18. The crude contains approximately 16% formation water and nearly 5% mole volume of carbon dioxide. The produced water separated from the crude contains 15 – 100 mg/l of suspended solids and the crude contains approximately 30 mg/l of suspended solids. The carbon dioxide content present in the system tends to reduce the pH of the system to less than 5 which makes the system corrosive. An emulsion breaker and corrosion inhibitor are injected upstream the Low Pressure Production Trap (LPPT). During normal operating conditions, the concentrations of these chemicals are in a range of 20 ppm for the corrosion inhibitor and 15-28 ppm for the emulsion breaker. The plant consists of two LPPT that are used to separate the gas from the crude oil (see flow diagram below). Gas separation is achieved by reducing the incoming crude pressure from 300 to 68 psi. The separated gas is routed to the gas facilities for subsequent treatment and dehydration. As the wet crude flows into the two spheroids, additional gas is separated and it’s transferred to the gas treating facilities. While in the spheroid, the crude forms two layers, an oil layer and formation water layer and the two layers are separated by an emulsion layer. Free water containing some emulsion and solids is pumped into the Corrugated Plates Interceptor (CPI) whereas the crude is pumped through the heat exchangers and heated to 145

oF-155

oF prior to desalting. The pressure is further reduced to less than 5 psi in the flash drum before the

crude is pumped to the desalting trains.

Complete oil-water and desalting of the crude takes place at the desalters. Fresh or sweet water from the Safaniya Utility Plant is used to wash and desalt the crude. The dehydrated crude oil is pumped through the heat exchangers and cooled to approximately 130

oF prior to storage and shipment. The produced water from the

desalting trains is routed to the CPIs for treated and stored in the formation water tank for subsequent injection into the disposable waste or produced water wells.

Statement of Synergy Synergy is created when the component of a system work together to create an outcome that is in some way of more value than the total of what the individual inputs. The whole should be greater than the sum of the individual parts. And in this particular case, the whole cost of synergizing the OFC chemicals should be lower than the cost of using the individual chemicals and the performance of the synergized chemicals should be more effective than when the individual chemical are deployed. The intentional introduction of this innovative idea upstream the production facility of the oil and gas industry should result to significantly benefit to oil and gas extraction organizations as a whole.

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OFC SYNERGY DEFINITION

SPE 154099 5

Principles of OFC Synergy The principle that led to the initiation of the project is based on the properties of both corrosion inhibitors and demulsifiers. Corrosion inhibitors typically consist of active inhibitor species taken up in appropriate solvent and some surfactant. The solvent will confer the desired solubility or dispersibility required for effective inhibitor deployment and surfactant will modifies the interfacial properties of the fluid which will affect partitioning behavior. Demulsifier or emulsion breaker is blend of surfactant compounds in a suitable solvent. Properly selected of both corrosion inhibitors and demulsifier based on this principle will greatly enhance the oil treatment process and reduce the total cost of oil field chemical treatment.

Description of Synergy

In an effort to enhance the performance of oil field chemical and reduce the total cost of the chemicals, oil field chemicals including corrosion inhibitor, emulsion treating chemical or emulsion breaker, scale inhibitor and oxygen scavenger were selected and deployed in an upstream oil and gas treating facility. The selection was based on the properties of oil field treating chemicals and the wet crude system. Two of chemicals (corrosion inhibitor & emulsion breaker) were found to complement each other since both chemicals contain some surfactant and aromatic solvent. The selected corrosion inhibitor possesses a demulsifier package which gives it some emulsion treating characteristics. The aromatic solvent and surfactant component that are present partially help to treat the emulsion in the wet crude and thus complement the function of the emulsion breaker. The desalting ability of the emulsion breaker in turn reduces the amount of salt and solid in the system resulting in a reduction of corrosiveness in the system. This synergetic or complementary action results in a cost effective emulsion treatment of the crude oil and the effective corrosion mitigation in the produced or waste water system. The surfactants present in both chemicals will improve the performance of the corrosion inhibitor by enhancing the adsorption of the active species of the corrosion inhibitor at the metal surface and leads to the formation of a hydrophobic monolayer. Nonionic surfactant, acts by incorporating the inhibitor into the micelles, which themselves adsorb on the steel surface and facilitate the attachment of other active species.

Objectives The objectives of the synergy process is to show that selecting oil field chemical based on their properties and matching these properties to that of the system will enhance the performance and lower the cost of using the chemicals. And subsequently, synergizing of oil field chemical should result in the recovering of crude oil from waste water intended for disposal. The whole cost of synergizing the chemicals should be lower than the cost of using the individual chemicals is the principal outcome envisage.

Strategy and Techniques The strategy is to show that synergizing OFC will enhance the performance and optimize the cost of chemicals used in treating wet crude in a production facility, the whole is greater the sum of the individual components. Synergizing of the oil field chemicals should result in the following:

Total chemical treating cost savings.

Better treatment of the produced water.

Cost effective corrosion mitigation at the wet crude handling system.

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Methodology In order to evaluate the cost effectiveness of the innovative process, the total cost for the oil field chemicals (Emulsion Breaker and Corrosion Inhibitor) that were used before and during project has been compared. The oil in water content in the produced water before and during the project has been used to estimate the volume of oil reclaimed and the average corrosion rates before and during synergy has also been used to assess the effective mitigation of corrosion in the system. Daily chemical consumption rates and the cost of each chemical were used in calculating the cost of chemicals used per month before and during synergy. Oil in water content from daily production reports were used to determine amount of oil recovered from produced or waste water. And corrosion rates from Linear Polarization probes or L.P.R. probes and Electrical Resistance probes or E.R Probes were used to evaluate the efficiency of the treatment before and during synergy.

Compatibility Test Initially, compatibility test was conducted by placing 30 ml of untreated produced water sample into seven sets of labeled 6-oz prescription bottles, and the bottles were topped to the 100 mark with untreated production that was freshly collected from incoming production line. No chemical was added to the first set of bottles and was considered as the blank or control, 0.2 ml of corrosion inhibitor was added into the second set, the third set was treated with 0.2 ml of emulsion breaker and the fourth set was treated with 0.2 ml scale inhibitor, the fifth set with 0.2 ml the emulsion breaker. The fifth was treated with 0.2 ml of emulsion breaker and 0.2 ml scale inhibitor, the sixth set with 0.2 emulsion breaker and 0.2 ml corrosion inhibitor and the seventh and final set was treated with 0.2 ml of emulsion breaker, 0.2 ml of scale inhibitor and 0.2 ml of corrosion inhibitor. The seven sets were capped and then vigorously shaken 50 times in order to mix the contents. The sets of bottles were set aside and the water dropout rate was observed (the time it takes the water to separate from the oil phase). The bottles were also observed for foaming and emulsion tendency and the rate of water drop out at a constant time interval was then recorded. When the water dropout was completed, a sample of the oil layer is obtained and centrifuged to determine the quantity of water, emulsion and solids remaining in the oil after the free water has dropout. The temperature of the test bottles were maintained close to that of the incoming production fluid by heating the bottles in a water bath and the temperature of the bath was maintained at 120

oF. This served as a control and standardized so that the

results are as reproducible as possible and more representative.

Time Minutes

Blank Water Vol.

(ml)

Corrosion Inhib (CI)

Water Vol. (ml)

Scale Inhibitor (SI) Water Vol.

(ml)

Demulsifier (D)

Water Vol. (ml)

CI + D SI + D CI+SI+D

1 Traces Traces Traces Traces 20 Traces Traces

3 Traces 3.0 05 15 30 Traces 10

5 0.1 25 07 20 30 Traces 15

7 0.1 27 10 25 35 0.1 20

10 0.2 30 10 30 37 0.2 22

Bottle test results for corrosion inhibitor, scale inhibitor and emulsion breaker.

SPE 154099 7

Field Application and Deployment Strategy

Based on the laboratory bottle initially conducted, Safaniya operation team requested 9000 gallons of the corrosion inhibitor and topped the day tank. The chemical injection points for corrosion inhibitor and emulsion breaker injection pumps were relocated from the draw-off pumps to upstream the production traps and the pumps were primed and checked for calibration. All corrosion inhibitors injection pumps were stopped for five days in order to collect bas-line data. The demulsifier injection rate was varied to meet with the BS&W and salt content of the processed crude and highest injection rate was recorded. And the scale inhibitor injection points were relocated from the production trap to the draw-off pumps. The corrosion inhibitor injection pumps were adjusted to 850 GPD and the injection of the inhibitor was re-established. Crude sample were collected every three hours and analyzed for BS&W and salt content (see table of field data attached). The demulsifier injection rates was initially reduced by 50 GPD as per the field application procedure but was later modified by operations to 50 GPD reduction every 6 hours instead of every 24 hours. The impact of the drastic change was observed after the third day and it was agreed to return to the initial reduction rate of 50 GPD every 24 hours. The corrosion rates of the produced water system were monitored using LPR- probes before and during the field trial. The corrosion rates results were compare before and during the OFC Synergy field trial.

Discussion

Analytical results from the corrosion monitoring LPR – probe downstream formation water tank at the Arab Heavy wet crude handling facilities indicated that the average corrosion rates during the synergy were lower than those before. Approximately 99.6 percent inhibitive efficient was observed with the increase in the injection rate of the corrosion inhibitor. The increase in the injection rate of the corrosion inhibitor resulted in the formation of a persistent corrosion inhibitor protective film and a big drop in the corrosion rates; from 290 mpy to 1.1 mpy and thus a better protection of the system. The reduction in corrosion rates also confirmed that oxygen scavenger is not needed to control corrosion in the system. The cost of the corrosion inhibitor is $4/gal compared to $13/gal, the cost of the demulsifier. Increasing the injection rates of both corrosion inhibitors and reducing that of the demulsifier effectively reduced the chemical treatment cost. The corrosion rates were monitored on daily basis using online Linear Polarization corrosion probes “LPR” probes, Electrical Resistance corrosion probes “ER” probes and corrosion coupons located both in the wet crude treating facilities and the produced water system. The corrosion rates results before and after synergy, were then compared and results were used to evaluate the protective efficiency of the innovative process (see appendix for graph of corrosion rates). Daily chemical injection rates were checked and recorded in the daily production report. Daily analysis of salt in oil content, oil in water content and water cut or BS&W was also carried by the laboratory technician. The treating vessels were surveyed for forming and emulsion tendency and the observation were recorded by the operation team on the daily report. Iron count measurement and corrosion inhibitor residual test were carried out twice a day by the laboratory technician and the chemical vendor local representative. The results were tabulated. A correlation between the concentrations of the corrosion inhibitor injected, corrosion inhibitor residual concentration and the iron count from both the oil and produced facilities was established.

Results and Interpretation

Results from the initial laboratory bottle test indicated that treating the wet crude with the corrosion inhibitor partially treated the emulsion in the crude resulting in some of the free water dropping out. The addition of 0.2 ml of the emulsion breaker resulted in the free water separating completely from the wet crude. This is an indication

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that the volume of the emulsion breaker required for treating emulsion in the system could be significantly reduced and subsequently the cost of the emulsion breaker. Comparing the monthly average corrosion rates before and after the synergy showed that the average corrosion rates during synergy were lower than the rates before synergy and thus the system was effectively corrosion mitigation during synergy (see graph 1 of average corrosion rates). Maintaining the corrosion rates to less than 3.0 mpy as per the company’s standard will results in a cost an effective operation of the facility since this will reduce the shut-in time and repairs associated with corrosion failure. The oil in water content for the month of June and July which falls before synergy is greater than that of the month August and September which is when synergy was carried out (see appendices graph 2 for oil in water content). Improving the quality of the disposal water will subsequently reduce the shut-in time required to restore the injectivity into the injection wells. It will also reduce the cost for work-over and/or stimulation (downhole acid cleaning of the injection tubing) of the wells, maintain the maximum operation of the plant and eliminate the need to drill additional water wells to meet the requirement for wastewater disposal. The total cost of deploying the chemicals before and after the synergy also indicates that it is cheaper or cost effective synergizing the chemicals. Approximately 45 percent total cost saving was realized during the oil field chemical synergy. By properly selecting OFC chemicals based on their properties and the chemistry of the system, the performances of the chemical were greatly enhanced. The total transaction and ownership cost of ownership has been reduced, crude oil has recovered from waste water intended for disposal and corrosion mitigation in the wet crude handling facility was enhanced. The whole cost of synergizing the chemicals is lower than the cost of using the individual chemicals.

Results and recommendation

Results

Demulsifier consumption rates was reduced by 45% Total chemical cost saving of $2MM/Year High corrosion mitigation efficiency rate of 99.6% (290 mpy to 1.1 mpy).

Recommendations

Continue the injection CORTON AR-505 corrosion inhibitor at 20 ppm based on total fluid. Discontinue the injection of oxygen scavenger into the formation water system. Establish an online corrosion monitoring downstream the formation water tank Provide chemical injection pump(s) with a total pumping capacity to inject 250 – 350 gpd of corrosion

inhibitor Establish OFC synergy as Best Practice.

Conclusion The Synergizing of Oil Field Chemicals (corrosion inhibitor and demulsifier) Upstream Arab Heavy Wet Crude handling Facilities has resulted in chemical treatment cost saving, better treatment of produced water and effective corrosion mitigation in the system. Comparing the results before and during the testing indicates a total chemical treatment cost savings greater than 2.MM per year and improved corrosion mitigation efficiency of 99.6%. This high efficiency in corrosion mitigation has proven that the injection of oxygen scavenger is not necessary.

SPE 154099 9

Table 1

OFC CHEMICALS COST SAVINGS CALCULATION

Before

Gallons/Day

Demulsifier $

12.77 947 $

12,093.19

Corrosion $

3.95 140 $

553.00 10 PPM based on formation water

Oxygen Scav

$ 17.00 207.9

$ 3,534.30

20 PPM in GOSP + 10 PPM in G26U

TOTAL

$ 16,180.49

Total Per Day at 165 MBD Formation Water

Yearly

$ 5,905,878.85

After

Gallons/Day

Demulsifier $

12.77 595 $

7598.15 Corrosion

Inhibitor $

3.95 875 $

3,456.25 20 PPM based on Total Fluid Oxygen

Scavenger $

17.00 0 $ - No Injection is needed

TOTAL $

11,054.40

Yearly

$ 4,034,856.00

Difference/Yr

$ 1,871,022.85

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Table 2

Field Demulsifier Consumption Table

Date AH Total Avg.

MBOD Demulsifier

GPD Demulsifier

PPM Crude Salt Content

(PTB)

31 July, 2010 813 948 23.2 9

1 August, 2010 799 896 22.3 7

2 August,2010 757 732 19.6 7

3 August, 2010 730 562 15.2 8

4 August, 2010 727 702 18.8 9

5 August, 2010 741 702 18.4 8

6 August, 2010 701 650 18.0 7

7 August, 2010 760 655 16.9 8

8 August, 2010 777 655 16.5 9

9 August, 2010 722 625 16.8 8

10 August, 2010 724 595 15.9 8

11 August, 2010 749 595 15.5 8

12 August, 2010 745 595 15.6 8

13 August, 2010 744 595 15.6 9

14 August, 2010 754 595 15.3 9

15 August, 2010 743 595 15.2 8

16 August, 2010 762 595 14.8 8

17 August, 2010 746 595 14.5 8

SPE 154099 11

Bottles Results Graph

Blank

SI

CI+DEM

0

5

10

15

20

25

30

35

40

1 3 5 7 912

1518

Vol. m

l

Time (Minutes)

Blank CI SI DEM CI+DEM

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LPR – Average Corrosion Rates

MPY

12

34

5

290

35.6

11.6 11.2

1.1

MPY

WEEKS

SPE 154099 13

Chemical Cost Graph

Befor

e

After

DemulsifierCorrosion Inhibitor

Oxygen Scavenger

0

Before After

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Safaniya Plant 369 Flow Diagram

Inj.

Po

int

G-1

56

A

/B/C

Inj.

Po

int

G-3

A/B