spe summaries

• SUMMARY OF BLOCKING GEL PAPER IADC.SPE 72291 • SUMMARY OF BLOCKING GEL PAPER SPE 68975 • SUMMARY OF BLOCKING GEL PAPER SPE 81441 • SUMMARY OF BLOCKING GEL PAPER SPE 86547 • SUMMARY OF BLOCKING GEL PAPER SPE 99729 • SUMMARY OF CARBONATE CEA PAPER 65355 • SUMMARY OF CARBONATE PAPER PUBLISHED 65068 • SUMMARY OF CARBONATE ACIDIZING ENGINEERING PAPER IPTC 10697 • SUMMARY OF CARBONATE PAPER NIF_00 SYMMETRY OF ACID

WORMHOLING • SUMMARY OF CARBONATE PAPER NIF 00 UNDERSTANDING FINITE

REACTIVITY • SUMMARY OF CARBONATE PAPER SPE 54719 • SUMMARY OF CARBONATE_ZCA PAPER SPE 58804 • SUMMARY OF CARBONATE_ZCA PAPER SPE/IADC 85337 • SUMMARY OF CONFORMANCE PAPER SPE 81447 • SUMMARY OF CORROSION FORMIC DECOMPOSITION PAPER SPE 106185 • SUMMARY OF CORROSION HAI303_HII600 NACE PAPER 06482 • SUMMARY OF CORROSION INHIBITOR ANN NACE PAPER H03166 • SUMMARY OF DIAGNOSTIC PROCESS ENHANCES GAS STORAGE

DELIVERABILITY SPE 51039 • SUMMARY OF FORMICHCL PAPER SPE 103978 • SUMMARY OF FORMICHCl PAPER SPE 78557 • SUMMARY OF GAS STORAGE WELL STIMULATION PAPER SPE 65636 • SUMMARY OF GUIDON AGS PAPER 107584 • SUMMARY OF GUIDON AGS MEXICO PAPER • SUMMARY OF GUIDON AGS PAPER 103771 • SUMMARY OF GUIDON AGS PAPER 106951 • SUMMARY OF GUIDON PAPER SPE 89413 • SUMMARY OF GUIDON AGS PAPER SPE 109714 • SUMMARY OF GUIDON AGS ARTICLE • Summary of Power Safe D Paper SPE 81732 • SUMMARY OF POWER SAFE D PAPER SPE 104119 • SUMMARY OF PULSONIX PAPER SPE 89653 • SUMMARY OF PULSONIX SS2000 PAPER SPE 93071 • SUMMARY OF PULSONIX SS2000 PAPER SPE 93987 • SUMMARY OF SCALE INHIBITION PAPER NIF_01_SCALE_DESORB • SUMMARY OF SCALE INHIBITION PAPER NIF_01_SCALE_ISOTHERM • SUMMARY OF SCALE INHIBITION PAPER NIF_02_LAB_SQUEEZE • SUMMARY OF SCALE INHIBITION PAPER SPE 94510 • SUMMARY OF SCALE INHIBITION PAPER SPE 95088 • SUMMARY OF SCALE INHIBITOR PLACEMENT PAPER SPE 107801 • SUMMARY OF SCALE REMOVAL PAPER (VISCOSIFIED) SPE 90359 • SUMMARY OF SGA7 PAPER SPE 107687 • SUMMARY OF STIM 2001 PAPER SPE 63179 • SUMMARY OF STIM 2001 PAPER SPE 82261 • SUMMARY OF STIM 2001 PAPER SPE 94695 • SUMMARY OF STIM 2001 PAPER SPE 96892 • SUMMARY OF STIM 2001 PAPER SPE 102412 • SUMMARY OF STIM 2001BIOVERT PAPER SPE 102606 • SUMMARY OF STIMWATCH PAPER SPE 100617 • SUMMARY OF STIMWATCH PAPER SPE 107775 • SUMMARY OF STIMWATCH PAPER SPE 110707 • SUMMARY OF SURGIFRAC PAPER SPE 71692

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SUMMARY OF GAS STORAGE WELL STIMULATION PAPER SPE 65636

TITLE Optimizing Deliverability in Five GasStorage ReservoirsCase Studies

AUTHORS John Guoynes, Ken Squire, Matt Blauch, Valerie Yeager, Halliburton Energy Services, Inc., John Yater, Robert Wallace, Russell Frame, Randall Clark, Kinder Morgan, Kinder Morgan, Inc.

PRESENTATION or

PUBLICATION INFORMATION

2000 SPE Eastern Regional Meeting, Held in Morgantown, West Virginia, 1719 October 2000

SUMMARY OF

PAPER

This paper illustrates case studies using “SolutionTeam” a multidisciplined team process, in which over 75 wells were diagnosed and treated successfully. Rigorous damageidentification techniques and reservoir quality diagnostics were used in the five gasstorage reservoirs. This paper also demonstrates how an effective diagnostic and ranking process can be used to tailor a well treatment that can optimize deliverability enhancement. Damage in each well was quantified using well test analysis and historical injection/withdrawal cycle performance matching. Log analysis, petrophysical data, geological data, wellbore imaging, and workover historical data were also gathered as treatment–design criteria. The deliverability improvement was quantified for each well using post treatment diagnostics. The posttreatment evaluations were updated with 1 and 2year followup evaluations. Well test analysis was used to evaluate reservoir properties and the degree of damage so wells could be ranked and the candidates selected based on their potential for deliverability improvement. Pretreatment damage diagnostic techniques such as downhole sampling, downhole video, gammaray/neutron(GR/N) log were employed to identify and rank wells based on the degree of damage mechanism identified in the well test analysis. Laboratory tests such as xray diffraction of samples indicated presence of typical formation fines such as quartz, calcite, illite, barite, gypsum, iron sulphide. Infrared analysis of samples indicated presence of corrosion inhibitors, hydrocarbon oils, aromatics, moderate amounts of ethoxylate and ethoxylated aliphatic and a small amount of ester. Comparison of absoluteopenflow (AOF) potential of a well before and after treatment was made to measure the productivity achieved following a treatment. After the pretreatment analysis was completed, the wells were ranked based on the degree of damage and the reservoir

flow capacity using the deliverability index. Case study 1 incorporates highpressure jetting, tailored acidizing, and hydraulic fracturing techniques used in a deep highpermeability pressuredrive carbonate reservoir. Case study 2 includes highpressure jetting and damagespecific fluid treatments in two shallow waterdrive clastic reservoirs. Case study 3 incorporates hydraulic fracturing and highpressure jetting of a shallow highpermeability pressuredrive clastic reservoir. Case study 4 incorporates highpressure jetting with foamed chemical treatments in a converted oilcarbonate reservoir. Tailored stimulation techniques in the four case studies included coiled tubing, highpressure wellbore sterilization jetting, various tailored chemical treatments, and hydraulic fracture stimulation. Study in this paper demonstrates that diagnostic process should be applied on a wellbywell basis to adequately develop a treatment strategy and further new well testing methods demonstrate the relationship between the physical cause of formation damage and the degree to which the identified mechanisms impair deliverability. Also, the wide range of damage mechanisms, and the fact that these mechanisms vary from well to well, indicates the need for custom treatments based on accurate identification of damage mechanisms.

HALLIBURTON TRADE NAME USED IN PAPER

Name: Primary Application:

TYPE OF

CONTENT

þ Case History þ Laboratory Study Background Research Review Field Study Comparison to competitor product Name of competitor and product:

OPPORTUNITIES FOR OTHER PSL’s Coiled Tubing

IMPORTANT REFERENCES

3. Blauch, M.E. et al.: “Diagnostic Process Enhances Gas Storage DeliverabilityA Case Study,” Paper SPE 51039 presented at the 1998 SPE Eastern Regional Conference and Exhibition held in Pittsburgh, Nov. 911

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SUMMARY OF GUIDON AGS PAPER 107584

TITLE Relative Permeability Modifiers and Their Use in Acid Stimulation in HPHT LowPermeability Carbonate Formations: Offshore Mexico Cases

AUTHORS Eduardo Soriano Duverney, Fernando Robles, Halliburton; Antonio Inda Lopez, Octavio Steffani, PEMEX

PRESENTATION or


2007 SPE Latin American and Caribbean Petroleum Engineering Conference held in Buenos Aires, Argentina, 15–18 April 2007.

SUMMARY OF

PAPER

Successful acid stimulation requires a method for diverting an acid across the entire hydrocarbonproducing zone. Because most producing wells are not homogeneous and contain sections of varying permeability, being able to completely acidize the interval is a major problem. This paper describes the use of a new lowviscosity system that uses a relative permeability modifier (RPM) that diverts acid from highpermeability zones to lowerpermeability zones and inherently reduces formation permeability to water with little effect on hydrocarbon permeability. Associative polymer (AP) technology involving the application of a hydrophobically modified water soluble polymer is used for the system. First the laboratory results of a previous publication using this system are summarized. Acid diversion testing was done in that work using single and parallel core assembly. Sandstone, Berea and Bedford limestone cores were used for the tests. The results of these tests illustrated that the AP is capable of providing diversion from a watersaturated core to oil – saturated core and is also capable of providing significant permeability reduction to the watersaturated core. In a singlecore test, it appeared that the acid diversion could be obtained up to at least 350ºF. This assumption is demonstrated in the field results presented in this paper. RPM system has been used effectively offshore Mexico with success for more than two years. The cases presented in this paper show the first application in a lowpermeability carbonate formation where oil production was increased significantly compared to previous traditional acid treatments using conventional diverters. Cases from three fields are presented in this paper. In the first case, the BHST was 302ºF and porosity was between 9 and 10%. Oil production was improved after the treatment and produced 9,700 BOPD with a drawdown pressure of only 213 psi. The water cut reduced from 14% to 1%. In the second case, one well had the BHST 320ºF and average porosity 11%. After the treatment, the increase in production was around 600 BOPD with a drawdown pressure of 400 psi. The second well had BHST 323ºF and average porosity 910%. After the treatment the oil rate increased from 7,166 BOPD to 10,067 BOPD

whereas the drawdown pressure decreased from 3,991 to 3,460 psi using a choke size of 1 in. In the third case, the well had BHST 275ºF and average porosity 8%. The production increased from 2,500 BOPD to 5,192 BOPD after the treatment. One important feature of this work is that the downhole conditions were highpressure/hightemperature (HPHT). Details from the jobs using this new RPM aciddiversion system, are presented showing pre and postjob production results.


Name: Guidon AGS

Primary Application: Acid diversion

TYPE OF

CONTENT

þ Case History Laboratory Study Background Research Review Comparison to competitor product Name of competitor and product: Not mentioned

OPPORTUNITIES FOR OTHER PSL’s Conformance Control


1. Eoff, L., et al.: “Development of a Hydrophobically Modified WaterSoluble Polymer as a Selective Bullhead System for Water Production Problems,” paper SPE 80206

2. Eoff, L., et al.: “Development of Associative Polymer Technology for Acid Diversion in Sandstone and Carbonate Lithology,” paper SPE 89413

3. Hernandez, R.G.: “A New Method for Acid Stimulation without Increasing Water Production: Case Studies from Offshore Mexico,” paper SPE 103771

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SUMMARY OF SURGIFRAC PAPER SPE 71692

TITLE Successful Hydrajet Acid Squeeze and Multifracture Acid Treatments in Horizontal Open Holes Using Dynamic Diversion Process and Downhole Mixing

AUTHORS

M. J. Rees and A. Khallad, PetroCanada Oil and Gas, A.Cheng, K. A. Rispler, J. B. Surjaatmadja, and B.W. McDaniel, Halliburton Energy Services, Inc.

PRESENTATION or


SPE Annual Technology Conference, New Orleans, September 30, 2001

SUMMARY OF

PAPER

Effective stimulation of wells with long, openhole horizontal completions is generally considered a difficult task, especially in lowpermeability carbonate reservoirs that require deep penetration with live acid. Successful acid treatments in wells with long openhole wellbores depend on the following conditions: • Live acid reaches the desired location along the wellbore. • Live acid reaches far into the formation for adequate etching or wormholing to achieve sufficient nearwellbore or fracture conductivity. • Isolating procedures are used to ensure that the acid is only placed within the target area. A relatively new hydrajet fracturing process has been suggested to achieve these goals. The process can be used in two ways: (1) dynamic fluid energy is used to divert flow into a specific fracture entry point to initiate a fracture at the intended location with live acid directed into this fracture plane, (2) highpressure downhole mixing is used to create foam for highintensity acid squeezes. This technique typically uses two independent fluid streams, one in the treating string and another in the annulus. The two fluids (if dissimilar) are mixed downhole at a tremendously high energy to form a homogenous mixture. Various methods for placing acid in an openhole (horizontal) wellbore such as pumping through casing, spot placement, washing, squeezing, hydrajet squeezing and fracture acidizing are described. Reasons for various production deficiencies and treatment options are also described. This paper also discusses and compares the results of conventional acid treatments with various styles of hydrajet fracture acidizing

treatments performed in seven openhole horizontal wells (Wells A, B, C, D, E, F and G) within two different areas of the same formation. The novel use of the downhole mixing feature is also discussed. Wells A, B, E, F, and G are located in an area of the formation that has lower porosity, lower effective permeability, and fracturing throughout the wellbore. Wells C and D are located in an area of formation that has higher porosity and less fracturing than rest of the wells. A careful study of production problems to determine the best and most economical solution for a particular well should guide the choice of treatment method. A wash alone, which is the simplest solution to apply, produced positive results in Well A, possibly because of the high quality of the reservoir in which this well is located. Generally, a horizontal well in this formation requires more than a simple wash to increase and sustain production. This is shown with the improvements exhibited by Well B. The formation fracturing in Wells C and D allowed successful use of the hydrajet fracturing technique. The hydrajet squeeze technique used in Wells E, F, and G effectively increased the production rates to unexpectedly high levels. Overall, the hydrajet stimulation technique has worked effectively when applied to appropriate candidate wells.

HALLIBURTON TRADE NAME USED

IN PAPER

Name: SurgiFrac or SurgiFrac NWB Primary Application: Acid Fracture Stimulation

TYPE OF

CONTENT

Case History Laboratory Study

Background Research Review

Comparison to competitor product

Name of competitor and product: n/a



(1) Surjaatmadja, J.B., Grundmann, S.R., McDaniel, B.W., Deeg, W.F.J., Brumley, J.L., and Swor, L.C.: “Hydrajet Fracturing: An Effective Method for Placing Many Fractures in Openhole Horizontal Wells,” paper SPE 48856 presented at the 1998 SPE International Conference and Exhibition, Beijing, China, November 26.

(2) Love, T.G., McCarty, R.A., Surjaatmadja, J.B., Chambers, R.W., and Grundmann, S.R.: “Selectively

!

!

Placing Many Fractures in Openhole Horizontal Wells Improves Production,” paper SPE 50422 presented at the 1998 SPE/CIM International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, November 14.

(3) Eberhard, M.J., Surjaatmadja, J.B., Peterson, E.M., Lockman, R.R., and Grundmann, S.R.: “Precise Fracture Initiation Using Dynamic Fluid Movement Allows Effective Fracture Development in Deviated Wellbores,” paper SPE 62889 presented at the 2000 SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 14.

(4) U.S. Patent 5765642: “Subterranean Formation Fracturing Methods,” June 1, 1998.

(5) Patent Pending, “Process for generating Fracturing foam downhole using the SurgiFrac and Other Jetting Processes.”

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SUMMARY OF BLOCKING GEL PAPER IADC.SPE 72291

TITLE

Isolation of a Horizontal Hole Section in an Openhole Well Using a NonDamaging Temporary Gel Plug to Facilitate Hydrocarbon Production from the Remaining Lateral Section A Case History from Kuwait.

AUTHORS Mohammed R. Khater, Saudi Arabian Texaco Inc., Shahab Uddin and Jamal A. AlRubaiyea, Kuwait Oil Co., Ashish R. Rai, Halliburton Overseas Ltd. Kuwait, Naz Gazi, Halliburton Energy Services, Inc.

PRESENTATION or


IADC/SPE Middle East Drilling Technology held in Bahrain, 22–24 October 2001.

SUMMARY OF

PAPER

This paper describes the application of a nondamaging temporary gel system to isolate a part of a horizontal section in an openhole well. The purpose of this application was to provide a cost effective method of isolating a high water saturated zone of the extended lateral to facilitate the production of hydrocarbon from the rest of the open hole. The candidate well (R91) selected for this application was the first extended lateral horizontal well (3000ft lateral section) drilled as a producer. The well was to be converted to an injector at a later time. Logging while drilling (LWD) was performed during the drilling phase of this well, and a low resistivity section was identified along the horizontal lateral. On completion of the drilling, a well test was performed, indicating a high water cut. It was suspected that this water was being produced from this low resistivity section along the lateral hole. An economical method for confirming and isolating the source of this water influx was needed. Since this was a low pressure well, an electric submersible pump (ESP) for production had been used. Since lowpressure wells were the norm for this field, ESP completions were commonplace. Different techniques, including use of drillpipe conveyed or coiledtubingconveyed production logging tool (PLT) were also considered. The nondamaging gel plug placed across the low resistivity section of open hole with coiledtubing allowed the operator to identify and confirm the source of water. The gel plug formed a barrier across this zone, thereby restricting and reducing the water influx. Presence of a natural fracture was also identified during the drilling phase, and hence, communication between the low resistivity interval with the oil zone towards the heel of the lateral section was confirmed. Due to nonavailability of certain logging tools at the time of requirement along with high costs of using such tools, the proposed gel technique was used as an alternative option. Being a non damaging pill with greater than 99% regained permeability after

cleanup, the well could safely be isolated with this technique. The pill would be dissolved with acid at a later stage when required. The operator’s objective of drilling this well to initially produce as much oil as possible, and then, at a later stage to convert it into an injector to improve the sweep efficiency in the area was achieved as a result of the application of this technique. This gel polymer had been prepared by grafting crosslinkable sites onto an HEC backbone. The polymer can be transformed into a rigid, crosslinked gel by adjustment of the pH of the solution from acidic to slightly basic through the use of nontoxic crosslinkers without using multivalent metals. This technique was limited to wellbore isolation only, and hence, any fracture communication in the reservoir (outside the wellbore) could not be affected.


Name: K MAX. Primary Application: Near wellbore isolation non damaging pill.

TYPE OF

CONTENT

þ Case History Laboratory Study þ Background Research Review Comparison to competitor product þ Field Study Name of competitor and product: HT Pill (BJ).



1. Blauch, M. E., Broussard, G. L., Sanclemente, L.A., Weaver, J. D. and Pace, J. R.: “Fluid Loss Control Using CrosslinkabIe HEC in HighPermeability Offshore FlexureTrend Completions,” paper SPE 19752, presented at the 65th Annual SPE Technical Conference, San Antonio, TX. October 811, 1989. 2. Holmes, R. E., and Sandy, J. M.: “A New Crosslinkable HECits Application in Conipietieii Work; 6th Offshore Southeast Asia Conference, Singapore, February 1986. 3. Himes, R. E. Ali, S. A., Hardy, M. A., Holtmyer, M. D., and Weaver, J. D.: “Reversible, Crosslinkable Polymer for Fluid Loss Control” paper SPE 27373, presented at the Formation Damage Control Symposium, Lafayette, LA, February 910, 1994. 4. Cole, R.C., Foley, K.A., Ali, S.A., “A New Environmentally Safe Crosslinked Polymer for FluidLoss Control,” paper SPE 29525, presented at the Production Operations Symposium, Oklahoma City, OK, April 23, 1995.

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SUMMARY OF BLOCKING GEL PAPER SPE 68975

TITLE Polymer Sealant for Unwanted Gas in Openhole GravelPack Completion

AUTHORS T. Bach; K.E. Wennberg (Statoil); A. Mebratu; W.P. Hendriks; J.M. Warren Jr. (Halliburton Energy Services, Inc.); T. Rolfsvaag (Conoco)

PRESENTATION OR


SPE European Formation Damage Conference held in The Hague, The Netherlands 2122 May 2001

SUMMARY OF PAPER

This paper is a joint effort of Statoil, Conoco and Halliburton. In September 1999, Statoil completed Well A–13 in the Åre formation of Heidrun Oilfield with 130m openhole gravel pack. Heidrun is located on the Haltenbanken area of the Norwegian Sea. During lifting the well produced 2000 Sm 3 /day with a high gastooil ratio (GOR) of 700 Sm 3 /Sm 3 . Based on production results from other wells completed in the same layers, GOR of this well was considerably higher than expected, forcing the operator to shut down the well. Free gas was believed to be flowing from gasfilled sand located immediately above the casing shoe. Production analysis indicated a high permeability flow channel between this layer and the upper zone of the gravel pack. This paper describes the well’s gasflow mechanism, the polymer gel systems used for sealing the gasflow zone, the placement technique, and the operational aspects of the selective gas shutoff treatment. The challenges associated with shutting off unwanted gas production in the Åre formation included (1) temporarily protecting the lower portion of the screen section, (2) selecting a permanent chemical/slurry for blocking gas, and (3) designing an effective placement method. A singlephase, twocomponent, waterbased temporary sealant gel with a positive environmental profile proved to be suitable for blocking unwanted gas production. This would allow later treatments for permanently filling all possible flowpaths. The permanent sealant selected for this treatment includes a novel system consisting of a base polymer and an organic crosslinker. The base polymer is a low molecularweight acrylamide copolymer that is crosslinked with an organic crosslinker. The polymer forms strong covalent bonds with the crosslinker, forming a permanent seal in the target zone. Laboratory tests show that the system can be used at temperatures up to 160°C and can provide a 99.9% reduction in permeability to water. Unlike systems formulated from metallic crosslinkers, this system can be pumped deeply into the formation as a thin gel without losing its ability to crosslink. The placement technique chosen had to isolate the lower gravelpacked zone. Engineers could achieve isolation by accurately spotting the temporary gel in the lower section of the well before pulling up and squeezing the permanent sealant into the upper zone. The

treatment was pumped through 2 7/8 in. CT. After the CT was pulled inside the casing shoe, the permanent sealant was squeezed into the Åre 9 and the suspected channel behind the casing. Extensive lab tests and simulations were conducted before the operation to finalize the required strength with minimal chemical concentration. In February 2000, a temporary blocking agent consisting of a crosslinked hydroxypropyl guar polymer was placed in the lower part of gravel pack. Then permanent sealant was injected into gas producing zone. After 72hours coil tubing was used to wash the well. Finally the well was lifted with production gas. The entire operation was completed in a single run with CT. Currently, the well is producing oil at a rate of 350 Sm3/day without any significant free gas.


Name: H2Zero and Temblok 50

Primary Application: Water shut of sealant and Temporary blocking agent

TYPE OF

CONTENT



Comparison to competitor product Field Study

Name of competitor and product: Not mentioned

OPPORTUNITIES FOR OTHER

PSL’s

1] Conformance Control 2] Coiled Tubing


5. Azari, M., Soliman, M., and Gazi, N.: “Reservoir Engineering Applications to Control Excess Water and Gas Production,” paper SPE 37810 presented at the 1997 SPE Middle East Oil Show in Bahrain, March 1518.

6. Soliman, M.Y., and East, L.: “Reservoir Conformance Approach and Management Practices for Improved Recovery Opportunities: Process and Case History,” paper SPE 53918 presented at the 1999 SPE Latin American and Caribbean Petroleum Engineering Conference in Caracas, Venezuela, April 2123.

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TITLE

Successful use of a CostEffective Temporary Non Damaging Gel Plug System to Isolate a Highly Permeable Producing Zone During a Stimulation Job of a Low Permeability GasProducing Zone in Khuff Gas Reservoir in BahrainA Case History

AUTHORS Mohammed Saeed Mirza, Bahrain Petroleum Company; Torsten Kritzler and Naz H. Gazi, Halliburton

PRESENTATION or


SPE 13 th Middle East Oil Show & Conference held in Bahrain, 58 April, 2003.

SUMMARY OF

PAPER

The Khuff formation in Bahrain has been producing for 33 years. Currently gas is being produced from 29 Khuff wells. They consist of 2,100 ft of dolomitized carbonate rocks with thin beds and nodules of anhydrite. To enhance the productivity of the reservoir, a matrix acid stimulation program was undertaken using coiled tubing and a temporary non damaging gel plug system with complete regained permeability to isolate the high permeability producing zone while the lowpermeability gasproducing zone was being stimulated. Because the isolated zone is also producing, the gel system has to be completely non damaging with full regained permeability to this isolated formation. The success of stimulating a lowpermeability interval where a high permeability producing zone is also present is primarily dependent on the ability to divert the respective stimulation fluid into the zone of lower permeability and productivity. Several methods are commonly used to divert the stimulating fluid in the non productive zone. These methods are dependent on the type of stimulation and configuration of the completion. If coiled tubing is used for throughtubing stimulation in cased holes, inflatable packers have limited expansion ratios and pressure capabilities. The previous use of ball sealers gave very limited results of only 10% incremental gas production. This paper presents the successful stimulation techniques and results of a unique and costeffective solution for a well where two intervals with different permeabilities were isolated without the high risks and costs of using a mechanical packer. Coiled tubing was used to stimulate the lower interval while the upper producing interval was isolated using a temporary chemical packers or gel plug. Temperature in this well exceeded 270ºF. A modified HEC polymer is used for this purpose. Because of the polymer’s unique properties, it can be transformed into a rigid, internally crosslinked gel if the pH of the solution is adjusted from

acid to slightly basic through the use of a nontoxic metal oxide crosslinker. No multivalent metal ions are associated with the crosslinking chemistry. The post job gas production of the treated well increased by approximate 50% from 43 MMSCFD to 65 MMSCFD showing positive results from the treatment using this gel plug system.


Name: KMAX Primary Application: Diversion of Matrix Acid Stimulation

TYPE OF

CONTENT

þ Case History Laboratory Study Background Research Review Comparison to competitor product Field Study




1. Cole R.C., Ali, S.A. and Foley K.A. “A New Environmentally Safe Crosslinked Polymer for Fluid –Loss Control” paper SPE 29525 presented at the 1995 Production Operations Symposium, Oklahoma City, Oklahoma, 23 April. 2. Jones A.T., Van der Bas, F. and Hardy B.V. “Gel Plugs for Temporary Isolation in Horizontal Wells Completed with Slotted Liner” paper SPE 38199 presented at the 1997 SPE European Formation Damage Conference The Hague, Netherlands, 23 June.

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TITLE Annular Barrier ReEstablishment Using a LongLife, HighStrength Polymer Gel System

AUTHORS Amare Mebratu, Halliburton; Børge Nerland and Tore Kleppan, BP Norway

PRESENTATION OR


International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, U.S.A., 18–20 February 2004.

SUMMARY OF PAPER

Well A01A in the Valhall field has been on production since late 1993, but its performance has been unstable with proppant and chalk flow back. Mechanical impairments have been repaired, the subsurface safety valve (SSSV) was locked open, and an insert SSSV was installed in May 2001. Although the control line was repeatedly treated with a pressureactivated sealant, leakage has been a recurring problem. Recently, a production tubing annulus communication was detected in Well A 01A. The leak point was believed to be at the seal assembly at the bottom of the production tubing string. The operator and service company engineers evaluated the mechanism of the leak and its severity. In January 2003, 30 bbl of a longlife, highstrength polymer system (HSPS) were placed in the annular space between the 5 ½in. production tubing and 9 5/8in. casing. Applying this polymer system as an annular barrier was a new technique. A temporary gel plug (TGP) consisting of a hydroxy propyl guar polymer and a crosslinker was pumped both ahead and behind the HSPS for placement accuracy and to prevent contamination. Because the well was at low pressure, base oil was used as a displacement fluid. The base oil helped reduce hydrostatic head under placement. The well was kept producing at normal rates during the operation, and pumping was completed within 4 hr with no production loss and no downtime. Annulus pressure was dramatically reduced from 1,300 psi to less than 250 psi. Some pressure increase was observed following well intervention work, but later pressure stabilized at 600 to 700 psi. When the well was shut in, there was no pressure increase observed in the annulus, while the tubing pressure increased from approximately 800 to 2,000 psi. Currently, the well is producing oil at 2,200 BOPD. Stable annulus pressure and normal production performance indicate that the annular gel plug is effectively blocking the communication. The use of this longlife polymer gel plug as an annular barrier is intended to keep the well producing until a tubing work over is possible and a permanent barrier is established. Payback time for the total cost of this operation is approximately four days. The highstrength polymer system is a crosslinkable polymer system that forms a longlife seal at downhole conditions. The system was originally developed to stop or reduce unwanted water or gas production by sealing formation matrices around the interval. HSPS consists of two components: a base polymer and a crosslinker. The base polymer is an acrylamide/acrylate ester copolymer. The copolymer is crosslinked by an organic crosslinker

polyethylene imine. The system has enhanced thermal stability, which forms strong covalent bonds. Because both components are in solution, they need only be diluted in the mixing brine. The two components are placed as a low viscosity fluid (20–50 cp) and form a solid gel when heated to downhole temperatures at predictable times. HSPS has a broad temperature range of 150°F to 320°F (66°C to 160°C). HSPS is stable in both CO2 and H2S. This paper describes the polymer gel systems, placement technique, operational aspects, and benefits of the method used.


Name: H2Zero and Temblok 50

Primary Application: Water shut off chemical sealant Temporary blocking agent

TYPE OF

CONTENT

Case History þ Laboratory Study

þ Background Research Review Comparison to competitor product Name of competitor and product: Not mentioned


PSL’s Conformance Control


1. Urdahl, Hans, et al.: “Experience with Temporary Sealing Leaking Tubing Annuli with ExtendedLife Polymer Gel Plugs in the Greater Ekofisk Area,” paper SPE 24982 presented at the 1992 European Petroleum Conference, Cannes, France, 1618 November.

7. Bach, T. et al.: paper SPE 68975 presented at the 2001 European Formation Damage Conference, The Hague, The Netherlands, 2122 May.

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TITLE How To Apply a Blocking Gel System for Bullhead Selective Water Shutoff: From Laboratory to Field

AUTHORS A. Stavland, Intl. Research Inst. of Stavanger; K. I. Anderson, Sand∅y, and T. Tjomsland, Statoil; and A.A. Mebratu, Halliburton

PRESENTATION OR


The 2006 SPE/DOE Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 2226 April 2006.

SUMMARY OF PAPER

This paper describes a new method for water control by the use of bullhead injection. Normally it is described as Disproportionate Permeability Reduction (DPR) or Relative Permeability Modifier (RPM). DPR is effective in multilayer reservoirs without crossflow and with some zones producing clean oil or in treating coning problems. DPR fluids may be classified as polymer systems, weakly crosslinked gel systems or rigid gel systems. Stavland and Nilsson suggested a general mechanism for DPR where DPR is governed by segregated or preferred flow of oil and water at the pore level. Calculations based on experimental data indicated that the DPR fluid saturation can be used as the controlling parameter rather than the fluid chemistry. The critical task is to control the saturation. In a patent, Stavland and Nilsson suggested injection of the gelant as an emulsion for field application. In this work, a water based gelant is emulsified in oil and injected into the formation. The emulsion is designed to separate into a water phase and an oil phase at static conditions in the formation. Upon reaction in the formation the water phase gels up while the oil phase remains mobile. Both the laboratory and field application results for this emulsified system are presented in this paper. For the laboratory study, a field proven copolymer system of acrylamide and t butyl acrylate crosslinked with polyethylene imine is chosen. This is reported to be stable up to 350ºF (177ºC). Two commercial emulsifiers, one alcohol ethoxylate and one fatty acid amine are selected. Based on availability, safety, viscosity and price, base oil is selected as the oil to use. The gel time and strength were measured by visual inspection of the samples. The core flood experiments were performed in Berea sandstone. In some experiments, parallel core floods were performed. The emulsion separation time is found to increase by increasing the wateroil ratio (WOR) and also by increased oil viscosity. The gelation rate was compared with a reference system where no oil or emulsifier was added to the gelant. Laboratory results showed that for water backflood a stable level in RRFw is rapidly reached. For oil there was a long decline period. The results clearly demonstrate the potential in designing the DPR effect by saturation control. A program was undertaken to verify this DPR method in a field test, using a commercial blocking gel system. For field results, Relative Productivity Index, PIr is selected as a better parameter instead of RRFs. The first treatment was performed in well 30/3A16 T2 at the Statoil operated Veslefrikk field offshore Norway. The pumping operation in the well was executed in

November 23, 2004. Results show that water production was reduced by 30% after the pilot test, while maintaining the oil rate. As expected, total well productivity was reduced by more than 80%. The treatment consisted of 124m 3 emulsion, bullhead from surface. Step rate testing and ion water analysis were combined to study the relative change in flow contribution between the 6 perforated intervals.


Name: H2Zero

Primary Application: Water shut off chemical sealant

TYPE OF

CONTENT

þ Case History þ Laboratory Study

þ Background Research Review Comparison to competitor product Name of competitor and product: Not mentioned


PSL’s Conformance control


7. Liang, J., Sun, H and Seright, R.S.: “Reduction in Oil and Water Permeabilities Using Gels,” paper SPE 24195 presented at the 1992 SPE/DOE Symposium on EOR, Tulsa, OK, April 2224

18. Stavland, A. and Nilsson, S.: “Segregated Flow is the Governing Mechanism of Disproportionate Permeability Reduction in Water and Gas Shutoff,” paper SPE 71510 presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, LA, September 30 – October 3.

22. Stavland, A. and Nilsson, S.: “Emulgert gel,” Norwegian patent No. 310581, 1999

28. Eoff, L. et al.: “Structure and Process Optimization for the use of a Polymeric RelativePermeability Modifier in Conformance Control,” paper SPE 64985 presented at the 2001 SPE International Symposium on Oilfield Chemistry, Houston, TX, February 13–16.

29. Seright, R.S.: ““Clean up” of Oil Zones After a Gel Treatment,” paper SPE 92772 presented at the 2005 SPE International Symposium on Oilfield Chemistry, Houston, TX, February 24.

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SUMMARY OF CARBONATE CEA PAPER 65355

TITLE Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations

AUTHORS M.A. Buijse and M. van Domelen

PRESENTATION or


This paper was revised for publication from paper SPE 39583, presented at the 1998 SPE International Symposium on Formation Damage Control held in Lafayette, Louisiana, 18–19 February.

SUMMARY OF

PAPER

Historically, emulsified acids have primarily been used in fracture acidizing. By combining information from theoretical studies, experimental studies, and field testing, a better understanding has recently been gained of the application of emulsified acids in matrix acidizing. This paper discusses the use of emulsified acid as a stimulation fluid for matrix treatments in heterogeneous carbonate formations. The goal of matrix stimulation of carbonate formations is to decrease skin by creating wormholes and to increase the effective wellbore radius while bypassing damaged areas. The two main challenges that have to be addressed when designing a matrix treatment in a carbonate are acid placement and; acid penetration and optimum wormhole growth. An effective diversion method is essential to help ensure complete zonal coverage and to remove damage from the entire producing interval. In this paper, results of flow tests are presented that compare the efficiency of emulsified acid with that of plain HCl acid. Several emulsified acid systems were tested. The effects of the injection rate, viscosity, and acid/oil volume ratio were analyzed on core samples. Rheological properties and temperature stability (up to 250°F) of the emulsion systems were analyzed by means of Fann50 tests. Emulsified acid systems are effective systems for matrix acidization of heterogeneous formations. The viscosity of the system will improve wellbore coverage and will divert fluid to the lowpermeability and/or damaged sections of the well. The low diffusivity of emulsified acid provides for efficient wormholing at low injection rates. The wormholes are narrow but penetrate deep into the formation. Plain HCl acid reacts fast and does not penetrate deep into the formation at higher temperatures. Short, wide wormholes are generally the result. At low rates, compact dissolution without skin reduction may be the result. Acidinoil emulsions are effective stimulation fluids in large intervals where streaks of high permeability can act as thief zones. This is shown by means of example calculations of the fluid flow and distribution in a well.

WEB LINK


Name: CEA (Carbonate Emulsion Acid) Primary Application: Matrix Acid Stimulation

TYPE OF

CONTENT







8. Buijse, M.A.: ‘‘Understanding Wormholing Mechanisms Can Improve Acid Treatments in Carbonate Formations,’’ paper SPE 38166 presented at the 1997 SPE European Formation Damage Conference, The Hague, The Netherlands, 2–3 June.

9. Jones, A.T., DØvle, M., and Davies, D.R.: ‘‘Using Acids Viscosified With Succinoglycan Could Improve the Efficiency of Matrix Acidizing Treatments,’’ paper SPE 30122 presented at the 1995 SPE European Formation Damage Conference, The Hague, The Netherlands, 15–16 May.

18. Wang, Y., Hill, A.D., and Schechter, R.S.: ‘‘The Optimum Injection Rate for Matrix Acidizing Carbonate Formations,’’ paper SPE 26578 presented at the 1993 SPE Annual Technical Conference and Exhibition, Houston, 3–6 October.

19. Paccaloni, G.: ‘‘A New, Effective Matrix Stimulation Diversion Technique,’’ paper SPE 24781 presented at the 1992 SPE Annual Technical Conference and Exhibition, Washington, DC, 4–7 October.

20. MaGee, J., Buijse, M.A., and Pongratz, R.: ‘‘Method For Effective Fluid Diversion When Performing a Matrix Acid Stimulation in Carbonate Formations,’’ paper SPE 37736 presented at the 1997 SPE Middle East Oil Show, Bahrain, 17–20 March.

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SUMMARY OF CARBONATE PAPER PUBLISHED 65068

TITLE Understanding Wormholing Mechanisms Can Improve Acid Treatments in Carbonate Formations

AUTHORS M.A. Buijse, Halliburton

PRESENTATION or


This paper (SPE 65068) was revised for publication from paper SPE 38166, presented at the 1997 SPE European Formation Damage Conference held in The Hauge, The Netherlands, 2–3 June.

SUMMARY OF

PAPER

The physics of acidizing is complex, and often only poorly understood, due to the coupling of mechanical and chemical processes. In fracture acidizing, rock mechanical properties play a dominant role in fracture initiation and fracture growth, while the chemistry of the acidrock reaction determines the final fracture conductivity. In matrix treatments, formation properties such as permeability and porosity determine the direction and magnitude of fluid flow, but these properties are continuously altered as a result of acidrock dissolution. For a proper understanding of the acidizing process it is essential to study the combined effect of acid reaction and fluid flow.

In this paper, acid wormholing in carbonate formations is studied. Acid spending is studied by modelling the wormhole as a cylindrical pore and numerically solving the convection diffusion equations. A finite acidrock reaction rate is assumed, allowing calculation and study of spending profiles in both the diffusioncontrolled and the reactioncontrolled regime. Flow properties such as fluid loss from wormhole to formation and fluid distribution in a multiple wormhole geometry are studied through numerical simulations. The fraction of fluid that leaks off to the formation before it reaches the wormhole tip increases with the wormhole length. It is shown how wormhole growth properties are affected by the length and distance of neighboring wormholes. Wormhole interaction explains why side branches quickly stop growing and it is a key element in the mechanism that determines the spatial distribution of wormholes and the wormhole density. The effect of injection rate and diffusion is studied with a simple model. This model explains several experimentally observed phenomena, such as the existence of an optimum injection rate and reduced wormhole efficiency at higher rates.

HALLIBURTON TRADE NAME

Name: None Primary Application: Matrix Acid Stimulation

USED IN PAPER

TYPE OF

CONTENT


þ Background Research Review


Name of competitor and product: None

OPPORTUNITIES FOR OTHER PSL’s Nil


4. Levich, V.G.: Physicochemical Hydrodynamics, PrenticeHall, Inc., Englewood Cliffs, New Jersey (1962).

5. Buijse, M.A.: ‘‘Mechanisms of Wormholing in Carbonate Acidizing,’’ paper SPE 37283 presented at the 1997 SPE Intl. Symposium on Oilfield Chemistry, Houston, 18–21 February.

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SUMMARY OF CARBONATE ACIDIZING ENGINEERING PAPER IPTC 10697

TITLE Front End Engineering Studies for Carbonate Stimulation Optimization

AUTHORS Dwight Fulton, Ken Lizak, Mary Van Domelen.

PRESENTATION or


International Petroleum Technology Conference, Doha, Qatar, 2123 November 2005.

SUMMARY OF

PAPER

This paper describes in four parts an integrated approach to stimulation treatment design for carbonate reservoirs. Using this process helps ensure that appropriate candidates are stimulated with the optimum treatment. Part 1 discusses preliminary candidate selection based on estimated productivity gains from various stimulation options. Part 2 describes how core testing can be used to demonstrate that specific carbonates will have uniquely different reaction characteristics when treated with various acid systems. The paper reviews specialty core testing to optimize acid treatments. Part 3 investigates modelling for prediction of matrix stimulation fluid placement and diversion, leading to predicted skin reduction and stimulation results. Part 4 describes refining a fracture acidizing treatment and more realistic simulation of expected well response. Parts 1 and 3 use the Halliburton STIM2001 software for the calculations and predictions shown there. Three example wells (“Ex1a”, “Ex1b” and “Ex2”) are

considered and thickness, permeability and porosity data for these wells are given. “Ex1a” is an example of a typical completion in that adequate perforations exist such that there is no mechanical skin factor present and all total skin may be attributed to nearwellbore damage. “Ex1b” is identical to “Ex1a” except that the number and length of the perforations has been artificially reduced, resulting in a significant perforation and partial completion skin. “Ex2” uses the same data except that the formations all have been artificially reduced to 25% of original permeability to hypothetically demonstrate a lower permeability example. The analysis of productivity for various conditions of

reduced skin show that “Ex1a” would be a good matrix acidizing candidate. Well “Ex1b” may be a good matrix acidizing treatment candidate, however, this well can realize a “quick win” increase in productivity through reperforating. “Ex2” shows that even when there is an appreciable skin factor, lowerpermeability formations are often better fracturing treatment candidates than matrix acidizing candidate. Core testing to understand carbonate reactivity with

various acid systems is a valid design consideration, whether the proposed treatment is matrix or fracture acidizing. Specialty testing for carbonate formations can be grouped into three basic categories: (1) mineralogical evaluations and rock properties, typically accomplished with Xray diffraction (XRD), acid solubility, and either petrographic or scanning electron microscope (SEM) examinations, (2) surface reactivity characteristics, determined with rotating disk experiments, and (3) reaction characteristics under flowing conditions, evaluated with acid etching tests. In matrix treatments, the biggest challenge is often fluid

placement and diversion. The effectiveness of a possible treatment depends on adequately treating all producing intervals. The paper contrasts a conventional treatment approach with an engineered design incorporating diversion. When fracture acidizing is required, the same reservoir

data can be used for more realistic simulation of fracture stimulation, often the best choice for low permeability reservoirs. Fracture modelling is a critical section of the pre job planning and postjob analysis. Models are run to achieve a desired conductivity and length optimized on permeability. Predicted bottomhole pressures during treatment and posttreatment production for the modelled fracture geometry should be compared to actual job gauge data and the production values to validate the design. The information learned can be used to improve future design models.


IN PAPER

Name: Nil Primary Application: Nil

TYPE OF

CONTENT




!

Name of competitor and product:



1. Nitters, G., Roodhart, L., Jongma, H., Yeager, V., Buijse, M., Fulton, D., Dahl, J., and Jantz, E.: Structured Approach to Advanced Candidate Selection and Treatment Design of Stimulation Treatments, paper SPE 63179, presented at the 2000 Annual SPE Tech. Conf., Dallas, Oct 14.

5. Gdanski, R.D. and van Domelen, M.S.: “Slaying the Myth of Infinite Reactivity of Carbonates,” paper SPE 50730 presented at the 1999 International Symposium on Oilfield Chemistry, Houston, TX, 1619 Feb.

6. Gdanski, R.D. and van Domelen, M.S.: “Understanding the Finite Reactivity of Carbonates,” Paper No. 26 presented at the 2000 NIF Oil Field Chemicals Symposium, Fagernes, Norway, 2022 March.

15. Cipolla, C.L., Wright, C.A., “Diagnostic Techniques to Understand Hydraulic Fracturing: What? Why? and How?,” paper SPE 59735, presented at the 2000 SPE/CERI Gas Technology Symposium, Calgary, Alberta, Canada, 35 April.

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SUMMARY OF CARBONATE PAPER NIF_00 SYMMETRY OF ACID WORMHOLING

TITLE The Symmetry of Acid Wormholing in Carbonates

AUTHORS Rick Gdanski, Halliburton

PRESENTATION or


Presented at the 2000 NIF Oil Field Chemicals Symposium, Fagernes, Norway, Mar. 2022

SUMMARY OF

PAPER

A new theoretical model has been developed to describe the chemical reactions of acid in the porous carbonate media. The three major unanswered questions of acid wormholing when pumped into carbonate formations for the past 20 years have been (1) How many dominant wormholes are created? (2) What is the spatial distribution of those dominant wormholes along the well bore? (3) What is the leakoff profile from the dominant wormholes under radial flow conditions? This paper presents answers to these three basic questions which lead to an understanding of the reaction of acid in matrix and the interaction of wormhole development. The new model requires a major paradigm shift in the understanding of matrix carbonate acidizing and the variables that control wormhole growth. Most investigators assume that the direction of fluid flow through the matrix is governed by the developing wormhole pattern. As a result, they focus on the physics of the wormhole growth and ignore the matrix itself. The breakthrough in thinking is that the developing wormhole pattern is governed by the fluid flow through the matrix. It was found that wormhole length is predominantly controlled by matrix porosity, permeability anisotropy and the volume of acid pumped not by reactivity. It was also found that formation reactivity and contact time with the acid predominantly control wormhole diameters and acidized permeability. The new theory confirms classically held “rules of thumb” for matrix acidizing of carbonates. The real purpose of the new wormholing theory is not to simply provide a new description of how wormhole patterns might be described. Rather, the real purpose is to exploit the simplicity of the theory to provide easy design criteria for acidizing carbonate formations. The new model also accommodates the effects of permeability anisotropy caused by natural fracturing or layering effects. Easy to use charts have been presented for designing matrix acidizing treatments under a variety of formation conditions.


Name: Nil

Primary Application: Nil

TYPE OF

CONTENT

Case History Laboratory Study þ Background Research þ Review Comparison to competitor product Name of competitor and product:



3. Gdanski, R.D. and van Domelen, M.S.: “Slaying the Myth of Infinite Reactivity of Carbonates,” paper SPE 50730 presented at the 1999 International Symposium on Oilfield Chemistry, Houston, TX Feb. 16 19.

23. Daccord, G.: “Chemical Dissolution of a Porous Medium by a Reactive Fluid,” Phys. Rev. Lett. (1987) 58, 479482.

24. Daccord, G. and Lenormand, R.: “Fractal Patterns from Chemical Dissolution,” Nature (1987) 325, 4143.

25. Daccord, G., Touboul, E. and Lenormand, R.: “Carbonate Acidizing: Toward a Quantitative Model of the Wormholing Phenomenon,” SPEPE (February 1989) 6368.

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SUMMARY OF CARBONATE PAPER NIF 00 UNDERSTANDING FINITE REACTIVITY

TITLE Understanding the Finite Reactivity of Carbonates

AUTHORS Rick Gdanski and Mary van Domelen

PRESENTATION or


2000 NIF Oil Field Chemicals Symposium, Fagernes, Norway, Mar. 2022

SUMMARY OF

PAPER

This paper builds upon the historical foundation in understanding the acidizing process and brings together the reactivity studies using a number of different reactors to show that carbonates do not have infinite reactivity. New reactivity data are suggested for default reactivity for normal limestones and dolomites in the absence of specific laboratory measurements. The rotating disk apparatus has been used for obtaining acid reaction rates on carbonates in the laboratory. Reactivity data that were determined with three distinctly different reactors on a single limestone were all consistent with each other. This study shows that oilfield limestones show an average Ea of 2 kcal/mole, while oilfield dolomites show an average Ea of 5.8 kcal/mole. Furthermore, it was observed that limestones are more reactive than dolomites up to 200°F. A formation may not always be predominantly limestone or dolomite. This situation presents a problem in choosing a default for reactivity. This study indicates that one should avoid using default reactivity for any type of carbonate. The reactivity of mixed carbonates with compositions ranging from 95% limestone to 95% dolomite was studied. It was observed that the 95% limestone behaved as an average limestone, while the 95% dolomite (5% calcite) behaved as an average dolomite. However, in the 60 to 80% calcite range the reactivity first increased as the calcite content decreased, which is attributed to an experimental artifact. Further, it is not yet clear how this behavior would manifest itself in an acid treatment. During fracture acidizing at low temperatures, these crystals might stay at the rock surface and spend or they might behave as insolubles. At high temperatures they might spend in normal fashion. The same situation might exist during matrix acidizing. However, it is suspected that wormholing would predominantly occur through the limestone portions, so the mixed composition carbonate might behave as though it were just a limestone. This study shows that the reactivity data should be determined in the

laboratory as a function of temperature for each carbonate considered for acidizing treatments. Laboratory core preparation for rotating disk reactivity testing must include presaturation with a noninterfering brine so that inadvertent acid spending does not occur within the porosity of the sample. It is also shown that carbonates have a significant surface kinetic effect in fracture acidizing treatments, even at temperatures of 250°F. Finally, it is concluded that liveacid penetration distances are greater than classically thought, which supports the notion that acid fluid loss may be the dominant factor controlling etched lengths.


Name: Nil


TYPE OF

CONTENT

Case History ! Laboratory Study

! Background Research Review




PSL’s Frac/Acid


1. Frasch, H.: “Increasing the Flow of Oil Wells, “U.S. Patent No. 556,669 (March 17, 1896).

2. Dill, W.R.: “Reaction Times of HydrochloricAcetic Acid Solution on Limestone,” paper presented at the 1960 Southwest Regional Am. Chem. Soc. Meeting, Oklahoma City, OK, Dec. 1 3.

3. Anderson, M.S.: “Reactivity of Dolomite Formations,” paper presented at the 1990 AIChE Annual Meeting, Chicago, IL, Nov. 1116.

4. Gdanski, R.D. and van Domelen, M.S.: “Slaying the Myth of Infinite Reactivity of Carbonates,” paper SPE 50730 presented at the 1999 SPE International Symposium on Oilfield Chemistry, Houston, Feb. 1619.

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SUMMARY OF CARBONATE PAPER SPE 54719

TITLE A Fundamentally New Model of Acid Wormholing in Carbonates

AUTHORS Rick Gdanski

PRESENTATION or


1999 European Formation Damage Conference, The Hague, The Netherlands, May 31 June 1

SUMMARY OF

PAPER

A new theoretical model has been developed to describe the chemical reactions of acid in the porous carbonate media. The three major unanswered questions of acid wormholing when pumped into carbonate formations for the past 20 years have been (1) How many dominant wormholes are created? (2) What is the spatial distribution of those dominant wormholes along the well bore? (3) What is the leakoff profile from the dominant wormholes under radial flow conditions? This paper presents answers to these three basic questions which lead to an understanding of the reaction of acid in matrix and the interaction of wormhole development. The new model requires a major paradigm shift in the understanding of matrix carbonate acidizing and the variables that control wormhole growth. Most investigators assume that the direction of fluid flow through the matrix is governed by the developing wormhole pattern. As a result, they focus on the physics of the wormhole growth and ignore the matrix itself. The breakthrough in thinking is that the developing wormhole pattern is governed by the fluid flow through the matrix. It was found that wormhole length is predominantly controlled by matrix porosity, permeability anisotropy and the volume of acid pumped not by reactivity. It was also found that formation reactivity and contact time with the acid predominantly control wormhole diameters and acidized permeability. The new theory confirms classically held “rules of thumb” for matrix acidizing of carbonates. The real purpose of the new wormholing theory is not to simply provide a new description of how wormhole patterns might be described. Rather the real purpose is to exploit the simplicity of the theory to provide easy design criteria for acidizing carbonate formations. The new model also accommodates the effects of permeability anisotropy caused by natural fracturing or layering effects. Calibration of the model with field treatments indicates only fractional pore volumes of acid are required to achieve a given stimulation distance—not multiple pore volumes.


Name: Nil


TYPE OF

CONTENT

Case History Laboratory Study þ Background Research þ Review Comparison to competitor product Name of competitor and product:



3. Gdanski, R.D. and van Domelen, M.S.: “Slaying the Myth of Infinite Reactivity of Carbonates,” paper SPE 50730 presented at the 1999 International Symposium on Oilfield Chemistry, Houston, TX Feb. 16 19.

20. Buijse, M.A.: “Understanding Wormholing Mechanisms Can Improve Acid Treatments in Carbonate Formations,” paper SPE 38166 presented at the 1997 European Formation Damage Conference, The Hague, The Netherlands, Jun. 23.

21. Daccord, G.: “Chemical Dissolution of a Porous Medium by a Reactive Fluid,” Phys. Rev. Lett. (1987) 58, 479482.

22 . Daccord, G. and Lenormand, R.: “Fractal Patterns from Chemical Dissolution,” Nature (1987) 325, 4143.

23. Daccord, G., Touboul, E., and Lenormand, R.: “Carbonate Acidizing: Toward a Quantitative Model of the Wormholing Phenomenon,” SPEPE (February 1989) 6368.

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SUMMARY OF CARBONATE_ZCA PAPER SPE 58804

TITLE Successful HighPressure/HighTemperature Acidizing With InSitu Crosslinked Acid Diversion

AUTHORS M. Buijse, R. Maier, and A. Casero, Halliburton, and S. Fornasari, ENI AGIP.

PRESENTATION or


2000 SPE International Symposium on Formation Damage Control held in Lafayette, Louisiana, 2324 February 2000.

SUMMARY OF

PAPER

This paper describes a very successful acid stimulation treatment performed in AGIP’s TrecateVillafortuna Field. The goal of the acid treatment was to remove the nearwellbore mud damage and to improve the permeability of the horizontal drain. The high pressure at 6000 m and the bottomhole static temperature (BHST) of 182°C, classify the acid treatment as High Pressure High Temperature (HPHT). This treatment used insitu crosslinked acid (ICA) as the diverting agent. The treatment is unique because it represents the highest temperature application ever attempted for such a system. Hightemperature acidizing poses a number of problems during treatment design and execution, such as high acidrock reaction rate and corrosion problems, which are not normally encountered during treatments at lower temperatures. The high acidrock reaction rate requires the use of a retarded acid system to ensure that acid will not all spend on the formation face (compact dissolution) but will penetrate deeper into the formation. Protecting the tubulars against acid corrosion requires careful selection of the acid fluids and inhibitor package design. This paper discusses these issues in more detail. The design process included temperature simulations, detailed laboratory testing, and a review of acid formulations that were used successfully in the TrecateVillafortuna Field and elsewhere. Temperature simulations indicated that cooldown from the bottomhole temperature (BHT) of 180°C to at least 150°C could be achieved despite the high treating pressures that limited injection rates. Even after cooldown, serious concerns about corrosion and the effectiveness of the ICA system still existed. Laboratory support included fluid optimization for hightemperature application of the ICA. The flow tests enabled the selection of the most appropriate base acid systems. The conclusion of these tests is that ICA is effective at temperatures up to at least 176°C (350°F).

Success of the treatment must also be attributed to the operational planning and close attention to experience gained from previous stimulation treatments. The execution of the treatment used (1) all of the components considered to be stateoftheart in matrix acidizing treatment execution and evaluation: prestimulation injection tests, spotting of acid with coiled tubing (CT) to help reduce injection pressures and improve zonal coverage, the use of the Maximum Pressure Maximum Rate Diversion Technique (MAPDIR), and real time treatment pressure monitoring and (2) design optimization through integration of laboratory testing and the use of modern theories in carbonate acidizing The paper presents job procedures and a detailed treatment pressure analysis. It also gives details on the changes in injectivity and the Productivity Index (PI) before and after stimulation.


Name: ZCA Primary Application: Matrix Acid Stimulation

TYPE OF

CONTENT


Background Research Review þ Field Study Comparison to competitor product

Name of competitor and product: Not used

OPPORTUNITIES FOR OTHER PSL’s Coiled Tubing.


4. Van Domelen, M.S. and Jennings, A.R. Jr.: “Alternate Acid Blends for HPHT Applications,” paper SPE 30419 presented at the 1995 Offshore Europe Conference, Sep. 58, Aberdeen, Scotland.

6. Buijse, M.A. and Van Domelen, M.S.: “Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations,” paper SPE 39583 presented at the 1998 International Symposium on Formation Damage Control, Feb. 1819, Lafayette,LA.

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SUMMARY OF CARBONATE_ZCA PAPER SPE/IADC 85337

TITLE

Remarkable Results from Stimulation Treatment Using Deep Penetrating Diverting Acid System in Marrat Tight Limestone Formation Case Histories from Humma Field, DZKuwait/Saudi Arabia.

AUTHORS Talal Z. AlMutairi and Mohammad A. Shahid, Kuwait Oil Company, David L. Barge, Saudi Arabian Texaco and Naz H. Gazi, Halliburton.

PRESENTATION or


SPE/IADC Middle East Drilling Technology Conference & Exhibition held in Abu Dhabi, UAE, 2022 October 2003.

SUMMARY OF

PAPER

This paper presents the results of joint research work between Kuwait Oil Company, Saudi Arabian Texaco and Halliburton. The Humma field is located in the southwest corner of the Divided Zone (DZ) bordering Kuwait and Saudi Arabia. Marrat production was discovered in the field in 1998 and brought online in 1999. The Jurassic Marrat formation consists of several distinct limestone layers of varying reservoir quality and productivity. These layers are generally classified as tight to low permeability limestones. Production from the Marrat formation is characterized by high initial production rates but with quick steep declines. To maintain producing rates the wells are acidized on a frequent basis with 15% HCl acid. The benefit of these frequent acid treatments diminished over time as postacid treatment production gains dropped. As a result, several stimulation alternatives to enhance the productivity were investigated. To overcome this problem of short sustaining of the post acid job incremental oil production, a better designed acid system was needed which would penetrate deeper into the formation. Also needed was a chemical diverting system for an effective diversion from the most permeable zones to less permeable zones. This will be in addition to the PPI straddle packers that would be used on the jobs. This paper describes the development and application of a deep penetrating acid system in stimulating the Marrat limestone formation in the Humma field. Core samples and reservoir rock properties were used to customize the system. The understanding of reservoir rock properties, the systematic approach of treatment design, and sustained production results were key factors in employing this system. It was important for the acid stimulation job design to collect the right information on the wells, including core analysis, cuttings, fluid loss histories during drilling, open hole logs, geology, reservoir properties,

and well test analysis results. The main design focus was on the rock properties and the understanding of the reasons of the low productivity. The resulting deep penetration acid system was found to be favourable for acid penetration and uniform distribution over the long limestone pay intervals. The system was tailored to penetrate “deep” into the formation while removing near well bore damage. The system creates uneven etching patterns in the formation, connecting the well bore with undamaged native permeability of the carbonate reservoir. The system was applied in three Humma Marrat wells. In all the three cases, incremental production increased by 201% and sustained since 1 ½ year to date. In the second well the incremental production was 151% and it was sustained for six months. In the third well the expected initial production was 2500 BOPD with ESP, but using the deep penetration acid technique the well started flowing by itself and sustained a production of 3381 BOPD as Natural Flow since one year to date. The flowing bottomhole pressure is still significantly high, and as a result of this the well has just been completed with TG5600 pump and is producing 4500 BOPD. This well is being monitored with the application of VSD and the production is expected to be +/ 6000 BOPD. The procedure and the placement techniques of using pinpoint injection packers, straddle packers and diverting systems, and the subsequent test results, provided insight into this treatment success and of limiting the uncertainties involved. The postjob analysis allowed further optimization of these processes, which would facilitate similar applications in the future.


Name: ZCA Primary Application: Matrix Acid Stimulation

TYPE OF

CONTENT

þ Case History Laboratory Study Background Research Review Field Study Comparison to competitor product Name of competitor and product: n/a



1. Buijse, M.A. and van Domelen, M.S.: “Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations,” paper SPE 39583 presented at the 1998 SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 1819 February.

6. Cole R.C., Ali S.A., and Foley K.A.: “A New environmentally Safe Crosslinked Polymer for FluidLoss Control,” paper SPE 29525 presented at the 1995 Production Operations Symposium,

Oklahoma City, Oklahoma, 23 April. 8. Mirza, M.S., Kritzler, T., and Gazi, N.H.: “Successful Use of a

Cost Effective Temporary Nondamaging Gel Plug System to Isolate a High Permeable Producing Zone during a Stimulation Job of a Low Permeability Gas producing Zone in Khuff Gas Reservoir in BahrainA Case History,” paper SPE 81441 presented at the 2003 SPE Middle East Oil Show and Conference, Bahrain, 58 April.

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SUMMARY OF CONFORMANCE PAPER SPE 81447

TITLE Lessons Learned from the First Openhole Horizontal Well Water Shutoff Job Using Two New Polymer SystemsA Case History from Wafra Ratawi Field, Kuwait

AUTHORS

Shahab Uddin, Kuwait Oil Company; Jimmy D. Dolan, and Ricardo A. Chona, Saudi Arabian Texaco, Inc.; Naz H. Gazi, and Ken Monteiro, Halliburton; Jamal A. AlRubaiyea and Anwar Al Sharqawi, Kuwait Oil Company

PRESENTATION or


SPE 13 th Middle East Oil Show & Conference held in Bahrain, 58 April, 2003.

SUMMARY OF

PAPER

The Wafra Ratawi Oolite reservoir is in the Partitioned Neutral Zone of Saudi Arabia and Kuwait. With the introduction of water injection, it faced water production problems, especially after drilling horizontal wells. An economical method to reduce this unwanted water influx was needed. The process was complicated in the horizontal openhole producing wells. Not only the water producing section of the part of the horizontal section has to be treated to reduce unwanted water production, but a good, costeffective method of temporarily protecting the producing horizontal section during this treatment was also needed to protect the potential oilproducing zone for future post treatment production. This requirement necessitated a good placement technique and the use of two gel systems, one to temporarily protect the oil zone and the other to permanently damage the water producing zone. This paper describes the application and techniques of placing a nondamaging temporary gel system to isolate the oil producing heel side of a horizontal section in an openhole horizontal well and the use of another organically crosslinked polymer system to shut off water from the toe side of this horizontal openhole wellbore. A candidate openhole lateral horizontal well was selected for this application. The suspected high water cut from the toe side was caused by interference between a nearby injection well and this producing well. The special features of the organically crosslinked polymer system compared to the older chromebased system are mentioned in the paper. The nondamaging gel polymer has been prepared by grafting a crosslinkable site onto an HEC backbone. Because of the polymer’s unique properties, it can be transformed into a rigid, internally crosslinked gel if the pH of the solution is adjusted from acid to slightly basic through the use of a nontoxic metal oxide crosslinker. No divalent or trivalent metals are associated with the polymer or included in its crosslinking chemistry.

Isolating the producing zones with the nondamaging gel packer run on coiled tubing while treating the water zones was important. The water shut off gel was then pumped into the bottom water zone below this zone. Job execution details and the post job results are given in the paper. The oil production has increased by 25% and the liquid production by 17% after the treatment. The initial results showed water cut reduction to between 70% and 80% from original 82%. The success of the conformance control job discussed in this paper was a result of reservoir understanding, problem identification, well defined objectives for the treatments, and the proper design and execution of the treatments to finally deliver the results. A complete field study is important to reap benefits from conformance management. Conformance response can be used to improve field development.


Name and Primary Application : KMax (Temporary nondamaging gel) and H2Zero (Permanent Gel)

TYPE OF

CONTENT

þCase History Laboratory Study Background Research Review Comparison to competitor product þ Field Study Name of competitor and product: n/a

OPPORTUNITIES FOR OTHER PSL’s

Conformance Control, Coiled Tubing


1. Azari, M., Soliman, M., and Gazi, N.: “Reservoir Engineering Applications to Control Excess Water and Gas Production” paper SPE 37810 presented at the 1997 Middle East Oil Show held in Bahrain, 1518 March. 2. Khater, M. et al.: “Isolation of a Horizontal Hole Section in an Openhole Well Using a Non Damaging temporary Gel Plug to Facilitate Hydrocarbon Production from the Remaining Lateral Section – A Case History from Kuwait,” paper SPE 72291 presented at the 2001 IADC/SPE Middle East Drilling Technology held in Bahrain, 2224 October. 3. Holems, R.E. and Sandy, J.M.: “A New Crosslinkable HEC – its Application in Conipieteii Work,” paper presented at the 1986 Offshore Southeast Asia Conference, Singapore, February. 4. Willhite, G. Paul: Waterflooding, Textbook Series, SPE, Richardson, Texas (1986) 28.

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SUMMARY OF CORROSION FORMIC DECOMPOSITION PAPER SPE 106185

TITLE Understanding Formic Acid Decomposition as a Corrosion Inhibitor Intensifier in Strong Acid Environments

AUTHORS Juanita M. Cassidy; Robert I. McNeil; Chad E. Kiser

PRESENTATION or


2007 SPE International Symposium on Oilfield Chemistry held in Houston, Texas, U.S.A., 28 February – 2 March 2007.

SUMMARY OF

PAPER

This paper investigates the role and mechanism of formic acid as a corrosion inhibitor intensifier in strong acid environments. The study confirms that CO is produced by decomposition of formic acid in strong acids under downhole conditions.

HCOOH CO + H20 This decomposition is found to be sensitive to temperature, acid strength, and alloy. The decomposition in HCl follows firstorder reaction rate with temperature and the activation energy for catalysis with HCl is 174kJ/mol. Decomposition is catalyzed homogeneously by HCl and heterogeneously by the steel surface. Further, the results reveal that HCl is a necessary component for heterogeneous reaction on the steel surface. Thus, the generation of CO by decomposition of formic acid is caused by the dual mechanism of metal surface catalysis and the homogeneous solution reaction catalyzed by HCl. The CO thus formed, bonds to the metal surface and reduces the ability of the metal surface to react with the intended electroactive molecule, decreasing the turnover rate. FTIR analyses of the decomposition product in strong HCl environments shows that CO is the gas produced. FTIR analyses shows that the homogeneous reaction producing CO occurs at about 230ºF (110ºC) for 7.5% HCl, at 220ºF (104ºC) for 15% HCl, and 150ºF (66ºC) for 28% HCl. For 15% HCl, the homogeneous reaction becomes significant at ≥ 250ºF (121ºC). Alloy type does appear to affect the reaction rate of the surface decomposition, the rate with N80 steel being greater than that for Incoloy 825. As metal surface heterogeneous catalysis is one of the contributors to decomposition of formic acid to CO, it is not surprising that different metals or alloys exhibit differences in bonding to formic acid and subsequent decomposition, and differences in bonding to CO itself. In the case of alloys, the percentage of iron in the composition may be key to the decomposition rate. The results suggest that, at least for moderate temperatures, where

heterogeneous decomposition predominates, formic acid intensification should be more effective on N80 steel.


Name: HII124F intensifier Primary Application: Corrosion Inhibitor Intensifier

TYPE OF

CONTENT





OPPORTUNITIES FOR OTHER PSL’s None

IMPORTANT REFERENCES Nil

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SUMMARY OF CORROSION HAI303_HII600 NACE PAPER 06482

TITLE Design and Investigation of a North Sea Acid Corrosion Inhibition System

AUTHORS Juanita M. Cassidy

PRESENTATION or


CORROSION NACExpo 2006, 61 st Annual Conference & Exposition.

SUMMARY OF

PAPER

As environmental standards are continually tightened, especially in the North Sea area, options for different corrosion inhibitor chemistries that will meet the criteria are becoming more limited. In addition, common additives used to augment the performance of the main corrosion inhibitor such as copper and antimony compounds are problematic because of their toxicity. This paper outlines the development of a unique inhibition system that meets the presentday North Sea environmental and performance requirements while offering a broad performance range. This unique inhibition system consists of a blend of inhibitor A which is a cinnamaldehydebased HCl acid inhibitor and inhibitor B which is a formulated bismuth inhibitor. Electrochemical tests were done by potentiodynamic polarization testing. Weightloss corrosion testing was performed using N 80 steel specimens. Corrosion data generated for Inhibitor A and B shows that corrosion inhibition in HCl fluids with these inhibitors is successfully attained at low temperatures with Inhibitor A, and at high temperatures on N80 steel and corrosion resistant alloys with both Inhibitor A and B. Thus, bismuth plating inhibitors can be used effectively in HCl fluids up to at least 400ºF (204ºC) if the deposition rate of bismuth is properly controlled. If the depositional rate is too high, it results in poor quality plating and the redox chemistry is probably controlled by charge transfer. Thus, it seems logical to lower the current density into a diffusioncontrolled region. One technique for doing this would be to set up a barrier or film on the ferrous surface. Cinnamaldehyde is effective in controlling bismuth deposition. It is believed to form a polymer coating on the metal surface. In the presence of bismuth ions, it is probably the imperfections in the polymer coating that allow bismuth to diffuse to the surface at a controlled rate. Ineffective plating conditions are evidenced by a mixed potential for the two simultaneous reduction oxidation reactions, Fe/Fe 2+ and Bi 3+ /Bi. Conditions that exhibit good plating show mixed potential (Emp) values approaching the bismuth electrode corrosion potential. Present environmental standards and a broad performance range can be attained with the developed inhibitor system.


Name: HAI303 inhibitor and HII600 intensifier Primary Application: Acid Corrosion Inhibition

TYPE OF

CONTENT







14. Walker, M. L., “Corrosion inhibiting compositions and methods,” U.S. Patent No. 5591381A (1997).

19. F.B. Growcock and V.R. Lopp, “Film Formation on Steel in CinnamaldehydeInhibited Hydrochloric Acid” Corrosion Vol 44. 1988, p. 248254.

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SUMMARY OF CORROSION INHIBITOR ANN NACE PAPER H03166

TITLE A Neural Network for Predicting Corrosion of Grade N80 Downhole Tubulars Exposed to Stimulation Fluids

AUTHORS Juanita M. Cassidy and Terry H. McCoy

PRESENTATION or


Not Available

SUMMARY OF

PAPER

Artificial neural networks (ANN) have shown promise as predictors in many situations, including corrosion risk assessment. In this investigation, a neural network has been proposed to determine corrosion losses expected from a variety of acid stimulation environments using commercial oilfield service company corrosion inhibitors. A model has been developed that appears suitable for corrosion prediction for N80grade tubulars in inhibited HCl. The even accuracy of the network model across the data distribution suggests that no area of weakness exists for predictability in corrosion losses for the conditions studied. Sensitivity analysis was also undertaken to determine which input variables had most affected corrosion losses. Sensitivity analysis of the data variables shows the temperature as the largest influence on the predicted corrosion losses, with HCl concentration as the next largest factor. Practical usage of a corrosion inhibitor requires development of sufficient data from weightloss coupon or electrochemical testing to cover the normal acidizing situations, but often oilfield acid job conditions that require extrapolation or interpolation from that data set will arise. In these cases, the only way to recommend an inhibitor loading is to run a corrosion test under the conditions outside of the existing data set. Limitations in ANNs require that predictions that fall close to the classification boundary result in either (1) changes to the controllable variables of the acid blend, or (2) actual corrosion testing. However, time considerations, material availability, or other factors may limit the possibility for testing. In those situations, an accurate ANN that could predict the possibility of success would be desirable. An ANN could also help determine how much corrosion inhibitor to test before running an actual laboratory test.


Name: HAI85M inhibited HCl was the object of this study Primary Application: Acid corrosion inhibition

TYPE OF

CONTENT






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1. I. S. Helliwell, M. A. Turega, and R. A. Cottis, “Neural Networks for Corrosion Data Reduction,” CORROSION/96, paper no. 379 (Houston, TX: NACE International, 1996).

4. H. M. G. Smets, and W. F. L. Bogaerts, “Neural Networks for Materials Data Analysis: Development Guidelines,” Computerization and Networking of Materials Databases: Fourth Volume, ASTM STP 1257, C. P. Sturrock and E.F. Begley, Eds. (Philadelphia, PA: American Testing and Materials, 1995), pp. 211 223.

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SUMMARY OF DIAGNOSTIC PROCESS ENHANCES GAS STORAGE DELIVERABILITY SPE 51039

TITLE Diagnostic Process Enhances Gas Storage Deliverability—A Case Study

AUTHORS

Matthew E. Blauch, Ken Squire, John Guoynes, Chad Jestes, Ray Loghry, William G. F. Ford, Daniel Durey, (Halliburton); Russ Frame, John Yater, (Natural Gas Pipeline of America)

PRESENTATION or


1998 SPE Eastern Regional Conference and Exhibition held in Pittsburgh, Pennsylvania, November 9 11.

SUMMARY OF

PAPER

The two case studies presented were performed in porousmedia gas storage fields. Case Study 1 was performed on a pressuredrive carbonate reservoir. Case Study 2 was performed on a waterdrive clastic reservoir. The new diagnostic process involves integrating decisionmaking processes and technologies as follows:

1. Candidate Selection: Some of the guidelines used include (1) the location of the wells within a reservoir, (2) the ages of the wells, (3) evidence that the wells were previously good withdrawal wells, (4) evidence of damage (solids observed in the wellbore or on tools, positive microbial evidence, failed stimulation procedures, etc.), and (5) wells that were used for both injection and withdrawal. The geologic location and distribution of the wells, Injection/withdrawal zones, including Kh, are also important selection factors, since these are integral factors for evaluating skin and other indications of damage.

2. Downhole Diagnostics: Once wells were selected for treatment, researchers performed downhole diagnostics to determine the cause of the wells’ declined deliverability performances. The diagnostic process consists of the following basic steps: 1. Examine the wellbore and formation areas with a high resolution downhole video (DHV) system tailored for damage identification. 2. Perform an onsite welltest analysis and extract a physical sample of the wellbore. 3. Perform laboratory analyses of the samples.

Case Study 1. The Natural Gas Pipeline Company of America (NGPL) operates the North Lansing gas storage field in east Texas which is considered for this study. The candidate selection process revealed a surprising diversity and mix of identified damage mechanisms. The dominant damage mechanism in several wells was calcium carbonate scale, while others were damaged by salt buildup. Wells with calcium carbonate or salt buildup were assigned a three step solution package, consisting of highdensity perforating,

precipitate removal with an indexing, highpressure jetting tool, and formation cleaning and skin reduction with a straddle tool. The wells containing chemical buildup were treated with a proprietary solvent treatment solution that removed both production chemical damage and inorganic damage that were identified with the diagnostic process. Since the treatments were completed, deliverability has increased by a potential 90 MMcf/D, exceeding the team’s goal of a potential 60 MMcf/D. This increase provided an average deliverability potential increase of 3.75 MMscf/D per well. Case Study 2. The Iowa storage field contains a waterdrive; clastic structural trap reservoir is field for this study. For this series of wells, the solution team was challenged to perform the following: (1) Determine a population of damaged wells. (2) Identify the primary causes of formation damage by applying the new diagnostic process. (3) Select highgrade candidate wells for deliverability enhancement within a predetermined budget. (4) Treat a population of candidate wells for each well’s individually identified damage mechanism(s). (5) Evaluate posttreatment results to determine the treatment’s effectiveness. The team selected 28 wells (17 from Mt. Simon and 11 from St. Peter) for damage quantification and mechanism diagnosis. The following types of primary damage were identified in the samples: (a) inorganic scale (carbonates, sulfates, and salt) (b) microbially induced precipitates and products (iron sulfides and hydrogen sulfide) (c) organic deposits (production chemical residue, paraffin, or other hydrocarbonbased material) The resultant treatment strategy is broken into three main treatment phases:

• Phase I. Wellbore sterilization Phase I fluid was formulated to target microbialrelated damage across and below the perforated interval. • Phase II. Wellbore solids cleanup Phase II fluid was formulated to provide economical wellbore (casing) cleaning, a less crucial process. This fluid system incorporates a microbial treatment solution (MTS), a dilute surfactant blend, and a pHbuffering system to reduce formation damage and reprecipitation. • Phase III. Perforation damage removal The following three primary perforation damage removal treatment fluids for Phase III were developed based on the diagnostic process: Damage Removal Fluid 1: Proprietary solvent/acid system Damage Removal Fluid 2: Nonchloride organic acid blend Damage Removal Fluid 3: 15% experimental sulfide removal acid formulation

The authors had treated a population of wells and monitored results from the welltreatment program. Upon completion of the treatment program, extensive posttreatment diagnosis was conducted separately. Observed damage mechanisms affecting field and wellbore scales can be complex and diverse. As proven by the diagnoses in the two case studies, a single, universal treatment solution is less optimal

than specifically developed solutions based upon diagnostic analysis at the field project level. However, not every well needs to undergo diagnostic study. Understanding of actual formation damage mechanisms affecting field wide production performance can lead to highly effective treatment solutions.


Name: FDPS591; HydraBlast (now Pulsonix); FE1A; Paragon 1; Algacide G; U.S. Patent 5,253,719 Primary Application: Formation Damage Diagnosis and Removal

TYPE OF

CONTENT




Field Study

Name of competitor and product: not mentioned

OPPORTUNITIES FOR OTHER PSL’s Pulsonix, Logging, Rotary Sidewall Coring, Slickline, CT Operations


1. Yeager, V.J., Blauch, M.E., Behenna, F.R. and Foh, S.E.: .Damage Mechanisms in GasStorage Wells,. paper SPE 38863 presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 58, and at the 1998 SPE Gas Technology Symposium, Calgary, Mar. 1518.

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SUMMARY OF FORMICHCL PAPER SPE 103978

TITLE LongTerm Comparative Evaluation of HCl/Formic Acid System Used To Stimulate Carbonate Formations at Severe Conditions in Saudi Arabia.

AUTHORS H.A. NasrElDin, S.M. AlDriweesh, Saudi Aramco, and L. Sierra, M. van Domelen, and T. Welton, Halliburton

PRESENTATION or


First International Oil Conference and Exhibition in Mexico held in Cancun, Mexico, 31 August2 September 2006.

SUMMARY OF

PAPER

This paper presents the results of joint research work between Saudi Aramco and Halliburton. The high levels of carbon dioxide and low levels of hydrogen sulphide content of some deep and high temperature gas producers contributed in the requirement to complete these wells using super Cr13 tubings. Due to the low permeability of the formation and the associated formation damage issues, acid fracturing treatments were required to optimize the productivity of these wells. This paper describes the selection, optimization and long term comparative evaluation of the gelled and insitu crosslinked HCl/formic acid systems used in this type of wells. The high temperatures encountered in deep wells and the susceptibility of super Cr13 to severe corrosion in high concentration HCl systems used for stimulation purposes added one additional difficulty to the acid stimulation process. As a result, the 28% HCl acids that are used in this field cannot be utilized in wells completed with super Cr13 tubulars. To overcome these problems, extensive experimental and field studies were performed to select an acid system to enhance the productivity of these wells. Four key observations were made based on rheological tests: (1) an in situ crosslink can be generated with an HClformic acid blend, (2) the overall temperature stability of a gelled acid can be greatly enhanced and maintained above 20 mPa.s for significantly longer periods compared to HCl alone, (3) the insitu gelled acid obtains a substantially higher viscosity that can be obtained using a fluid that has HCl alone, and (4) the spent viscosity of even linear gels can be improved by using HCl and formic acid. Core flood tests performed with HCl/formic acid systems showed their ability to create deep wormholes in tight carbonate cores; however the corrosiveness of these systems at downhole conditions could be severe if the correct type and concentration of corrosion inhibitor is not used.

In general, for the HCl/formic acid systems at downhole conditions (275 o F) it was found that high concentrations of corrosion inhibitors are required to protect the super Cr13 completions. Based on lab tests study acid stimulations were performed, the flow back fluid was recovered and analysed to observe the corrosion problems and to optimize the corrosion inhibitor. The corrosion inhibitor package maintained the integrity of the super Cr13 tubing, with no significant uniform or pitting corrosion. No operational problems were encountered during mixing or pumping the acid. Gelled and insitu gelled 15wt% HCl/9wt% formic acid systems were used successfully to acid fracture eleven vertical wells in deep gas reservoirs. In all the cases the wells responded very well to the acid stimulation and the completion integrity was not compromised in a short or long term. Substantial increases in gas production and flowing wellhead pressures were obtained. The paper also shows for the first time a comparative long term well response to the acid stimulation of the two acid systems used in the area, showing the better performance of the insitu crosslinked HCl/formic system over the gelled HCl/formic system.


Name and Primary Application: ZCA prepared with HCL/Formic Acid System

TYPE OF

CONTENT







1. Welton, T.D. and van Domelen, M.S.: “Highviscosity Yield Acid Systems for High temperature Stimulation,” paper SPE 98236 presented at the 2006 SPE Formation Damage Control Conference held in Lafayette, LA, 1517 Feb.

2. NasrElDin, H.A., AlKhuraidah, A.S., Kritzler, T.Cassidy, J.: “Recent Developments in HighTemperature Acidizing with Super 13Cr Completions: Laboratory Testing,” paper SPE 78557 presented at the 2002 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, United Arab Emirates, Oct. 1316.

3. NasrElDin, H.A., Driweesh, S.M. Muntasheri, G.A.: “Field Application of HClFormic Acid System to Acid Fracture Deep Gas Wells Completed with Super Cr13 Tubing in Saudi Arabia,” paper SPE 84925 presented at the 2003 International

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Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, Oct. 2021.

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SUMMARY OF FORMICHCl PAPER SPE 78557 \

TITLE Recent Developments in Hightemperature Acidizing with Super 13Cr Completions: Laboratory Testing

AUTHORS H. A. NasrElDin, A. S. AlKhuraidah, (Saudi Aramco), T. Kritzler, J. Cassidy (Halliburton)

PRESENTATION or


10 th Abu Dhabi International Petroleum Exhibition and Conference, 13 16 October 2002.

SUMMARY OF

PAPER

This paper presents the results of joint research work between Saudi Aramco and Halliburton. The new gas reservoirs in Saudi Arabia presented challenging conditions such as temperatures up to 275 ° F, H2S contents up to 10 mol% and CO2 contents higher than 2 mol%. Previous completions utilized regular lowcarbon steel (L80 and C95) metallurgy. Due to the nature of the reservoir conditions, these types of completion hardware could not be applied in areas where H2S content is very low and CO2 is high. Super 13Cr completions have been proven to be reliable in these environments. However, Super 13Cr completions cannot tolerate the high acid concentrations (28 wt% HCl Acid) that are needed to acid fracture the tight carbonate formations available in Saudi Arabia. This paper discusses how the aforementioned problem was overcome by developing an acid blend using 15 wt% HCl and 9 wt% formic acid. Initial laboratory tests showed high corrosion rates for the Super 13Cr coupons when this acid formulation was applied. It is possible to inhibit 15 wt% HCl/9 wt% formic acid effectively up to 250 ° F for three hours. However, the inhibitor intensifier concentration is high level at 150 lbs/Mgal. Temperature simulations were performed to further optimize the inhibitor package. Lowering the temperature range had a dramatic effect on the intensifier loading. Therefore it was suggested to run a tapered system using a higher intensifier loading at the beginning compared to the end of the treatment. It is a good practice to tailor the inhibitor package to adjust for cooldown of the completion when performing highrate stimulation treatments. During the testing of several coupons, a difference in pitting patterns under the same conditions for different coupons was noted. This difference was explained due to different composition of the coupons, i.e. different percentage of molybdenum, which was varying between 1.5 and 2.5 wt%. It was shown that with higher molybdenum

concentration higher corrosion rates were observed. Hence, the percentage of molybdenum is critical to obtain effective protection of the completion. It is also mentioned that Potassium Iodide is the recommended inhibitor intensifier for SCR13 completions. Compatibility of various additives was conducted and corrosion tests were performed at bottomhole conditions. As a conclusion, a new corrosion package was developed for Super 13 Cr tubing. This package is compatible with reservoir fluids and other acid additives. In addition, it produces acceptable corrosion rates with no pitting. This paper shows that it is not only necessary to use a sound engineering approach to well completion design, but also that it is necessary to take all other contributing factors into account, such as the stimulation method to be used after completing the well.


Name: HII124B

Primary Application: Corrosion Inhibitor Intensifier

TYPE OF

CONTENT


Background Research þ Review

þ Field Study Comparison to competitor product




3. Rahim, Z. and AlQahtani, M. Y. : “Selecting Perforation Intervals and Stimulation Technique in the Khuff Reservoir for Improved and Economic Gas Recovery,” Paper SPE 68216 presented at 2001 SPE Middle East Oil Show held in Bahrain, 1720 March.

21. Do Carmo Marques, L.C. and Mainer, F.B.: “Corrosion Problems Associated with the use of CopperBased Corrosion Inhibitor Intensifier in Acid Stimulation Treatments,” paper SPE 23634 presented at the 1992 Latin American Petroleum Engineering Conference held in Caracas, Venezuela, 811 March.

22. Keeney, B.R. and Johnson, Jr., J. W. : Inhibited Treating Acid,” U.S. Patent Number 3,773,465, 1973.

23. Keeney, B.R.: “Acid Corrosion Inhibition Using Metal Halide Organo Inhibitor Systems,” Materials Performance, 12 (September, 1973) 1315.

26. Lynn J.D. and NasrElDin, H.A.: “A Corebased Comparison of the Reaction Characteristics of Emulsified and Insitu Gelled Acids in Low Permeability, High Temperature, Gas Bearing Carbonates,” paper SPE

65386 presented at the 2001 SPE International Symposium on Oilfield Chemistry held in Houston, TX, 1316 February.

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SUMMARY OF GUIDON AGS MEXICO PAPER

TITLE A New Method for Acid Stimulation Without Increasing Water Production: Case Studies from Offshore Mexico

AUTHORS Gabriel Hernandez Reza, Pemex; Eduardo Soriano, Larry Eoff and Dwyann Dalrymple, Halliburton

PRESENTATION or


Paper SPE 103771 with minor updates by the same authors, presented at the 2006 SPE International Oil Conference and Exhibition in Cancun, Mexico, August 31–September 1, 2006.

SUMMARY OF

PAPER

Successful acid stimulation requires a method to distribute the acid between multiple hydrocarbon zones. Since almost all producing wells are inhomogeneous, containing sections of varying permeability, this can be a huge problem. In addition, the water saturation of the various zones plays an important role. Since acid is an aqueous fluid, it will tend to predominantly enter the zones with the highest water saturation. These water zones are also often the highest permeability zones, so acid stimulation will often result in large increases in water production. This paper describes the use of a new low viscosity system that inherently reduces formation permeability to water with little effect on hydrocarbon permeability, and also diverts acid from high permeability zones to lower permeability zones. The treatment is referred to as relative permeability modifier (RPM), disproportionate permeability modifier or bullhead treatment. Hydrophobically modified water soluble polymers are used for the treatment. Rather than reaching a plateau in adsorption, as is common for hydrophilic polymers, hydrophobicallymodified polymers appear to produce a continued growth in adsorption with increased polymer concentration. This is attributed to associative adsorption of polymer chains on previously adsorbed layers of polymers. Hence, this technology is referred to as associative polymer (AP) diverter. In the laboratory, parallel core testing was used; polymer and acid were bullheaded into both a watersaturated core and an oilsaturated core simultaneously. Laboratory tests have shown that the AP diverter can divert acid from predominantly watersaturated zones to predominantly oilsaturated zones in both sandstone and carbonate lithology. In both sandstone and carbonate, it provided permanent waterpermeability reduction. This new system has been used in offshore Mexico in the Chuc, Caan, and Pol fields among others over the past year. During this time, over 30 wells have been treated with the new system. Most standard acid treatments in this field result in increased hydrocarbon and water production. The new system has resulted in increased hydrocarbon production with no increase in water production, and in some cases a

decrease in water production. Details from several of these jobs are presented which show the diversion and production results.


Name: Guidon AGS Primary Application: Acid diversion

TYPE OF

CONTENT

þ Case History þLaboratory Study

Background Research Review Comparison to competitor product Name of competitor and product: Not mentioned



1.Eoff, L. et al.: “Development of a Hydrophobically Modified WaterSoluble Polymer as a Selective Bullhead System for Water Production Problems,” SPE 80206

2.Eoff, L. et al.: “Development of Associative Polymer Technology for Acid Diversion in Sandstone and Carbonate Lithology,” SPE 89413

3. Zaitoun, A., Kohler, N.: “Improved Polyacrylamide Treatments for Water Control in Producing Wells,” paper SPE 18501

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TITLE A New Method for Acid Stimulation without Increasing Water Production: Case Studies from Offshore Mexico

AUTHORS Gabriel Hernandez Reza, Pemex; Eduardo Soriano, Larry Eoff, Dwyann Dalrymple, Halliburton

PRESENTATION or


First International Oil Conference and Exhibition in Mexico held in Cancun, Mexico, 31 August–2 September 2006

SUMMARY OF

PAPER

Successful acid stimulation requires a method to distribute the acid between multiple hydrocarbon zones. Since almost all producing wells are inhomogeneous, containing sections of varying permeability, this can be a huge problem. In addition, the water saturation of the various zones plays an important role. Since acid is an aqueous fluid, it will tend to predominantly enter the zones with the highest water saturation. These water zones are also often the highest permeability zones, so acid stimulation will often result in large increases in water production. This paper describes the use of a new low viscosity system that inherently reduces formation permeability to water with little effect on hydrocarbon permeability, and also diverts acid from high permeability zones to lower permeability zones. The treatment is referred to as relative permeability modifier (RPM), disproportionate permeability modifier or bullhead treatment. Hydrophobically modified water soluble polymers are used for the treatment. Rather than reaching a plateau in adsorption, as is common for hydrophilic polymers, hydrophobically modified polymers appears to produce a continued growth in adsorption with increased polymer concentration. This is attributed to associative adsorption of polymer chains on previously adsorbed layers of polymers. Hence, this technology is referred to as associative polymer (AP) diverter. In the laboratory, parallel core testing was used; polymer and acid were bullheaded into both a watersaturated core and an oilsaturated core simultaneously. Laboratory tests have shown that the AP diverter can divert acid from predominantly watersaturated zones to predominantly oilsaturated zones in both sandstone and carbonate lithology. In both sandstone and carbonate, it provided permanent waterpermeability reduction. This new system has been used in offshore Mexico in the Chuc, Caan, and Pol fields among others over the past year. During this time, over 30 wells have been treated with the new system. Most standard acid treatments in this field result in increased hydrocarbon and water production. The new system has resulted in increased hydrocarbon

production with no increase in water production, and in some cases a decrease in water production. Details from several of these jobs are presented which show the diversion and production results.



TYPE OF

CONTENT


Background Research Review Comparison to competitor product þ Field Data Name of competitor and product: Not mentioned



1. Zaitoun, A., Kohler, N.: “Improved Polyacrylamide Treatments for Water Control in Producing Wells,” paper SPE 18501 2. Eoff, L. et al.: “Development of a Hydrophobically Modified WaterSoluble Polymer as a Selective Bullhead System for Water Production Problems,” paper SPE 80206 3. Eoff, L. et al.: “Development of Associative Polymer Technology for Acid Diversion in Sandstone and Carbonate Lithology,” paper SPE 89413

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TITLE Simultaneous Acid Diversion and Water Control in Carbonate Reservoirs: A Case History from Saudi Arabia

AUTHORS Ali A. AlTaq, Hisham A.NaserElDin, Jimmy K. Beresky, Khalid M. Naimi, Saudi Aramco and Leopoldo Seirra, Larry Eoff, Halliburton

PRESENTATION or


SPE Europec/EAGE annual conference and exhibition held in London, United Kingdom, 1114 June 2007

SUMMARY OF

PAPER

Acid diversion and water control are usually addressed as two separate issues. Associative polymers can be used to simultaneously achieve effective diversion and water control during a single treatment. Objectives of the study presented in this paper are to (1) assess the effectiveness of associative polymers in reducing brine permeability in carbonate cores, (2) design a polymerbased treatment to control water and divert acid in matrix treatment and (3) evaluate the use of this type of polymers based on field application. A polymer based treatment was applied in an offshore, perforated vertical well with two sets of perforations in a carbonate reservoir in Saudi Arabia. The acid treatment was needed to restore the productivity of the upper set of perforations and reduce water production from the lower set of perforations. The solution properties of both ionic and nonionic water soluble polymers are uniquely modified when hydrophobic groups are introduced into the polymer chains. The primary factor responsible for this property modification is the associative tendency between the hydrophobic groups when placed in aqueous media. The viscosity of a polyelectrolyte solution decreases with added salt because of the screening of the charges on the polymer chain by the component ions of the salt. For hydrophobicallymodified polymers, the reduction in viscosity caused by charged screening is more than compensated for by the increased intermolecular interactions among the hydrophobic groups due to the presence of salt. Thus, they find use as viscosifiers for brines such as those used in drilling fluids. Experimental studies were carried out to investigate the potential use of associative polymers to control water mobility and act as an acid diverter. Coreflood experiments were conducted on reservoir cores at downhole conditions (temperature of 200ºF and pressure of 3,500 psi). 15 wt% HCl was used for the studies. A polyacrylamide modified with C18 acrylate as hydrophobe was used in the study. Both single

core flow model and parallel core flow model were used for laboratory studies. Extensive lab testing showed that associative polymers had no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced. Besides the laboratory results, this paper presents a case history where an associative polymer was applied during matrix acid treatment of a damaged well. The treatment included stages of associative polymer solutions and 20 wt% HCl with additives. Post stimulation treatment production data showed that oil rate increased by 11fold; whereas water rate decreased by 3fold; resulting in a reduction in water cut from 75 to 14 vol%. Production Logging Tool (PLT) test confirms that the associative polymer was very effective in diverting the acid to the oil zone. The PLT showed that the upper set of perforations was producing most of the fluid, which further confirmed that the associative polymer was effective in reducing the relative permeability to water. A build up analysis showed that the skin value decreased from +17.9 to 4.19 after the treatment indicating that the results of the acid treatment did remove skin damage, without increasing water production. An openhole log of a well in carbonate formation is also presented in the paper.


Name: Guidon AGS

Primary Application: In Carbonate Reservoirs

TYPE OF

CONTENT



OPPORTUNITIES FOR OTHER PSL’s Conformance Control, Baroid Fluid Services


1. Eoff, L, Dalrymple, D and Reddy, B.R. “ Development of Associative Polymer Technology for Acid Diversion in Sandstone and Carbonate Lithology” SPEPF 20(3)(2005) 250256. 2. McCormick, C.L., Bock, J., and Schulz, D.N.:Encyclopedia Polymer Science and Engineering, second edition, Mark, H.F., Bikales, N.M., Oveberger, C.G., and Menges, G.T. (ed.) Wiley interscience: New York 17(1989) 730. 3. “Hydrophilic polymers: Performance with Environmental Acceptance,” Glass, J.E. (ed.) Advances in chemistry series 248, American Chemical Society: Washington, DC (1996). 4. Eoff, L., Dalrymple, D., Reddy, B.R., Morgan, J. and Farmpton, H.: “Development of a Hydrophobically Modified Watersoluble Polymer as Selective Bullhead System for WaterProduction Problems,” paper

SPE 80206.

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SUMMARY OF GUIDON PAPER SPE 89413

TITLE Development of Associative Polymer Technology for Acid Diversion in Sandstone and Carbonate Lithology

AUTHORS Larry Eoff, Dwyann Dalrymple, B.R. Reddy

PRESENTATION or


2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 17–21 April 2004.

SUMMARY OF

PAPER

This paper describes the use of associative polymer technology (APT) to achieve fluid diversion during an acid stimulation treatment. APT involves the use of a very low viscosity aqueous polymer solution. It reacts immediately with the formation surface to significantly reduce the ability of subsequent aqueous fluids to flow into highpermeability portions of the rock. The first stage containing the APT predominately will enter the most permeable area, diverting following acid stage(s) to less permeable sections of the rock. APT has little or no effect on the flow of subsequent hydrocarbon production. This paper includes a general description of associating polymers and their properties, as well as a detailed description of the laboratory development of the current system. Laboratory data showing the ability of APT to reduce the ability of aqueous fluids to flow through porous media is presented. Parallel flow studies using watersaturated and oil saturated cores are presented that show the ability of APT to divert acid in both sandstone and carbonate cores. These tests also show the ability of APT to decrease water permeability in the watersaturated core while the diverted acid increases the permeability of the oilsaturated core. This paper discusses the initial project wherein the goal was the development of a polymer which would provide a minimum of 80% reduction in brine permeability, with a maximum of 50% reduction in oil permeability. Several hydrophobicallymodified water soluble polymers were investigated. Polyacrylamide modified with C18 hydrophobe groups did improve the level of brine permeability reduction. However, the target goal of 80% minimum reduction had not been met. The hydrophobic modification also appeared to be increasing the temperature stability of the base polymer (polyacrylamide) at the screening temperature of 175ºF. A hydrophobic modification of Polydimethylaminoethyl methacrylate by introducing C16 hydrophobe could achieve the targeted 80% reduction in permeability to brine with little or no damage to the effective permeability to oil. In addition, no decline in the effective brine permeability reduction has been seen with continued flow

through the cores for six months, at 210ºF. This polymer was chosen for field development. Four acid diversion jobs have been pumped with APT till date. For three of them, production results are not available. But for all of them, the pressure response indicate that each stage of the acid behind the APT stage was being diverted to less permeable zones. In the fourth job for which production data is available, a 34% increase in oil production and 3% decrease in water cut (from 21% to 17%) were achieved after the job. In sandstone, APT can provide acid diversion and permanent water permeability reduction. In carbonate, it can provide acid diversion. Further work is needed to determine whether permanent water permeability reduction will be seen.


Name: The term Associative Polymer Technology (APT) is used Primary Application: Acid diversion.

TYPE OF

CONTENT



OPPORTUNITIES FOR OTHER PSL’s Conformance Control, Drilling Fluids


1. Zaitoun, A., Kohler, N.: “Improved Polyacrylamide Treatments for Water Control in Producing Wells,” paper SPE 18501 2. Eoff, L. et al.: “Development of a Hydrophobically Modified WaterSoluble Polymer as a Selective Bullhead System for Water Production Problems,” paper SPE 80206 3. Taylor, K.C. and NasrElDin, H.A.J.: “WaterSoluble Hydrophobically Associating Polymers for Improved Oil Recovery: A Literature Review,” J. Petro. Sci. Eng. (1998) 19, 289. Paper SPE 29008 4. AudibertHayet, A. et al.: “Novel Hydrophobically Modified Natural Polymers for Nondamaging Fluids,” paper SPE 56965 5. Volpert, E. et al.: “Adsorption of Hydrophobically Associating Polyacrylamides on Clay.” Langmuir (1998) 14, 1870. 6. Dalrymple, E.D. et al.: “Studies of a Relative Permeability Modifier Treatment Performed Using Multitap Flow Cells,” paper SPE 59346

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SUMMARY OF GUIDON AGS PAPER SPE 109714

TITLE Effective Acid Diversion and Water Control in Carbonate Reservoirs Using an Associative Polymer Treatment: Case Histories From Saudi Arabia

AUTHORS Ali A.Altaq, Hisham A. NasrElDin, Ridha A. Lajami, Saudi Aramco and Leopoldo Sierra, Halliburton

PRESENTATION or


Presented in 2007 SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., 1114 November, 2007.

SUMMARY OF

PAPER

Acid diversion and water control are usually addressed as two separate issues in the oil industry. An associative polymer can be used to simultaneously address these two issues in a single treatment. Associative polymer treatments were successfully applied during matrix acid stimulation in onshore and offshore oil carbonate reservoirs in Saudi Arabia. The oil producers were completed as perforated and openhole wells. The associative polymer was applied in combination with acid treatments mainly to: 1) mitigate the preferential stimulation of water saturated zones located near oil producer layers, 2) improve acid diversion in heterogeneous carbonate reservoirs, and 3) restore the productivity of the damaged wells. Extensive studies were carried out to investigate potential use of an associative polymer to control water mobility and act as an acid diverter. Coreflood experiments (Parallel cores) conducted on reservoir cores at downhole conditions showed that the polymer treatment has no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced. In addition, the associative polymer was very effective in diverting acid into oilsaturated cores. This paper presents the results obtained from several wells where an associative polymer was applied successfully during matrix acid treatments of damaged wells. Associative polymers are macromolecules with attractive groups, some of which possess hydrophobic moiety. The rheological properties of the associative polymers are influenced by the hydrophobe type and content, molecular weight, degree of hydrolysis, temperature and presence of surfactant. The polymer used in this study was an acrylate polymer modified with a C16 hydrophobe. Three cases, referred to as Wells A, B and C are studied. Wells A and C have a primarily calcite reservoir while Well B has a mixed calcite and dolomite reservoir. Reservoir temperatures of Wells A, B and C were 144, 225 and 200ºF respectively. All the treatments included stages of associative polymer solutions and 20 wt% HCl with additives. Post stimulation treatments production data, buildup, downhole gauges and production logging confirmed that the associative polymer was very effective in diverting the acid into oil saturated zones and resulted in a significant reduction in water production.



TYPE OF

CONTENT


Background Research Review Comparison to competitor product Name of competitor and product: Not specified.



1. NasrElDin, H.A., AlHabib, N.S., AlMumen, A.A., Jemmali, M. and Samuel M.: “ A New Effective Stimulation Treatment for Long Horizontal Wells Drilled in Carbonate Reservoirs,” SPEPO, 21(3) (2006) 330338. 2. AlTaq, A.A., NaserElDin, H.A., Beresky, J.K., Naimi, K.M., Sirra, L. and Eoff, L.: “Simultaneous Acid Diversion and Water Control in Carbonate Reservoirs: A Case History from Saudi Arabia,” paper SPE 106951 presented at the 2007 SPE EUROPEC/EAGEA Annual Conference and Exhibition , London, UK, 1114 June. 3. Reza, G.H., Oriano, E., Eoff, L. and Dalrymple, D.: “A New Method for Acid Stimulation without Increasing Water Production: Case Studies From Offshore Mexico,” paper SPE 103771 presented at the 2006 International Oil Conference and Exhibition in Mexico, Cancun, Mexico, 31 August2 September. 4. Eoff,L., Dalrymple, D. and Reddy, B.R.: “Development of Associative polymer Technology for Acid Diversion in Sandstone and Carbonate Lithology,” SPEPF 20(3) (2005) 250256.

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SUMMARY OF GUIDON AGS ARTICLE

TITLE Smart acid system reduces water

AUTHORS Dwyann Dalrymple, Larry Eoff and Matt Blauch.

PRESENTATION or


E&P, July 2005 Copyright: Hart Energy Publishing, 4545 Post Oak Place, Ste. 210, Houston, TX 77027 USA (713)9939320, Fax (713) 8408585

SUMMARY OF

PAPER

This article describes the prospects of Associative Polymer Technology (APT) in acid diversion. APT is applied prior to an acid treatment and it uses the relative permeability modifier (RPM) technology to divert treating acid away from water producing zones. Unlike many other available acid diversion techniques, APT has the special feature to reduce the water production after an acid treatment. APT uses a hydrophobically modified water soluble polymer for selective permeability reduction of the water zone. It has little effect on relative permeability to oil and gas. APT can be used regardless of lithology and with almost any acid treatment. It is placed in alternating stages throughout the treatment. APT can provide highly effective acid diversion without gelling or subsequent setting up. The technology is simple to use requiring no zonal isolation, no catalyst and no special placement technique. Due to fast reaction with the rock, no set in period is required. The treating polymer concentration is determined based on the application temperature. APT is successfully used up to 350 º F (176 º C). In laboratory tests on two sandstone cores, one oilsaturated, and the other watersaturated, acid increased the permeability to both oil and water. When the acid was preceded by APT agent, permeability to oil increased significantly but permeability to water was cut by 96%. The APT system has been applied successfully in landbased wells in the United States, Mexico, Venezuela and Angola. To date, the system has been pumped in more than 40 acidizing treatments. In a typical well in Mexico, oil production was increased by 34% and water cut was reduced from 21% to 17%. APT helps in cost saving by reducing produced water as well as having less impact on the environment. It can be a major contributor to revitalize activities in mature reservoirs.


Name: The term Associative Polymer Technology (APT) is used. Primary Application: Acid diversion

TYPE OF

CONTENT

Case History Laboratory Study Background Research þ Review

Comparison to competitor product Name of competitor and product: Not specified.



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Summary of Power Safe D Paper SPE 81732

TITLE Damage Removal in Screened Horizontal Wells

AUTHORS D. J. McCulloch, J. Mann (Halliburton); P. Macmillan, S. Ali (ChevronTexaco)

PRESENTATION or


SPE/ICoTA Coiled Tubing Conference, Houston, Texas, U.S.A., 8–9 April 2003.

SUMMARY OF

PAPER

This paper describes a common damage mechanism in screened and gravel packed completions in horizontal wells and the remedial cleanup procedures developed. Horizontal wells do not normally require stimulation for primary reasons as it is often necessary to cleanup the Drill In Fluid (DIF) filter cake. This paper deals with the Alba field that is located in block 16/26 of the UK sector of north sea. It was expected that drilling in the reservoir section would be through reactive shales and unconsolidated sand, thus three high priority requirements were perceived to be: shale inhibition and borehole stability while drilling and sand exclusion while producing. Sometime later when production started, analysis of recovered sand indicated that average sand size was approximately 110 microns, suggesting that there has been mechanical failure of the screens. Prior to the remedial treatment and in order to ensure the future integrity of the well the damaged section of screens was repaired using a straddle system. A placement technique was developed which included a Coil Tubing, “Controlled Injection Technique” (CIT) in combination with a True Fluidic Oscillator (TFO) to aid in placing a modified Proprietory Scale and DIF filtercake Solvent (PSDS) fluid behind the screen into the gravel packed annulus. Field trials of various types of CT jetting tools were undertaken to determine the most efficient means of moving fluid through a screen into a gravel pack. This paper elaborates on the PSDS fluid testing procedures and the type of fluids used. Five tests were performed during the course of this evaluation using different PSDS formulations and the results are illustrated. Thus, the placement technique is supported with surface testing results of two standard jetting tools versus a True Fluidic Oscillator (TFO) for the placement of the stimulation fluid. This PSDS fluid was specifically modified to improve the effectiveness of removing filtercakes layed down with a drill solids laden DIF mud sample from the field. The presence of formation drilled solids, results in a much more tenuous filtercake than one created with a clean DIF. Field results show that after the initial

well cleanup, PSDS treatment had improved the productivity by 62% if the inflow length is normalized to account for the effect of reduced inflow due to the packer section. Field tests also indicated an improved movement of fluids behind a screened pipe with the TFO tool compared to the conventional jetting tools. Installation of a completion straddle effectively repaired an eroded section of screen. It has also been found that increasing the strength of PSDS type solvents can increase their effectiveness in cleaning up calcium carbonates based DIF filtercakes, but not as effectively as direct contact with fluid. Mutual solvent increased the effectiveness of PSDS solvent fluids in an oil saturated gravel pack. Hence, a combination of laboratory evaluation, field testing and engineering developments have lead to an effective process for cleaning up calcium carbonate filtercake damage in horizontal gravel packed wells that has global applications.


Name: PowerSafe D, Pulsonix Primary Application: Wellbore cleanout

TYPE OF

CONTENT



Field Study



OPPORTUNITIES FOR OTHER PSL’s Coiled Tubing, Sand Control


1) Fredd, C.N. and Fogler, H.S.: “Chelating Agents as Effective Matrix Stimulation Fluids for Carbonate Formation”, paper SPE 37212, 1997.

2) Burton, R.C., Hodge, R.M., Wattie, I., and Tomkinson, J.:“Field Test of a Novel DrillIn Fluid CleanUp Technique”, paper SPE 58740, 2000.

3) Murray G., Brookley J., Ali S., Davidson E., MacMillan N., Roberts J. “ Development of the Alba Field Part 1” SPE 73726.

4) Murray G., Morton K., Blattel S., Davidson E., MacMillan N., Roberts J. “Development of the Alba Field Part 2” SPE 73727.

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SUMMARY OF POWER SAFE D PAPER SPE 104119

TITLE Openhole cleanup of deep, hightemperature horizontal wells with a chelantbased acid system – case histories from Indonesia

AUTHORS Kunto Wibisono, Robert C. Burton, Richard M. Hodge, (ConocoPhillips); Rio Wijaya, Bastiaan Nieuwland and Juanita Cassidy

PRESENTATION or


Presented at the 2006 SPE international Oil and Gas Conference and Exhibition, Beijing, China, December 57.

SUMMARY OF

PAPER

This paper covers work performed in the Belanak field offshore Indonesia. Belanak wells which are drilled in the Gabus Massive reservoir have a bottom hole static temperature of 315ºF (157ºC). The wells are typically long horizontals (23003400ft) with openhole completions utilizing standalone screens through the producing interval. The reservoir section is drilled with a waterbased Drillin Fluid (DIF) consisting of polymer and CaCO3 particles and displaced to a solidsfree, DIF prior to running the screens. Typically, acid is used to degrade waterbased DIF filtercake and remove CaCO3 contained in the filtercake. The use of a common acid was not an option for this development because of the high reservoir temperature (>300°F). The combination of high reservoir temperature and long shutin times after acid treatment lead to a high probability of severe corrosion of the sand control screens. In addition to the corrosion concerns with common acids, the rapid removal of the filtercake with acid could create localized, high leakoff of the treating fluid resulting in an uneven distribution of acid across the horizontal openhole section. To overcome these problems, a slow reacting alternative chemical solution was required allowing the stimulation fluid to be placed across the entire horizontal openhole section before the CaCO3 filtercake was dissolved and before major losses started to occur. The solution was found in the application of a Chelant Based Acid System. This paper details the applications of the Chelant Based Acid System as a means to remove CaCO3 filter cakes in 10 Belanak wells, post treatment well performance, best practices, and lessons learned. A slowreacting chelant based acid system, EDTA(Ethylene Diamine Tetraacetic Acid), has proven to be effective for openhole cleanout of high temperature sandstone reservoir drilled with water based DIF using CaCO3 bridging particles. Special polymer degrader in EDTA solution is not required for wells with 315ºF BHT. As long as the treatment fluid pH is higher than 7 and the well is not in severe fluid loss problem, the EDTA treatment does not cause a fluid loss to the well. An EDTA treatment volume of 136 bbl per 1000 ft of 81/2”

openhole length showed the best results for openhole cleanout effectiveness. Spent EDTA can be left in an openhole horizontal for extended length of time up to 114 days without any evidence of plugging due to precipitation or from secondary reaction versus the laboratory test of 96 hours soaking time.


Name: PSDS (PowerSafeDScale) Primary Application: Removal of DIF filtercake on openhole face

TYPE OF

CONTENT





OPPORTUNITIES FOR OTHER PSL’s Drilling Fluids


4. R. C. Burton, R. M. Hodge, I. Wattie and J. Tomkinson; “Field Test of Novel DrillInFluid CleanUp Technique”, SPE 70757 presented at the SPE Eropean Formation Damage Conference held in The Hague, The Netherlands, 2122 May 2001

8. D. J. McCulloch, J. Mann, P. Macmillan and S. Ali: “Damage Removal in Screened Horizontal Wells”, SPE 81732 presented at the SPE/ICoTA Coiled Tubing Conference held in Houston, Texas, USA on 89April 2003.

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SUMMARY OF PULSONIX PAPER SPE 89653

TITLE Screen and NearWellbore Cleaning and Stimulation Tools Evaluation: Recent Experience in Well Operation

AUTHORS Aziz Harthy, Petroleum Development Oman; Ramzi Abdulkadir, Halliburton; Iqbal Sipra, Jan Saeby and Avadhut Raiturkar, Petroleum Development Oman; Michael Bailey, Jim Venditto, Halliburton

PRESENTATION or


SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, U.S.A., 2324 March 2004.

SUMMARY OF

PAPER

In Southern Oman, oilproducing wells are completed with wire wrap screens, internal gravel packs and predrilled liners. These wells produce from mature clastic formations where fines migration and subsequent blockage of screens can result in impaired oil production. Conventional treatment use coiled tubing and a jetting tool to remove this damage. The gains resulting from these intervention activities were often short lived. This lack of longevity required frequent well intervention and oil deferment, often resulting in a loss of revenue. This paper describes the results of a systematic approach to evaluate the wellbore cleaning and stimulations tools that are currently available in the industry. Three cleanout tools viz. RotationCavitation Tool, PiezoElectric Sonic Tool, and PulseJetting Tool were used for implementing this approach as a trial in oilproducing wells. Excellent success was achieved with a pulsejetting tool operating on the Principle of Coanda effect to create pulsating pressure and remove perforation tunnel damage, scales, formation fines, mud and cement damage, drilling damage, and water and gas blocks. The effect of the cleanout procedure is presented in terms of initial production and sustainment of production level. This paper also outlines the importance of using proper cleaning and/or stimulation fluid. To help avoid clayswelling problems, special emphasis is placed on the brine fluid salt concentration. In conclusion, the pulse jetting tool coupled with properly engineered stimulation design has proven to be a very successful and economic wellbore cleanout and stimulation tool in Oman. The versatility of the tool enables it to be deployed for use with coiled tubing or regular workover strings. Many fluids, including nitrogen, can be pumped through the tool. This versatility is important because most of the wells are subhydrostatic and require the use of nitrified fluid to maintain circulation in case cleanout and welllifting operations occur immediately after sandstone acid stimulation.


Name: Pulsonix Primary Application: Near wellbore stimulation.

USED IN PAPER

TYPE OF

CONTENT





OPPORTUNITIES FOR OTHER PSL’s Coiled Tubing, Sand Control, Well Intervention


1. E. Stevenson, A. Raiturkar, K. AlHarthy, R. Abdulkadir, M. Buijse: “Structured Approach to Matrix Stimulation Proves Successful in Oman,” paper SPE 82261 presented at European Formation Damage Conference held in The Hague, Netherlands, 1314 May 2003.

2. Nitters, G., Roodhart, L. Jongma, H., Yeager, V., Buijse, M., Fulton, D., Dahl, J., Jantz, E.,: “Structured Approach to Advanced Candidate Selection and Treatment Design of Stimulation Treatments,” paper SPE 63179, presented at the 2000 Annual SPE Tech. Conf., Dallas, TX, Oct. 14.

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SUMMARY OF PULSONIX SS2000 PAPER SPE 93071

TITLE Optimized Stimulation Treatments in Straddled Completions

AUTHORS M. I. Willemse, O. Mostafa, M. ElAshry, I. Abdallah, and A. A. Sattar, Bapetco; A. Waheed, and B. Conrad, Halliburton

PRESENTATION or


14 th SPE Middle East Oil & Gas Show and Conference held in Bahrin International Exhibition Centre, Bahrin, 1215 March 2005.

SUMMARY OF

PAPER

Hundreds of wells have been completed by completing a producing zone(s) behind straddle packers. It is not a problem if such wells produce troublefree and meet expectations. However, if there is a problem, then the options for executing an enhanced stimulation treatment are limited. Generally, the best treatment has consisted of pumping and squeezing away the treatment into the perforations via the sliding side door (SSD). The preferred technique is to improve the injectivity into the perforations by spotting reactive fluids at the perforations or using some type of mechanical action such as perforation jetting to break up blockages in the perforation tunnels. This is only possible when perforations are accessible through the wellbore. These problems become more complicated if the zones of interest are sandstone reservoirs. This paper addresses such a scenario, in which a dirty sandstone reservoir not previously acidized, was not producing up to expectations. The zones were completed between straddle packers and were only accessible through SSD, 100 ft above the perforations. The benefits of using highpressure jetting to loosen up debris across the damaged perforations could not be used because the perforations were not directly accessible.

In addition to applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. The TFO’s are based on the Coanda effect. The tool does not have any moving parts and it does not rely on cavitation to create pressure waves. There are no packer elements to fail, and TFO efficiently transfers the kinetic energy of the fluid pumped to the damaged zone. Thus this tool provides a continuous pressure pulse in the fluid system that allows solid build up within the perforations to fatigue and break up while the acid system works on the rock matrix. The results from the TFO treatment of this well were exceptional and are presented in the paper. Based on the job results several conclusions can be drawn:

1. Integrated teamwork was a key to success. 2. Acid jobs should be considered on a casebycase basis. 3. The response of the well depends on correctly analyzing the

damage mechanism and choosing an appropriate stimulation

technique. 4. Rock mineralogy information is essential if sandstone acid

stimulation is planned. 5. The completion design, if possible, should be optimized to

allow direct access to the perforations. 6. The organic acid and retarded HF acid systems worked very

well with the formation types treated. 7. Pressure responses from the acid job plots verified this as did

the production results. In future jobs acid volumes can be optimized.

8. Though nitrified acid is one of the better systems for stimulating lowpressure reservoirs, it should be carefully re evaluated if chosen again for tight formations such as those seen in this well.

9. The TFO provided a new and better way to treat zones that are not directly accessible.

10. Artificial lift is necessary for lifting the spent acid and putting the well on production.

11. The formation was competent enough to resist sand production after the acid treatment.


Name: PulsonixTF Primary Application: Fluidic oscillator (TFO) used for stimulating the zones. Name: Sandstone 2000 Best Practices Primary Application: Halliburton’s exclusive sandstone stimulation process that includes rock analysis as the basis of stimulation design. Name: Fines Control Acid Primary Application: retarded acid system and works on fines stabilization as well. Name: Claysafe F preflush Primary Application: Works on formation conditioning before exposing to HF acid.

TYPE OF

CONTENT





OPPORTUNITIES FOR OTHER PSL’s Coiled Tubing, Completions, Frac/Acid


2. Gdanski, R. and Shuchart, C.: “Advanced Sandstone Acidizing Designs Using Improved Radial Models,” paper SPE 38597 presented at the 1997 Annual Technical Conference and Exhibition, San Antonio, Texas, 5–8 October.

!

4.Gdanski, R.: “Formation Mineral Content Key to Successful Sandstone Acidizing,” Oil and Gas J. (30 August 1999) 90.

8.Gdanski, R.: “AlCl3 Retards Acid for More Effective Stimulations,” Oil and Gas J. (October 1985) 111115.

10. Harthy, A., et al.: “Screen and NearWellbore Cleaning and Stimulation Tools Evaluation: Recent Experience in Well Operation,” paper SPE 89653 presented at the 2004 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, 23–24 March.

11. McCulloch, D. et al.: “Damage Removal in Screened Horizontal Wells,” paper SPE 81732 presented at the 2003 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, 8–9 April.

12. Gunarto, R., et al.: “Production Improvement for Horizontal Wells in Sumatra,” paper SPE 86545 presented at the 2004 International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18–20 February.

7. Hall, B.E.: “Methods and Compositions for Dissolving Silicates in Subterranean Formations,” U.S. Patent 4,304,676 (Dec. 8, 1981).

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SUMMARY OF PULSONIX SS2000 PAPER SPE 93987

TITLE Ensuring Effective Stimulation Treatments in Difficult Completions

AUTHORS M. I. Willemse, O. Mostafa, M. ElAshry, I. Abdallah, and A. A. Sattar, Bapetco; A. Waheed, and B. Conrad, Halliburton

PRESENTATION or


2005 SPE/ICoTA Coiled Tubing Conference and Exhibition held in The Woodlands, Texas, U.S.A., 1213 April 2005.

SUMMARY OF

PAPER

Achieving effective stimulation across zones which are not readily accessible, such as in horizontal wells completed with slotted liner, gravel pack, internal gravel pack, or plain sand screens is a challenge in the oilfield because there is no easy way to effectively remove the drilling fluid filter cake from the wellbore walls. Similar inaccessibility is encountered when dealing with straddled completions. Another accessibility problem is encountered when a “fish” becomes caught up across the perforated interval and accessibility again is denied. It is not a problem if such wells produce troublefree and meet expectations. However, if there is a problem then the options for executing an enhanced stimulation treatment are limited. Generally, the best treatment has consisted of pumping and squeezing away the treatment into the perforations via the sliding side door (SSD). The preferred technique is to improve the injectivity into the perforations by spotting reactive fluids at the perforations or using some type of mechanical action such as perforation jetting to break up blockages in the perforation tunnels. This is only possible when perforations are accessible through the wellbore. These problems become more complicated if the zones of interest are sandstone reservoirs. This paper addresses such a scenario in which a dirty sandstone reservoir not previously acidized, was not producing up to expectations. The zones were completed between straddle packers and were only accessible through SSD, 100 ft above the perforations. The benefits of using highpressure jetting to loosen up debris across the damaged perforations could not be used due to stimulation challenges as mineralogical issues. In addition to applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. This tool provides a continuous pressure pulse in the fluid system that allows solid build up within the perforations to fatigue and break up while the acid system works on the rock matrix. The results from the TFO treatment of this well were exceptional and are presented in the paper. The paper also describes the challenge in a gas well where the perforations were inaccessible because of an unidentified “fish” left in the hole during workover; however, there was fluid communication

around the fish. This resulted in declined production after workover. Low circulation material, along with TFO included in the CT stimulation string were employed to rectify the problem. Post treatment results were awaited during the writing of this paper. Based on the job results several conclusions can be drawn: Integrated teamwork was a key to success. Acid jobs should be considered on a casebycase basis. The response of the well depends on correctly analyzing the damage mechanism and choosing an appropriate stimulation technique. Rock mineralogy information is essential if sandstone acid stimulation is planned. The completion design, if possible, should be optimized to allow direct access to the perforations. The organic acid and retarded HF acid systems worked very well with the formation types treated. Pressure responses from the acid job plots verified this as did the production results. In future jobs acid volumes can be optimized. Though nitrified acid is one of the better systems for stimulating lowpressure reservoirs, it should be carefully reevaluated if chosen again for tight formations such as those seen in this well. The TFO provided a new and better way to treat zones that are not directly accessible. Artificial lift is necessary for lifting the spent acid and putting the well on production. The formation was competent enough to resist sand production after the acid treatment.


Name: PulsonixTF Primary Application: Fluidic oscillator (TFO) used for stimulating the zones. Name: Sandstone 2000 Best Practices Primary Application: Halliburton’s exclusive sandstone stimulation process that includes rock analysis as the basis of stimulation design. Name: Fines Control Acid Primary Application: retarded acid system and works on fines stabilization as well. Name: Claysafe F preflush Primary Application: Works on formation conditioning before exposing to HF acid.

TYPE OF

CONTENT





OPPORTUNITIES FOR OTHER PSL’s Coiled Tubing, Completions, Frac/Acid


3. Harthy, A., et al.: “Screen and NearWellbore Cleaning and Stimulation Tools Evaluation: Recent Experience in Well

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Operation,” paper SPE 89653 presented at the 2004 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, 23–24 March.

4. McCulloch, D. et al.: “Damage Removal in Screened Horizontal Wells,” paper SPE 81732 presented at the 2003 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, 8–9 April.

5. Gunarto, R., et al.: “Production Improvement for Horizontal Wells in Sumatra,” paper SPE 86545 presented at the 2004 International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18–20 February.

6. Gdanski, R. and Shuchart, C.: “Advanced Sandstone Acidizing Designs Using Improved Radial Models,” paper SPE 38597 presented at the 1997 Annual Technical Conference and Exhibition, San Antonio, Texas, 5–8 October.

7. Gdanski, R.: “Formation Mineral Content Key to Successful Sandstone Acidizing,” Oil and Gas J. (30 August 1999) 90.

8. Hall, B.E.: “Methods and Compositions for Dissolving Silicates in Subterranean Formations,” U.S. Patent 4,304,676 (Dec. 8, 1981).

9. Gdanski, R.: “AlCl3 Retards Acid for More Effective Stimulations,” Oil and Gas J. (October 1985) 111115.

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SUMMARY OF SCALE INHIBITION PAPER NIF_01_SCALE_DESORB

TITLE Successful Model of the Kinetic Release of a Phosphonate Scale Inhibitor

AUTHORS Rick D. Gdanski and Gary P. Funkhouser

PRESENTATION or


2001 NIF International Oil Field Chemistry Symposium, Geilo, Norway, April 14.

SUMMARY OF

PAPER

The ability to model and predict the desorption of scale inhibitors from reservoirs is dependent on understanding the adsorption/desorption process. It is often assumed that laboratory desorption tests are a reasonable approximation of equilibrium desorption conditions of scale inhibitors. Isotherms are derived from these laboratory profiles for use in radial model calculations of field treatments. However, this paper demonstrates that laboratory experiments may not be at equilibrium conditions. In addition, it discusses a kinetic equation that was developed and used with the modified Langmuir isotherm for modeling kinetic desorption of a common phosphonate scale inhibitor diethylenetriamine penta(methylenephosphonic acid) (DETPMP). The kinetic desorption of scale inhibitors was modeled through the use of both the static isotherm and dynamic decline profile conducted at variable flow rates. The rate of inhibitor desorption at low pH is linearly related to the square of the concentration gradient from equilibrium. The rate of inhibitor desorption at neutral pH essentially follows the equilibrium profile defined by the static adsorption isotherm. Inhibitor concentrations measured at the surface from well returns represent equilibrium desorption conditions. The new modeling method successfully matches published inhibitor decline profiles for both laboratory and field examples. The field examples were found to decline in accordance with equilibrium conditions. From the wellreturns modeling, a new “surface” for adsorption was discovered and later identified as siderite.


Name: LP65 Primary Application: Scale Inhibition

TYPE OF Case History Laboratory Study !

CONTENT






1. Meyers, K.O., Skillman, H.L., and Herring, G.D.: “Control of Formation Damage at Prudhoe Bay, Alaska, by Inhibitor Squeeze Treatment,” JPT (June 1985) 10191034.

3. Chen, P. and Graham, G.M.: “Examination of the Influence Flow Rate on Inhibitor Return Concentrations in NonEquilibrium Core Flooding of Generically Different Scale Inhibitor Applied in Both Adsorption and Precipitation Treatments,” paper presented at the NIF 11th International Oil Field Chemicals Symposium, Fagernes, Norway, March 2022, 2000.

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SUMMARY OF SCALE INHIBITION PAPER NIF_01_SCALE_ISOTHERM

TITLE Improved AdsorptionIsotherm Modeling for Phosphonate Scale Inhibitors

AUTHORS Gary P. Funkhouser and Rick Gdanski

PRESENTATION or


Presented at the 2001 NIF International Oil Field Chemistry Symposium, Geilo, Norway, April 14

SUMMARY OF

PAPER

Classical static adsorption isotherms are generally presented on linear plots of adsorption vs. solution concentration. Curve fitting of the data is normally represented by hand drawn curves, and mathematical fitting is rarely done. Static data directly impacts the study of scale inhibitor adsorption/desorption. Furthermore, isotherm fitting with the modified Langmuir equation provides the mathematical framework for an understanding of desorption kinetics. This paper presents static adsorption isotherms for the common phosphonate scale inhibitor diethylenetriamine penta (methylenephosphonic acid) (DETPMP) on silica flour, kaolinite, illite, smectite, alumina, and siderite. However in many systems, static adsorption isotherm data do not follow the simple Langmuir isotherm. By incorporating an interaction parameter ( β) to modify the Langmuir equation, a wide variety of adsorption experiments can be fit easily. This paper demonstrates the information available from static adsorption isotherms in the region below the plateau and mathematical fitting with the modified Langmuir equation is shown. The mathematical fitting has been done to estimate the model parameters like interaction parameter, equilibrium constant, adsorption capacity, etc. This work, thus describes the limitations of the simple Langmuir isotherm and significance of incorporating an interaction parameter to modify the Langmuir equation. The minerals studied can be broadly classified into three groups, strongly adsorbing (siderite), moderately adsorbing “silicalike” minerals (silica and kaolinite) and weakly adsorbing “aluminalike” minerals (illite, smectite, and alumina). Static adsorption isotherms were useful in determining the magnitude of the kinetic effect on desorption in linear flow tests. Siderite may be responsible for the longterm, lowlevel inhibitorreturn profiles sometimes observed after squeeze treatments.


Name: Primary Application:

TYPE !

OF CONTENT







2. Hong, SA. and P.J. Shuler: “A Mathematical Model for the Scale Inhibitor Squeeze Process,” paper SPE 16263 presented at the 1987 International Symposium on Oilfield Chemistry, San Antonio, TX, February 46.

4. Fowler, R. and E.A. Guggenheim: Statistical Thermodynamics, Cambridge University Press, Cambridge (1952) Chapter 10.

5. Meyers, K.O., H.L. Skillman, and G.D. Herring: “Control of Formation Damage at Prudhoe Bay, Alaska, by Inhibitor Squeeze Treatment,” Journal of Petroleum Technology (June 1985) 10191034.

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SUMMARY OF SCALE INHIBITION PAPER NIF_02_LAB_SQUEEZE

TITLE Fully Contained Laboratory Squeeze Treatments

AUTHORS Rick D. Gdanski, Gary P. Funkhouser

PRESENTATION or


2002 NIF International Oil Field Chemistry Symposium, Geilo, Norway, March 1720.

SUMMARY OF

PAPER

Scale inhibitor adsorption/desorption studies have been commonly performed in the laboratory with short cores. These cores are typically treated with several pore volumes (PV) of scale inhibitor solution and then shut in to allow complete saturation on the surfaces. The excess scale inhibitor is flushed from the core, and the adsorbed inhibitor is desorbed by a continuous flow of simulated formation brine. The decline profiles can then be used for deducing a “dynamic” adsorption isotherm. This paper introduces an improved testing procedure that involves conducting a laboratory inhibitor squeeze treatment that is fully contained within the test column. Squeezes were performed in the injection direction without any scale inhibitor exiting the column. The inhibitor was a commonly used phosphonate, diethylenetriaminepenta(methylenephosphonic acid) (DETPMP). Brine flow was reestablished in the production direction after the squeeze to desorb the inhibitor and the entire process was successfully modeled. The experimental analysis included dual mineralogy, stacked isotherm mathematics, and kinetic desorption. Ironsubstituted carbonates play an important role in providing longterm release of scale inhibitor for scale prevention in produced brines with low minimum inhibitor concentration (MICs). Desorption of DETPMP from ironsubstituted carbonates is fast, but still exhibits significant kinetic effects in laboratory experiments. Scale inhibitors apparently return at nearequilibrium conditions from squeezed wells. Since well returns of scale inhibitors are essentially at equilibrium conditions, the relevant independent variable for squeeze modeling is produced water volume. Squeeze life then becomes a secondary function based on produced water rates. One of the roles of the overflush is to redistribute the adsorbed scale inhibitor from clays and onto iron substituted carbonates.


Name: LP65 Primary Application: Scale Inhibition

TYPE OF Case History Laboratory Study !

CONTENT






7. Gdanski, R.D. and Funkhouser, G.P.: “Successful Model of the Kinetic Release of a Phosphonate Scale Inhibitor,” paper presented at the NIF 2001 International Oil Field Chemistry Symposium, Geilo, Norway, April 14.

9. Funkhouser, G.P. and Gdanski, R.D.: “Improved Adsorption Isotherm Modeling for Phosphonate Scale Inhibitors,” paper presented at the NIF 2001 International Oil Field Chemistry Symposium, Geilo, Norway, April 14.

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SUMMARY OF SCALE INHIBITION PAPER SPE 94510

TITLE Mineralogy Driven Scale Inhibitor Squeeze Designs

AUTHORS Rick Gdanski, Gary P. Funkhouser

PRESENTATION or


6 th SPE European Formation Damage Conference, Scheveningen, The Netherlands, 2527 May 2005.

SUMMARY OF

PAPER

Prevention of formation damage caused by scaling brines is a common challenge for producing wells. Deposits that can occur in the formation and in the tubulars are often mitigated with scale inhibitors by squeezing them into the formation. This paper describes several aspects of how formation mineralogy can affect treatment designs and showed how the mineralogy can be used to create a first good estimate of the adsorption isotherm, which is normally the primary controlling mathematical function that describes how the scale inhibitor will return from the formation. This was accomplished by first determining the true equilibrium adsorption isotherms of a common scale inhibitor like diethylenetriamine pentamethylenephosphonic acid (DETPMP) on various single minerals. This paper demonstrates that scale inhibitors, particularly at pH less than 5, are reactive with formation mineralogy and can lead to fluid conditions not achievable in short core testing, and therefore not generally anticipated during the squeeze treatment. This paper also discusses how an evaluation of the formation mineralogy can lead to insight into ways to avoid many damage mechanisms unobservable in shortcore testing. Static adsorption isotherms have been determined for DETPMP on several minerals at neutral and low pH. The adsorption behavior on aluminosilicates seems to naturally group into two categories suggested as being aluminatype surfaces and silicatype surfaces. The natural grouping of the isotherms was observed at both neutral and low pH. The adsorption isotherms for DETPMP on siderite were situated at a lower concentration than either the aluminatype or silica type surfaces. Composite isotherms representing the surface categories of aluminatype, silicatype, and ironsubstituted carbonates have been constructed. DETPMP returns profiles can be understood in the context of the three surface categories. The method of creating composite isotherms based on formation mineralogy and laboratory adsorption data on specific minerals allows the estimation of a relevant isotherm for scale inhibitor squeeze designs. Depletion experiments of DETPMP on aluminosilicates at low pH suggest that aluminium leaching from the clays may cause enhanced depletion of the scale inhibitor from solution. LowpH scale inhibitor squeeze

treatments may experience unexpected formation damage from aluminium leaching and subsequent scale inhibitor precipitation. The use of lowpH mainstages to provide compatibility between formation water and scale inhibitor squeeze treatments may be ineffective because of spending on carbonates. Care should be taken to use base fluids for squeeze treatments that are compatible with swelling clays if they are present in the oilproducing layers of a formation. Compatible base fluids include 6% NaCl, 7% KCl, and seawater fortified with 3% KCl, and are essentially “1 molar” brines.


Name: LP65 Primary Application: Scale inhibition

TYPE OF

CONTENT







Funkhouser, G.P. and Gdanski, R.D.: “Improved Adsorption Isotherm Modeling for Phosphonate Scale Inhibitors,” paper presented at the 2001 NIF International Oil Field Chemistry Symposium, Geilo, Norway, April 14.

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SUMMARY OF SCALE INHIBITION PAPER SPE 95088

TITLE A Complete Theory of Scale Inhibitor Transport and Adsorption / Desorption in Squeeze Treatments

AUTHORS K.S. Sorbie, HeriotWatt University and R. D. Gdanski, Halliburton.

PRESENTATION or


SPE 7 th International Symposium on Oilfield Scale held in Aberdeen, United Kingdom, 1112 May 2005.

SUMMARY OF

PAPER

This paper, presents a reevaluation of the equations that have been proposed to model Scale Inhibitor (SI) transport and adsorption in porous media. Various approaches are analyzed in terms of two basic aspects: (a) the mathematical structure of the various equations used to describe transport; and (b) the surface chemistry assumptions and models used to describe the SI/rock retention mechanism, particularly by adsorption. The authors specifically focus on comparing and reconciling their own (HeriotWatt University and Halliburton) respective approaches, which have been developed over the last few years. The analysis and comparison is carried out in the context of the mathematics and the description of the adsorption process. In the calculations, authors have shown some of the predicted rate effects of the HeriotWatt (HW) and Gdanski and Funkhouser (GF) models. However, in practice, the correct form of the adsorption rate equation may be established by performing static adsorption rate experiments where the adsorption level is monitored over time from some initial solution concentration, to some final value. Models are numerically integrated and are presented. These integrated equations should then be compared with the experimental results. This will help to establish the correct rate law as well as the actual values of the adsorption parameters. This approach assumes, of course, that no additional chemistry occurs, such as precipitation with calcium, extraction of aluminium from clays to cause additional SI deposition, or other additional complex surface reactions. Chemical reactions captured by an isotherm under one set of conditions in the laboratory may not transform properly to field conditions. Therefore, it will be important to identify and isolate adsorption and chemical reaction effects. HW and GF models are compared and the advantages and disadvantages of each of them are presented. The mathematics are essentially identical, although different units give slightly different forms of expressions in various papers. However, there are three important differences in the details of the adsorption modelling

between the two approaches as follows: (1) The form of the adsorption rate law is different in each approach. A 1 st order law is assumed in the HW model whereas a 2 nd order rate law is assumed in the GF approach. The latter emphasises the effect of rate, which depends on the ratio of adsorption rate to fluid velocity via the Damkohler number. (2) The Langmuir form (sometimes modified Langmuir) of the equilibrium isotherm adsorption, is assumed by GF for the mineral separates (supported experimentally). The HW leaves this open and either a Langmuir, Freundlich or table of numbers (usually) may be used to model adsorption. (3) In the GF approach, the entire rock is treated as a mineral assemblage and multiisotherm treatment may be applied by using a Langmuir form for each of the rock components. The HW approach only considers a single adsorption isotherm although a clear connection between these approaches is demonstrated for one of the dynamic cases.


Name: Nil


TYPE OF

CONTENT

Case History Laboratory study



Field Study

Name of competitor and product: OPPORTUNITIES FOR OTHER PSL’s Nil


1. Sorbie, K.S., Wat, R.M.S. and Todd, A.C.: “Interpretation and Theoretical Modelling of ScaleInhibitor/Tracer Corefloods,” SPE Production Engineering, pp. 307312, August 1992.

2. Yuan, M.D., Sorbie, K.S., Jiang, P., Chen, P., Jordan, M.M., Todd, A.C., Hourston, K.E. and Ramstad, K.: “Phosphonate Scale Inhibitor Adsorption on Outcrop and Reservoir Rock Substrates The ‘Static’ and ‘Dynamic’ Adsorption Isotherms", in Recent Advances in Oilfield Chemistry, Edited by P. H. Ogden, Royal Society of Chemistry, Special Publication No. 159, 1994.

3. Funkhouser, G.P. and Gdanski, R.D.: “Improved Adsorption Isotherm Modeling for Phosphonate Scale Inhibitors”, Presented at the NIF International Oilfield Chemistry Symposium, Geilo, Norway, 14 April 2001.

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SUMMARY OF SCALE INHIBITOR PLACEMENT PAPER SPE 107801

TITLE Gelled scale inhibitor treatment for improved placement in long horizontal wells at Norne and Heidrun fields

AUTHORS Olav M. Selle, Martin Springer and Inge H. Auflem, Statoil ASA, Ping Chen and Rozenn Matheson, Champion Technologies, and Amare Mebratu and Gerard Glasbergen, Halliburton

PRESENTATION or


Presented at the European Formation Damage Conference, Scheveningen, The Netherlands, May 30June 1, 2007

SUMMARY OF

PAPER

A joint study was initiated by a major operator in the North Sea and two service companies in 2002, with the objective of improving the placement of treatment fluids. As a result of this work, a fully viscosified scale inhibitor system is developed. The system comprises a purified xanthan viscosifying agent, a standard scale inhibitor for down hole scale squeezing and a breaker to achieve controlled gel breaking down hole. The system has been field tested at Norne field in two long horizontal wells at Heidrun field in one long deviated well, all with significant permeability variations and cross flow. The operations were successful and the scale treatments have protected the wells from scaling. The paper describes the product qualification process, placement simulation, temperature prediction and gel breaking characteristics, case histories and post job evaluation. The qualification process included:

• Polymer gel/scale inhibitor compatibility • Gelled scale inhibitor temperature stability and breaking

characteristics • Gelled scale inhibitor shear thinning property • Technical qualification of gelled scale inhibitor by core

flooding for formation damage and inhibitor return profile Based on the results from the lab work and the three case studies presented in this paper, the following conclusions are drawn:

• Gelled scale inhibitor squeeze treatments have been successfully applied for light viscosity diversion in two long horizontal wells with multizone production at the sub sea Norne field.

• Scale protection and squeeze lifetime in the wells were as good as or better than standard treatments.

• The post job analysis indicated that effective viscous diversion was obtained, and that the key to simulate placement correctly is to account for the variation in fluid viscosity due to cool down of the well during pumping.

• Purified xanthan gel showed no formation damage from core flooding experiments and no well damage at the Norne field.

• Gelled scale inhibitor squeeze treatment was only partly successful for the Heidrun A28 A well. The placement of the scale inhibitor seems to be good, but the well was damaged from plugging during injection.

• A well with injectivity problems is not a good candidate for light viscosity diversion.

• Treatment can be pumped at a higher rate due to significant reduction in friction pressure with this system.

• Good quality rheology measurements are important in understanding light viscosity systems regarding shear thinning and breaking mechanisms.

• This technology is particularly beneficial in sub sea wells where coil tubing deployment requires rig deployment and expensive coiled tubing operation.


Name: BioPac, SPbreaker, Scale inhibitor Primary Application: Gravel pack carrier fluid, Gel breaking agent, BaSO4 Scale inhibitor from Champion technologies

TYPE OF

CONTENT







1. Selle, Wat, Vikane, Nasvik, Chen, Hagen, Montgomerie, Bourne, “A way beyond scale inhibitors – extending scale inhibitor squeeze life through bridging” SPE 80377

2. Selle, Wat, Nasvik, Mebratu “Gelled organic acid system for improved CaCO3 removal in horizontal open hole wells at the Heidrun field.” SPE 90359

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SUMMARY OF SCALE REMOVAL PAPER (VISCOSIFIED) SPE 90359

TITLE Gelled Organic Acid System for Improved CaCO3 Removal in Horizontal Openhole Wells at the Heidrun Field

AUTHORS Olav M. Selle; Rex M.S. Wat; Haavard Nasvik (Statoil) and Amare Mebratu (Halliburton)

PRESENTATION or


SPE Annual Technical Conference and Exhibition held in Houston, Texas, U.S.A., 26–29 September 2004.

SUMMARY OF

PAPER

Proper contact with treatment fluids is necessary to remove calcium carbonate (CaCO3) damage from openhole wells. Poor results are often caused by the improper placement of acid. Such was the case in the horizontal, openhole wells with sand screens on the Heidrun Field (Norwegian Sea). In these wells, bullheading plain HCl acid to dissolve carbonate kill pills provided only temporary effectiveness. An operator and a service company initiated a joint project to study Heidrun’s CaCO3 removal problem. Two wells were selected as candidates because of their severe CaCO3 plugging. The team surmised that treatment could be improved with more uniform placement of acid. To provide a more even distribution of the acid treatment, the team developed a gelled organic acid system. This paper describes the product quantification process and the chemistry of the new gelled organic acid system. A diversion technology study screened possible treating methods, and different gelling products were tested for potential formation damage, viscosity profile, and gel breaking characteristics. A purified xanthan polymer with an added breaker was selected for further evaluation. When used to viscosify HCl, the gelbreaking time of the xanthan gel was too short for bullheading applications at Heidrun. Subsequently, an organic acid blend with acceptable CaCO3 dissolution power was formulated, and an environmentally acceptable corrosion inhibitor was incorporated. Two case histories are presented to show that the system was applied with success. The gelled organic acid system is now qualified for use in the Heidrun field. This system is applicable to most types of completions and the paper includes a discussion of its benefits. Based on the results of the two case studies presented in this paper, the following conclusions are drawn: a) Viscous diversion seems to be a good alternative for acid treatment of long horizontal openhole wells with multizone production. b) Purified xanthan gel showed no formation damage from specially designed geldiversion, returnpermeability measurements, while two other commercial gels failed the test. c) It was possible to design a viscous organic acid mixture for Heidrun

field applications. d) The gelled organic acid was successfully deployed in two horizontal wells at Heidrun, and no problems were experienced during pumping or returning the wells to production. e) The intervention in Well A26, the 650 m long horizontal well, indicated that effective viscous diversion was obtained and the resulting productivity was better than most of previous 10% HCl bullheading treatments. f) The intervention in Well A30A, the 73m, upwardsdipping well, indicated that viscous diversion was somewhat better than bullheading but less effective than CT. g) The gelled organic acid was also capable of dissolving equal amounts of CaCO3 particles from killpill material in the two wells compared to the HCl treatments, including the one performed with coiled tubing.


Name: Gelled organic acid is BIOPAC, SPBreaker, Hot rock acid (acetic and formic mix) Primary Application: Carrier fluid for gravel packing, Gel breaking agent, CaCO3 dissolving acid

TYPE OF

CONTENT






1] Completion Tools, 2] Coiled Tubing


4] Stalker, R., Graham, G.M., Oliphant, D., Smilie, M.: “Potential Application of Viscosified Treatments for Improved Bullhead Scale Inhibitor Placement in Long Horizontal Wells – A Theoretical and Laboratory Examination,” paper SPE 87439 presented at the 2004 International Symposium on Oilfield Scale, Aberdeen, UK, 2627 May.

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SUMMARY OF SGA7 PAPER SPE 107687

TITLE Optimization of Surfactantbased Fluids for Acid Diversion

AUTHORS H.A. NasrElDin, A. AlNakhli, S. AlDriweesh (Saudi Aramco); T. Welton, L. Sierra, M. Van Domelen (Halliburton)

PRESENTATION or


This paper was prepared for presentation at the European Formation Damage Conference held in Scheveningen, The Netherlands, 30 May–1 June 2007

SUMMARY OF

PAPER

This paper examines the use of surfactant gels during acid injection and describes the optimization of these fluids. Unlike available viscoelastic surfactants used today in the field, this surfactant is cationic at low pH values. If used in live acids, the fluid has relatively low viscosity when pumped. However, once the acid is spent the surfactant molecules significantly increase the fluid viscosity. To further enhance diversion, the acidic fluid can also be foamed. Alternately, brine gelled with surfactants can be foamed and utilized for diversion. Rheological measurements were conducted on Hastelloy fitted rotational viscometers at temperatures from 70 to 300°F. The effects of surfactant concentration and acid additives on the apparent viscosity of various surfactantbased fluids were investigated in detail. The viscosity of live 20 wt% HCl with the surfactant was much lower than the apparent viscosity of spent acids. Another important observation is the presence of a maximum in the apparent viscosity at 150°F. The apparent viscosity in presence of magnesium chloride was higher than that of calcium chloride. The difference, however, diminished at higher temperatures and reflected the complex nature of surfactantsalt interactions. The apparent viscosity increased by adding salts (sodium and magnesium), especially at higher surfactant concentrations. Surfactant solutions with and without live acid were placed in a high temperature/high pressure (HT/HP) seethrough cell (STC) at various temperatures to examine potential phase separation, thermal stability of the surfactant and compatibility with other acid additives. The results indicated that the surfactant was stable and compatible with other acid additives. No phase separation was noted up to 250°F. Ferric ion is not compatible with this surfactant at high concentrations. The apparent viscosity of the surfactant solutions can be predicted using CarreauYasuda model. Coreflood tests indicated that the surfactant delayed acid breakthrough in carbonate cores. Acceptable corrosion rates were obtained when this surfactant was added to the acid.

The performance of this surfactant was validated with field trials. It was used with up to 28 wt% HCl as insitu acid diverter. Matrix acid treatments that are based on this surfactant were successfully applied in more that 50 wells. It was also used to enhance the stability and apparent viscosity of foams used for acid diversion in power water injectors. All wells responded and no operational problems were encountered.


IN PAPER

Name: SGA7 Primary Application: Surfactant Gelling Agent for Acidising applications

TYPE OF

CONTENT







6. Chang, F.F., Qiu, X., NasrElDin, H.A.: "Chemical Diversion Techniques Used for Carbonate Matrix Acidizing: An Overview and Case Histories," paper SPE 106444 presented at the 2007 SPE International Symposium on Oilfield Chemistry held in The Woodlands, TX, Feb 28 – March 02.

9. Mohammed, S.K., NasrElDin, H.A. and Erbil, M.M.: ''Successful Application of Foamed Viscoelastic SurfactantBased Acid,'' paper SPE 95006 presented at the 2005 SPE European Formation Damage Conference, Scheveningen, The Netherlands, May 25 27.

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SUMMARY OF STIM 2001 PAPER SPE 63179

TITLE Structured Approach to Advanced Candidate Selection and Treatment Design of Stimulation Treatments

AUTHORS

Gerrit Nitters, Leo Roodhart, Hans Jongma (Shell EP Technology Applications and Research), Valerie Yeager, Marten Buijse, Dwight Fulton, Jeff Dahl, Eric Jantz (Halliburton Energy Services, Inc.)

PRESENTATION or


2000 SPE Annual Technical conference and Exhibition, Dallas, Texas, 14 October 2000.

SUMMARY OF

PAPER

High failure rates for matrix acidizing treatments are usually attributed to poor candidate selection and/ or inadequate treatment design. A structured approach to appropriate candidate selection and treatment design should increase the success rate and overall production of candidate wells. Another reason for the high failure of matrix acidizing treatments is the lack of proper technology transfer to the field. Because acidizing fluid selection and placement involve complicated chemistry and technology, information transfer and design can be best accomplished with a software design tool. Stimulation budgets can be more effectively spent when decisions are based on an overall reservoir solution that considers all types of treatments. To improve the situation, a task force investigated the problem and mapped out a total process. They concluded that individual pieces of design, software and some design rules existed for many elements, but they lacked an integrated overall approach. This paper describes a new tool for fast, complete technology transfer through a user friendly, easytouse browser software program. This program puts the latest technology and a structured, engineered solution at the fingertips of every field engineer. Four phases have been used as a basis for developing the new software program. Phase 1 involves candidate selection and damage identification. One goal of the software is to help users wisely apply their stimulation resources (help them treat the right wells and avoid wasting money on the wrong ones). All possible damage mechanisms that should

be considered have been reported. Phase 2 focuses on fluid selection. An expert system, a geochemical simulator and userspecified information can be applied independently or in combination to obtain a complete fluid series. Phase 3 is to design a treatment that will effectively place the fluid so that it will remove the damage hindering production. Placement includes diversion, various placement techniques, the determination of the complete pumping schedule with stages, volumes, and rates, and the simulation of the fluid placement to optimize the design process. In Phase 4, the approach is to evaluate the results and enter this information into the design system.


IN PAPER

Name: STIM2001 Primary Application: Matrix Acid Treatment Design

TYPE OF

CONTENT




Name of competitor and product: StimCADE



Numerous, this paper is also an excellent review paper for matrix stimulation technologies.

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TITLE Structured Approach To Matrix Stimulation Proves Successful in Oman

AUTHORS

Eddie Stevenson, Petroleum Development Oman; Raiturkar Avadhut, Petroleum Development Oman; Khalfan Al Harthy, Petroleum Development Oman; Ramzi Abdulkadir, Hallibuton Energy Services; Marten Buijse, Shell EP Technology Applications and Research

PRESENTATION or


SPE European Formation Damage Conference, The Hague, The Netherlands, 1314 May 2003.

SUMMARY OF

PAPER

In early 2000, the success rate for matrix stimulations matched the industry average of around 30%. In mid2000, an integrated approach was launched, covering all aspects of the stimulation process, and today the success rate for engineered stimulation stands at 85%. Long term sustained gains have been achieved allowing stimulations to become an effective tool for reservoir management. This paper presents some examples of successful matrix stimulation applications using a structured approach. The key to success of any operational activity is ensuring full engagement of all parties. This is achieved within stimulations by applying a process management approach, which covers all aspects from candidate selection to activity review with future plans/requirements proposed. Each step in the process has been mapped out and all contributing parties are identified. There are typically ten steps that define the “fully engineered” approach, although not all steps may be required for each remedial treatment. The ten steps are (1) Candidate selection (2) Completion of stimulation data request forms (SDRS) (3) Using well history (4) Running the integrated stimulation design software (5) UTC calculation and economic challenge (6) Laboratory compatibility testing (7) Finalising stimulation proposal (8) Executing the activity through the service company (9) Hookup/Beamup, and (10) Well performance review. Different wells have been studied. Well1 showed heavy damage immediately after startup. Well2 is located in a

field with poor sandstone. Well3 is again a poor sandstone with high clay content. Well4 was killed with 3% KCl. Well5/6 are water injectors that had been plugged almost completely. These wells are examples of the typical gains that can be expected from the integrated approach. In future, stimulation will continue to play an important role. To be effective, the treatments must be individually designed and based on the integrated, process management approach. Technical experts must keep abreast of all new technologies and techniques and be aware of potential applications within the well stock. Continuous training must be maintained to ensure all relevant parties are aware of the business opportunities available from remedial treatments. This paper documents that 2 MM bbl of additional oil was recovered as a result of using the described process.


IN PAPER

Name: STIM2001 Primary Application: Matrix Acid Stimulation

TYPE OF

CONTENT

þ Case History Laboratory Study






Nitters, G., Roodhart, L., Jongma, H., Yeager, V., Buijse, M., Fulton, D., Dahl, J., Jantz, E.: “Structured Approach to Advanced Candidate Selection and Treatment Design of Stimulation Treatments”, paper SPE 63719, presented at the 2000 Annual SPE Annual Tech Conf., Dallas, Texas, 14 October 2000.

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TITLE Field Validation of Acidizing Wormhole Models

AUTHORS Gerard Glasbergen, Diederik van Batenburg, Mary Van Domelen and Rick Gdanski (Halliburton)

PRESENTATION or


6 th Formation Damage Conference, Scheveningen, The Netherlands, 2527 May 2005.

SUMMARY OF

PAPER

This paper describes how two different wormhole models are implemented in a placement simulator. One model, called a lineartype model, is fully consistent with the decades of linear flow tests conducted in the laboratory. The second model, called a symmetry model, is exceedingly difficult to validate in the laboratory. The evaluation is conducted by comparing the predicted treating pressure responses of the models using the actual treatment rates and fluid properties vs. the actual (measured) pressure response. Several field cases of matrix–acidizing treatments in carbonate formations are used to access the validity of the different wormhole models. There is a small difference between the behaviour of the two wormhole models in the selected case histories. The differences in observed treatment pressure responses between the two wormhole models are too small to determine which one is the better model. Recommendations for improvement of the models have been made based on the comparison. A matrix treatment simulator has been used that includes such effects as multiple formation layers with independent formation parameters and allows for modelling zonal coverage. The formation parameters include permeability, porosity, mineralogy, acid reactivity, skin damage, and permeability contrast. The well parameters include height of the layers, wellbore tubulars, friction pressures, etc. This simulator has been an ideal framework for evaluating the two acidizing wormhole models. The case histories show that correct representation of the placement of the fluids is at least as important as the wormhole model. Flow into the formation is a key for the propagation of the wormholes and correct wellbore friction data and reservoir characteristics play important roles. It is

concluded that wormhole evolution in a placement simulator should ideally be represented by a gradually changing permeability in time and space. This paper also demonstrates the key issues related to the interaction between the wormhole models and zonal coverage.


IN PAPER


TYPE OF

CONTENT







For Linear wormhole model: 1) Buijse, M. A., and Gdanski, R. D.: “ Chemistry and Physics of Wormhole Growth in Carbonate Acidizing,” 8 th International Oil Field Chemicals Symposium, Norwegian Society of Chartered Engineers, Geilo, Norway, March 1997.

2) Buijse, M. A.: “Understanding Wormholing Mechanisms Can Improve Acid Treatments in Carbonate Formations,” SPEPF, 15 (3), (August 2000), pp.168175.

For Radial wormhole model: 1) Gdanski, R. D.: “A Fundamentally New Model of Acid Wormholing in Carbonates,” paper SPE 54719, Presented at the 1999 European Formation Damage Control Conference, The Hague, The Netherlands, May 31June 1, 1999.

2) Gdanski, R. D.: “The Symmetry of Acid Wormholing in Carbonates,” 11 th Int. Oil Field Chemistry Symposium, Norwegian Society of Chartered Engineers, Fagernes, Norway, March, 2000.

For overview of other models: 1) Fred, C. N. and Miller, M. J.: “Validation of Carbonate Matrix Stimulation Models”, paper SPE 58713 presented at the International Symposium on Formation Damage Control, Lafayette, LA, February 2324, 2000.

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TITLE A Semiempirical Model To Calculate Wormhole Growth in Carbonate Acidizing

AUTHORS M. Buijse, Shell Intl. E& P B.V., and G. Glasbergen, Halliburton

PRESENTATION or


2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 12 October 2005.

SUMMARY OF

PAPER

This paper describes the development of a relatively simple wormhole growth model. The model is semiempirical and its accuracy depends on two parameters Weff, the wormhole efficiency factor and WB, the wormhole B factor that can be measured in a simple (linear) core flow test. Alternatively, the value of these two parameters can be taken from literature data. Parameters such as temperature, acid concentration, permeability and mineralogy, have not been modelled explicitly but are incorporated in the model in these two constants. The semiempirical nature of the model gives it flexibility beyond many much more extended models. The wormhole penetration depth is a function of acid volume, coverage and injection rate. In developing the semiempirical wormhole model, it was found that an improved fit of actual treatment data could be obtained if a time delay was incorporated into the equations. The wormhole model was embedded in a comprehensive near wellbore simulator to analyze wormhole behaviour in more complex environments, such as multilayered reservoirs and long horizontal wells. The model has been used with good success in the design of many carbonate acid treatments. Several examples have been discussed in the paper.


IN PAPER


TYPE OF

CONTENT

Case History Laboratory Study ! !

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For Experimental data:

Fred, C.N., Tjia, R. and Fogler, H.S.: “The Existence of an Optimum Damkohler Number for Matrix Stimulation of Carbonate Formations”, Paper SPE 38168 presented at the SPE European Formation Damage Conference, 23 June, 1997, The Hague, The Netherlands.

For Time delay:

Daccord, G., Lenormand, R. and Lietard, O.: “Chemical Dissolution of a porous medium by a Reactive Fluid. –I. Model For the “Wormholing” Phenomenon”, Chem. Eng.Sc., 48(1993) 169178.

For overview of other models:

Fred, C. N. and Miller, M. J.: “ Validation of Carbonate Matrix Stimulation Models”, paper SPE 58713 presented at the International Symposium on Formation Damage Control, Lafayette, Lousiana, Feb. 2324, 2000

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SUMMARY OF STIM2001 PAPER SPE 102412

TITLE Improved Acid Diversion Design using a Placement Simulator

AUTHORS Gerard Glasbergen, Halliburton; Marten Buijse, Shell

PRESENTATION or


2006 SPE Russian Oil and Gas Technical Conference and Exhibition held in Moscow, Russia, 3–6 October 2006.

SUMMARY OF

PAPER

This paper, gives an overview of the different diversion methods and their application. Further, it discusses the implementation of the models in a comprehensive fluid placement simulator (FPS). The work shows how this simulator can be used to optimize placement and diversion. In an acid treatment, the fluid diversion design is often based on guidelines, rulesofthumb, and an intuitive idea on how diversion "works." Simulators are not used, usually because they are not available. However, the use of a diversion simulator shows that many of the guidelines and intuitive ideas are wrong, or at least incomplete; this is illustrated with example calculations.

Two examples of diversion using gelled fluids (in short and long intervals) are simulated. The success of gelleddiversion treatments in shorter intervals depends on the volumes of the ungelled and gelled stage and on the position of the high and low permeability zones relative to the position of the fluid entrance in the wellbore. Often the situation is complex and a simulator is required to visualize fluid placement and to evaluate the success of fluid diversion. A longer wellbore will likely benefit from gelled fluids because of improved fluid coverage.

Validation of the models is presented based on the analysis of two case histories. Several validation methods are used. The applied methods are skin analysis over time, bottomhole and treating pressure comparison over time, and injection surveys. Case1 is a multilayered Russian carbonate reservoir in which different diversion techniques and combination of diversion techniques have been used. Case 2 is a temporarily abandoned, deviated water injection well that was used for a field trial to test a new particulate material.

The predictions of the FPS used in this investigation are in good agreement with measured field data. Pressure predictions follow the measured predictions fairly well. The comparison with injection surveys from a PLT is promising as well. The authors are confident that the model can be used in predictions for zonal coverage within acceptable accuracy when reservoir parameters are known within reasonable uncertainties. The model has also been used successfully in

the design and evaluation of many acid treatments in a large variation of reservoirs worldwide over the last couple of years.


Name: STIM2001

Primary Application: Diversion Design

TYPE OF

CONTENT




Field Study


OPPORTUNITIES FOR OTHER PSL’s Conformance, Sand Control


1. Nitters, G., et al.: “Structured Approach to Advanced Candidate Selection and Treatment Design of Stimulation Treatments,” paper SPE 63179, presented at the 2000 SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 14, 2000.

2. Jones, A.T. and Davies, D.R.: ‘‘Quantifying Acid Placement: The Key to Understanding Damage Removal in Horizontal Wells,’’ SPEPF, 13 (3), (August 1998), pp 163169.

3. Glasbergen, G., et al.: “Field Validation of Acidizing Wormhole Models,” paper SPE 94695 presented at the 2005 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 2527 May.

4. Buijse, M.A. and Glasbergen, G.: “A Semiempirical Model to Calculate Wormhole Growth in Carbonate Acidizing,” paper SPE 96892 presented at the SPE 2005 Annual Technical Conference and Exhibition, Dallas, Texas, 912 October.

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SUMMARY OF STIM2001BIOVERT PAPER SPE 102606

TITLE Design and Field Testing of a Truly Novel Diverting Agent

AUTHORS Gerard Glasbergen, Brad Todd, Mary Van Domelen (Halliburton), Mark Glover (BP, America, Inc.)

PRESENTATION or


SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, U.S.A., 24–27 September 2006. Bibliography No.: SPE 102606

SUMMARY OF

PAPER

This paper presents the work done in a joint project between Halliburton and BP, America, to develop a novel fluiddiversion process. This project resulted in a particulatediversion agent that has several advantages over traditional particulate diverters including little or no environmental impact, negligible solubility at surface conditions, controlled permeability of the filter cake or perforation pack, upper temperature limit significantly higher than traditional diverting agents (excluding salt), compatibility with nearly all treatment fluids, diverter degradation at bottomhole conditions to eliminate posttreatment removal, and excellent regained permeability. A variety of new chemical compositions for the degradable particulate diverting agent (DPDA) were screened and aliphatic polyester diverting agent was selected based upon the criteria required by the operator. An extensive field trial was conducted, incorporating multiple steprate tests, fluidefficiency tests, treatmentpressure matching, pressurebuildup tests, temperature surveys, and injection profiles. These tests were performed in a 226ºF sandstone reservoir at approximately 11,900 ft MD. The application to matrix stimulation and chemical placement techniques using both pressure matches and injection profile matches are unique and novel processes. Injection tests, production log analysis, and posttreatment pressure analysis indicate that DPDA can be placed efficiently in existing perforations, does modify injectivity uniformly across the entire interval, and degrades under bottomhole conditions. From the skin analysis it can be concluded that the DPDA degraded. The placement simulator proved to be a very effective tool when evaluating the field trial. Injection distributions were predicted and compared to the measured distributions with good agreement. In addition the predicted pressure responses matches the measured bottomhole pressures during the majority of the treatment.


Name: BioVert

USED IN PAPER Primary Application: Diverting Agent

TYPE OF

CONTENT




Field Study


OPPORTUNITIES FOR OTHER PSL’s Fracturing, Conformance, Sand Control


1. Nitters, G., et al.: “Structured Approach to Advanced Candidate Selection and Treatment Design of Stimulation Treatments,” paper SPE 63179, presented at the 2000 SPE Annual Technical Conference and Exhibition, Dallas, TX, October 14, 2000.

2. Jones, A.T. and Davies, D.R.: ‘‘Quantifying Acid Placement: The Key to Understanding Damage Removal in Horizontal Wells,’’ SPEPF, 13 (3), (August 1998), pp 163169.

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SUMMARY OF STIMWATCH PAPER SPE 100617

TITLE RealTime Monitoring of Acid Stimulation Using a FiberOptic DTS System

AUTHORS Ray Clanton (OXY, USA), James Haney, Rick Pruett, Courtney Wahl, John Goiffon, and Dan Gualtieri (Halliburton)

PRESENTATION or


SPE Western Regional/AAPG Pacific Section/GSA Cordilleran Section Joint Meeting held in Anchorage, Alaska, U.S.A., 8–10 May 2006.

SUMMARY OF

PAPER

This paper discusses a unique system that combines a fiberoptic distributed temperature system (DTS) to measure the distributed temperature across the entire wellbore and a molecular telemetry transmission system that provides a singlepoint determination of bottomhole pressure. The system has been used to perform realtime downhole monitoring of multistage acidstimulation treatments performed on wells that contain multiple nonisolated pay intervals. The fiberoptic for the DTS is contained inside a length of capillary tubing, which is placed concentrically inside a larger size capillary tubing. The created annulus between these 2 strings of capillary comprises the molecular transmission system for determining the bottomhole pressure. Use of a DTS/PTS (pressure transmission system) system while stimulating offers several advantages over traditional methods. Fluid progress can be monitored over the entire length of the wellbore. A downhole pressure reference can be used to better control pump rates and prevent formation damage. Effectiveness of diverter methods can be monitored in real time. If one diversion method is not effective, another method can be immediately implemented. In the case history presented, the temperature profile across the multiple pay intervals yielded valuable information for identifying which zones were “taking” the acid, allocating how much acid these zones were taking (relative to one another), and identifying the zones not taking acid. This allowed onthefly changes to be made onsite in realtime regarding the makeup of the acid treatment, the pumping rates, and when and where to apply diversion processes. This system enabled the operator to continuously monitor the wellbore temperature across the interval that was being stimulated as well as from a single point bottomhole pressure below the lowest perforation. In this case, the system was deployed inside the work string used for the acid stimulation, but the system can also be permanently deployed. The nominal ratings for this monitoring system are 250°C and 10,000

psi. This allows the system to be applied in a large number of wells, either onshore or offshore. Furthermore, there are no downhole electronics and no moving parts, making the system extremely well suited for harsh environments.


Name: StimWatch® Stimulation Monitoring Service

Primary Application: Matrix Acid Stimulation Monitoring (Realtime downhole fluid placement identification.)

TYPE OF

CONTENT




Field Study



Coiled Tubing, WellDynamics, Completion Products, Wireline and Perforating


2. Wijaya, Z.,Nath, D.K.,Andayani, Y.: “Fiber Optic Used To Support Reservoir Temperature Surveillance in Duri Steam Flood,” SPE Paper 93240 presented at the SPE Asia Pacific Oil & Gas Conference and Exhibition held in Jakarta, Indonesia, 57 April 2005.

3. Nath, D.K., Sugianto, R., Finley,D.: “FiberOptic Distributed Temperature Sensing Technology Used for Reservoir Monitoring in an Indonesia Steam Flood,” paper SPE/PSCIM/ CHOA 97912 presented at the 2005 SPE International Thermal Operations and Heavy Oil Symposium held in Calgary, Alberta, Canada, 1–3 November 2005.

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TITLE RealTime Fluid Distribution Determination in Matrix Treatments Using DTS

AUTHORS Gerard Glasbergen, Dan Gualtieri, Mary van Domelen (Halliburton) and José Sierra (WellDynamics)

PRESENTATION or


European Formation Damage Conference held in Scheveningen, The Netherlands, 30 May–1 June 2007.

SUMMARY OF

PAPER

The application of distributed temperature sensing (DTS) during matrix treatments to monitor the temperature profiles along the wellbore in real time is a recent method to obtain a qualitative indication of the fluid distribution. This paper discusses whether DTS can also be used to quantify the fluid distribution during a matrix treatment. With DTS, the realtime read out is a feasible technique that has been developed to present and evaluate the temperature surveys in real time. Further, a coupled wellbore and nearwellbore thermal model is available that runs in real time. This paper describes these techniques and models and validations using several case histories. In addition, an analysis of matrix treatments using DTS temperature surveys, where available, is presented. The models are used in the analysis to obtain calculated fluid flow distribution. The application of methodology in real time and benefits of quantification of fluid flow distribution are presented. The paper states that knowledge of the zonal coverage of the injected fluid is one of the benefits of quantification. The possibility to determine the flow distribution in real time opens the door to more applications which include (1) considering the effectiveness of diverters, (2) identifying well conditions prior to treatment by quantifying flow distribution during an injectivity test, (3) making realtime treatment decisions, (4) improving future job designs, (5) understanding the reasons for well performance, (6) quantifying damage removal per layer during the treatment, and (7) optimizing fluid volumes. These benefits are discussed in detail. The paper concludes that quantification of the flow distribution in matrix treatments leads to better understanding of placement and diversion and a more efficient use of stimulation fluids. Applying DTS is valuable for stimulation treatments where temperature effects are important, and can lead to better understanding and economic use of additives.


Name: StimWatch

Primary Application: Real Time Diversion Monitoring

TYPE OF

CONTENT




Field Study




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TITLE RealTime Diversion Quantification and Optimization using DTS

AUTHORS Gerard Glasbergen, Dan Gualtieri, Rakesh Trehan, Mary Van Domelen (Halliburton), Micky Nelson (Occidental of Elk Hills).

PRESENTATION or


SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14 November 2007.

SUMMARY OF

PAPER

This paper discusses the application of DTS to quantify the effectiveness of diversion agents. Quantification of fluid distribution makes it possible to determine the flow distribution both before and after a diverter stage so that the diversion effect can be evaluated. Knowledge of the diverter effect will lead to better understanding of the diversion process and subsequently to optimization of future treatment designs. Ultimately, use of real time quantification of the effect of diversion will lead to the development of realtime optimization itself. In realtime optimization, the results of a diverter stage will be used to adjust the next diverter stage to optimize placement. The posttreatment analysis of the temperature profiles showed that flow distribution can be quantified both before and after a diverter stage. Based on the observations, the decision was made to develop a diagnostics tool that can be used in real time and will enable realtime quantification. The novel approach of using the diagnostics tool in combination with DTS during matrix acid treatments will help to further optimize diversion treatments. This optimization is both an optimization during the treatment and an optimization of diverter stages in future treatments. The quantification method uses tracer slugs to evaluate the effect of diversion. The idea is to inject a tracer slug before and after a diverter stage. Evaluating each of these slugs will result in flow distributions before and after the diverter stage and measurement of the diversion effect. The tracer slugs are small volumes of fluid that will have a different temperature signature than the majority of fluids being injected. The concept consists of tracing the leading and trailing edge of the slug at different timestamps and arriving at a fluid velocity profile along the perforations. This velocity profile can be relatively easily converted to a flow rate and leak off profile. An injectivity test before a matrix acid treatment provides a great amount of valuable information that can be used to alter the design for the main treatment. The diversion strategy and concept of tracer slugs to monitor diversion

was applied during a foam acid treatment in the Elk Hills field. Both DTS and realtime downhole pressure measurement were used to monitor the treatment. The combination of realtime skin evaluation with the capability of an onthefly acid blender would allow complete control of an acid treatment. The potential to completely control the stimulation and diversion effect enables bullhead treatments in longer intervals rather than use of mechanical isolation, which can result in time and cost savings. DTS provides information about fluid going out of isolated intervals that could not be observed without this technology.


Name: StimWatch

Primary Application: Real Time Diversion Monitoring

TYPE OF

CONTENT




Field Study




Glasbergen, G. et al. 2007. RealTime Fluid Distribution Determination In Matrix Treatments Using DTS. Paper SPE 107775 presented at the 2007 EFDC, Scheveningen, The Netherlands, 30 May–1 June.

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