2 Oilfield Review

Storing Natural Gas Underground

Alexander BaryFritz CrotoginoBernhard PrevedelHannover, Germany

Heinz BergerEWE AktiengesellschaftOldenburg, Germany

For help in preparation of this article, thanks to ThomasBeutel, Joerg Blecker, Günter Lampe, Olaf Rolfs, RomanRoski, Botho Saalbach and Uwe Schmidt, Hannover,Germany; Ted Bornemann, Houston, Texas, USA; John Cookand Matt Garber, Cambridge, England; Jean-ClaudeHocquette, Meylan, France; Steve Holditch, College Station,Texas; John Kingston, Crawley, England; Mehmet Parlar,Rosharon, Texas; Daniel Sikorski and Jay Terry, Charleston,West Virginia, USA; and Ray Tibbles, Kuala Lumpur, Malaysia.

Underground storage of natural gas is a growing industry that helps gas suppliers meet fluctuating demand. Techniques for

designing, constructing and monitoring gas-storage facilities range from the latest in salt-mining ingenuity to both established

and cutting-edge oilfield technologies.

Kenneth BrownJoseph FrantzWalter SawyerPittsburgh, Pennsylvania, USA

Michael HenzellRosharon, Texas, USA

Klaus-Uwe MohmeyerE.ON Kraftwerke GmbHBremen, Germany

Nae-Kan RenBeijing, China

Kevin StilesDominion (CNG) Transmission CorporationClarksburg, West Virginia, USA

Hongjie XiongHouston, Texas

ADN (Azimuthal Density Neutron), DGS (Delayed GelationSystem), FMI (Fullbore Formation MicroImager), GVR(GeoVision Resistivity), IDFILM, METT (MultifrequencyElectromagnetic Thickness Tool), OFM, RAB (Resistivity-at-the-Bit) and VIPER are marks of Schlumberger.1. http://www.eia.doe.gov/

Summer 2002 3

Energy demands are increasing as the world’spopulation of energy users grows. At the sametime, many people want to decommissionnuclear plants in support of a cleaner environ-ment. Clean-burning natural gas is the fuel mostlikely to meet society’s complex requirements inthe early 21st Century.

Projections for the next 20 years indicateincreases in consumption of energy from nearlyall sources (right).1 The estimated demand fornuclear energy shows a decrease, but use of oil,coal, natural gas and renewable sources willlikely increase, with natural-gas usage showingthe greatest increase.

Current worldwide gas reserves of 5146 tril-lion cubic feet (Tcf) [146 trillion m3] appear suffi-cient to meet projected demand for theforeseeable future. These reserves are currentlyconcentrated in the Former Soviet Union and theMiddle East, far from areas of demand (right). Inabout 2020, gas production will outpace oil pro-duction in barrels of oil equivalent (BOE) per year.However, by then, some countries that currentlyhave adequate gas reserves, the USA included,probably will become importers.

Natural gas has two main uses—generationof electricity and space heating with gas-burningfurnaces. In many parts of the world, demand fornatural gas is seasonal. Typically, more gas isused in cold months than in warm months, but insome regions electricity demand rises again inhot weather because of air-conditioning usage.

In addition to seasonal variation in usage,local power demand usually varies over a 24-hour period, with high demand occurring dur-ing the workday and lower demand at night. Peakdemand periods may last only a half-hour, bututility companies must be prepared to supplyadditional power whenever peaks occur.

Utility companies that burn gas have to buysupplies for their power plants. Long-term con-tracts with gas suppliers ensure a base-leveldelivery for everyday power generation, but seasonal demand may require additional pur-chases at the instantaneous, or “spot,” price at agiven location. When demand is low, utility com-panies sell excess gas on the spot market orstore it, if they can.

Gas suppliers are in a similar situation, andoften enter into “take-or-pay” contracts with gasexporters, oil and gas exploration and production(E&P) companies and pipeline owners. Theselong-term contracts require buyers to pay for anagreed-upon amount of gas, whether there is ademand or not. In times of high demand, gas

suppliers also make spot purchases, but as soonas demand falls, they may opt to store gasinstead of selling it at a low price.

Underground storage of natural gas is animportant way to manage fluctuating prices anddemand. Storage is a vital part of the chain thatlinks upstream oil and gas activities, such asexploration and production, with downstreamdistribution, and ultimately, consumers. Manystorage facilities are managed on a merchantbasis by independent companies whose businessis gas storage. These storage companies provide

gas hubs connected to multiple pipelines for sev-eral gas suppliers and distributors.

This article reviews the history of undergroundgas storage and describes types of storage facili-ties. Several technologies developed for oil andgas formation evaluation, drilling, reservoir char-acterization, completion and stimulation playimportant roles in the gas-storage story. Casestudies demonstrate how these technologies areused to help in the design, construction and mon-itoring of underground gas-storage facilities.

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> Projections of energy consumption. Use of oil, coal, natural gas and renew-able sources, such as hydroelectric energy, will increase, more than makingup for the projected decrease in consumption of nuclear energy. Natural gasshows the largest increase.

IndustrializedAsia Western

Europe Centraland

SouthAmerica

NorthAmerica

Africa

Middle EastEastern Europe and theFormer Soviet Union

DevelopingAsia

Gas Reserves

>Worldwide reserves of natural gas. Total reserves amount to 5146 trillioncubic ft (Tcf) [146 trillion m3]. Most are in regions far from high demand.

Underground Gas-Storage SystemsUnderground storage systems can be constructedin salt formations, porous rock and abandonedmines (above). Porous rock systems may be eitherdepleted hydrocarbon reservoirs or aquifers.

The first recorded underground gas-storagesite opened in 1915, in Welland County, Ontario,Canada.2 In 1916, the Zoar field, near Buffalo,New York, became the first storage project in theUSA, and continues to operate today. These pro-jects injected gas produced elsewhere intodepleted hydrocarbon reservoirs in the summer,and produced the gas for use in the winter. Alsoin 1916, Deutsche Erdoel AG received a Germanpatent on the solution mining of salt cavities forstoring crude oil and distillates.

Over the next decades, there were fewadvances in gas-storage technology, but activityrenewed in the USA by 1950. That year, natural-gasliquids were first stored in a solution-mined saltcavity in the Keystone field, Texas, USA. In 1961,a cavern in bedded salt in Marysville, Michigan,USA, was first used for natural-gas storage.These storage projects were initiated to bring gassupply to growing population centers whendemand exceeded the capacity of steel pipelines.During 1970, the first leached salt-dome cavernfacility opened for gas storage in Eminence,Mississippi, USA. This system was designed toreplace Gulf of Mexico production that had to beshut in during hurricanes. Similar structures havebeen designed to store strategic reserves of oiland gas as national-security measures.

Now there are more than 550 undergroundgas-storage facilities in operation worldwide.About two-thirds of these are in the USA, and themajority of the rest are in Europe. Most storageis in porous rock systems—either depleted oiland gas reservoirs that have been converted togas storage, or aquifers—but some cavern-stylefacilities exist. In Europe, salt-cavern facilitieshave proliferated thanks to an abundance of nat-urally occurring salt deposits and a history of saltmining. Salt caverns are also used for storage inthe USA, especially near the Gulf of Mexico.Storage facilities in abandoned mines or rockcaverns are less common.

One of the leaders in storage-facility designand construction is Kavernen Bau- und Betriebs-GmbH (KBB), now a Schlumberger company. KBBhas been involved in more than 100 such projectsworldwide (next page, top). Each project requires petrophysical and mechanical characterization ofthe proposed subsurface location to ensure thatformation properties are suitable for long-termgas storage. Salt formations are evaluated forrock strength and volume. Porous rock formationsare assessed for structural closure, seals andadequate porosity and permeability to sustainhigh deliverability rates.

Two important parameters for all under-ground storage facilities are the working-gas vol-ume, or gas available for withdrawal, and themaximum withdrawal rate over a defined periodof time. Working gas is determined by the storage-facility volume and the difference

between maximum and minimum gas pressures.A volume of gas, called cushion gas, alwaysremains in storage. The maximum withdrawalrate from storage can be limited by flow resis-tance in the production well and in porous rock.

Well-construction techniques for gas-storagewells must ensure that wellbores tolerate highinjection pressures, high production rates andfrequent cycling—injection followed by produc-tion. Gas-storage wells also have long lifetimes,80 or more years, compared with oil and gas pro-duction wells.

In the following sections, we first describetechnologies used to create salt-cavern facilities,and then highlight case studies in porous rock.

Storage in Salt CavernsSalt has several properties that make it ideal forgas storage. It has moderately high strength andflows plastically to close fractures that could oth-erwise become leaks. Its porosity and permeabil-ity to liquid and gaseous hydrocarbons are nearzero, so stored gas cannot escape. Salt cavernsprovide high deliverability; gas can be withdrawnquickly because there is no pressure loss fromflow through pores. Cavern storage can cycle—switch from injection to production—in a matterof minutes, and contains a large fraction of work-ing gas relative to total gas. Salt caverns are thepreferred option for merchant storage, becausethey allow frequent cycling and high rates ofinjection and production.

4 Oilfield Review

> Underground storage systems constructed in salt (left), abandoned mines (center) and porous rock (right).

Summer 2002 5

Exploration for salt bodies relies on electro-magnetic, seismic and gravimetric surveys,because salt’s conductivity, velocity and densityare in high contrast with those of surroundingrocks. Borehole logs and coring help assess saltstructure and composition. Salt can occur in lay-ers, but such evaporite accumulations often con-tain anhydrite, limestone and dolomite, which donot dissolve. Salt domes tend to have morehomogeneous composition than mixed evaporitelayers, and are preferred for gas storage becausethey dissolve more uniformly and can accommo-date larger caverns.

Rock-mechanical investigations are an essen-tial component of storage design. Theoreticalcalculations help determine the suitability of agiven salt formation to house a cavern. Thesecalculations require knowledge about the saltstructure and strength, and help verify the shapeand location of the cavern, separation betweencaverns, and cavern stability at operating pres-sures (below).

2. “Natural Gas Storage: Historical Development &Expected Evolution,” GasTIPS (June 1997):GasTechnology Institute. http://www.gri.org/pub/con-tent/nov/19981103/165547/gts97-b-01.html

Salt-cavern storage Brine or saltproduction

Porous-rockstorage

Rock-cavern storage Special mineral-saltproduction

> Locations of caverns and salt-production projects constructed by Kavernen Bau- und Betriebs-GmbH (KBB). In addition to hydrocarbon-storage facilities, KBB builds and manages facilities for brine,salt and other mineral production.

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> Building a salt-cavern rock-mechanical model. Well logs and cores help construct a simplified geological profile (left). This serves as the basis for thetheoretical rock-mass model (middle left) for the salt and bounding layers. A two-dimensional finite-element calculation model (middle right), symmetricabout the cavern’s vertical axis, divides the theoretical model into elements for stress calculation. The resulting calculations reveal the stress distribution(right) around the proposed cavern.

Salt deforms plastically in relatively shorttime frames, explaining its superb sealing quali-ties. While this property helps maintain imper-meability and keeps salt caverns from fracturingunder large stress changes, it also means thatcaverns will shrink over time. Experiments on saltcores help determine formation strength anddeformation characteristics (above).

Well logs and salt cores are studied to deter-mine the optimal dissolution process for creatingsalt cavities (above right). The presence of insol-uble impurities is an important factor in deter-mining the best leaching tactics, but cannotalways be identified on well logs; cores providesamples for laboratory solution testing.

Cavern development involves drilling a wellthrough which fresh water will enter and wastebrine will exit (right). This well also is used forgas injection and withdrawal, and will typicallyhave casing cemented to the top of the cavern.When drilling through salt, brine-saturated mudhelps avoid excess dissolution of salt while thehole is drilled to the cavern bottom. A typical cas-ing plan includes a 28-in. conductor pipe, inter-mediate 24-in. or 20-in. casing if required byoverburden, 185⁄8-in. or 16-in. surface casing setin caprock, and finally 133⁄8-in. or 11-in. casingcemented below the salt top. Leaching and pro-duction strings hang into the cavern from the lastcemented casing.

Before leaching operations can begin, ahydraulic well-integrity test (WIT) is performed toconfirm that the well system—wellhead, lastcemented casing, casing shoe and open sectionof hole—is sound. During storage and retrievaloperations, the highest differential pressuresexperienced by the cavern are at the lastcemented casing shoe, and this is where themaximum pressure is experienced during a WIT.

In one salt-cavern well, the WIT exhibitedunacceptable hydraulic losses. Further investiga-tion pointed to a weak zone, probably a microan-nulus between cement and salt, at the 133⁄8-in.shoe. Traditional repair options were reviewed,but found to be inadequate. Squeezing cementthrough perforations might damage the integrity

6 Oilfield Review

> Results of laboratory experiments to determinestrength and deformation properties of saltcores. The two cores in the foreground exhibitplastic deformation. The two cores immediatelybehind them show fracturing.

10 µm

> Salt cores (left) and photomicrograph (right) prepared for dissolution studies.Mineral composition and salt texture can affect the dissolution process, andmust be characterized to optimize cavern construction.

Gas

Brine

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Water

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> Effects of relative positions of freshwater injection and brine withdrawal indirect leaching (left) and reverse leaching (right). More salt is dissolved at thelevel of water injection, creating a wider cavity at that depth. Injection andwithdrawal levels can be modified to control cavern shape.

Summer 2002 7

of the last cemented casing, and cementing anadditional liner would limit the size of the leach-ing and production strings.

Completion engineers selected theSchlumberger DGS Delayed Gelation Systemfluid for squeezing into the cemented annulus.The DGS fluid maintains a low viscosity until aninternal catalyst causes the gel to form. The gelwas squeezed while an inflatable straddle-packer assembly separated the cemented casingaround the shoe from the openhole section. The packers also isolated the section for a sec-ond WIT run to verify repair-job success (left).Once well integrity was confirmed, leachingcould commence.

In the leaching process, fresh water ispumped down one tubing string of the well, andbrine is returned through another. Roughly eightvolumes of water are required to dissolve onevolume of salt. The cavern roof is protected fromuncontrolled dissolution by pumping in a protec-tive fluid, usually liquefied gas—typically nitro-gen—that floats on the surface of the brine.Below this protective blanket, the cavern can besolution-mined in approximately cylindrical formin accordance with the rock-mechanical and solution-mining calculations and targets. The rel-ative depths of the leaching strings can be modi-fied to control the shape of the cavern. The shapeand size of the resulting cavern can be confirmedwith sonar caliper tools (left).

The produced brine can be used by the chem-icals industry for salt and other mineral extrac-tion, released into nearby seas if allowed, ordisposed of by injection into other rock layerswith sufficient injectivity. In some cases, wastebrine is disposed of in abandoned salt mines.

Undissolved impurities in the salt form awater-saturated residue, or sump, in the bottomof a cavern. After the cavern is filled with dry gas,water from the sump will evaporate into the gasas the gas is produced. The depressurization ofthis wet gas may cause the formation of hydratesthat can block downhole pipes and surface facil-ities. Cavern pressure, temperature, humidity anddewpoint should be monitored to determine con-ditions for hydrate-free gas withdrawal. Injectionof inhibitors to prevent hydrate formation is acommon practice before gas withdrawal.

The time required to create a cavern dependson solubility of the salt and the desired size ofthe cavern. One recently constructed cavern facil-ity consists of five separate salt caverns about250 m [820 ft] high and 40 m [131 ft] across.Construction costs, including drilling wells,leaching salt, installing surface facilities andinjecting cushion gas totaled US $150 million.

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> Fluid-loss rates from well-integrity tests (WITs) before and after isola-tion repair. The WIT conducted before repair (blue dots) showed con-tinuing high losses, indicating a probable microannulus between saltand cement at the 133⁄8-in. casing shoe. After DGS Delayed GelationSystem gel was squeezed through perforations at this zone, a secondWIT showed controlled losses (red dots).

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> Cavern shape delineated by sonar measurements.

Total project duration from feasibility to hookupand commissioning was more than five years.KBB is constructing a cavern that, when finished in2003, will be the largest in the world (above).

Another example of a cavern gas-storagefacility is in Nuettermoor, Germany. TheNuettermoor location provided operator EWEAktiengesellschaft, Oldenburg, with ideal condi-tions: salt of high quality, a favorable locationwithin the transport network, problem-free extrac-tion of fresh water and disposal of brine into theEms estuary. The caverns in Nuettermoor are up to400 m [1312 ft] high and 75 m [246 ft] wide.

The Nuettermoor facility has 18 caverns ofwhich two are still under construction. The totalgeometrical cavern volume is about 8.5 million m3

[300 MMcf] and can accommodate about 1.3 billion m3 [46 Bcf] of natural gas, of which80% is working gas and 20% is cushion. Theminimum operating pressure is approximately 30bars [440 psi], and the maximum pressure isapproximately 150 bars [2200 psi]. One of thelargest of its type in the world, the Nuettermoorfacility guarantees a significant part of theGerman energy supply.

Another example of cavern gas-storage is thefacility in Huntorf, Germany, operated by E.ONKraftwerke GmbH. Four gas-storage cavernswere created by dissolution of a Permian saltdome in 1975 for a total volume of 1.1 million m3

[39 MMcf]. Each cavern is 220 to 275 m [720 to900 ft] high and about 60 m [200 ft] across atmaximum width. With a maximum storage pres-sure of 100 bars [1450 psi], the total storagecapacity is 137 million m3 [5.10 Bcf]. Of this, thevolume of working gas is 68 million m3 [2.53 Bcf],and the remainder is cushion gas. Adjacent to the Huntorf facility is a compressed-air energy storage facility (see “Storing Compressed-AirEnergy,” page 10 ).

Drilling Porous-Rock Gas-Storage WellsMost gas-storage facilities are in the porous rockof depleted gas reservoirs that have been inoperation for decades. Depleted fields are lessexpensive to develop than other types of instal-lations, because existing production wells andgathering lines can be converted for storage use.In many cases, depleted fields contain the basegas needed to operate a storage facility. In gen-eral, porous-rock facilities are appropriate forseasonal and strategic-reserve storage. Limitedproduction capacities and deliverability constraintheir use for supplying energy during peak-loadelectricity generation. Operators of these fieldscontend with many of the same problems that oiland gas E&P operators experience, and oftenapply proven oilfield technology to increase fieldcapacity and improve rates of gas deliverability.

8 Oilfield Review

In 1998, CNG Transmission, now part ofDominion Transmission, made plans to create ahigh-deliverability horizontal well by reenteringan existing well in the South Bend gas-storagereservoir, Armstrong County, Pennsylvania, USA.If a short-radius sidetrack could be drilled withcoiled tubing and could follow the sands in thefluvially deposited 100-Foot Sand ofMississippian age, CNG Transmission wouldhave a cost-effective way to improve field perfor-mance.3 The resulting well would tie into theexisting pipeline infrastructure and surface facil-ities, and underbalanced coiled tubing drillingwould cause minimal environmental impact withreduced formation damage.

The South Bend gas field was discovered in1922, and was converted to gas storage in 1951.Reservoir capacity is 17.34 Bcf [491 million m3] ofwhich 5.81 Bcf [164 million m3], or 33.5%, areavailable for withdrawal. The field contains61 injection-withdrawal wells and 4 observationwells. Seventy-five percent of the gas deliver-ability comes from only 12 wells, evidence thatreservoir heterogeneity has made for challengingwell placement.

To enhance the chances for a successful hor-izontal sidetrack, the company needed to under-stand the petrophysical characteristics andstratigraphic nature of the high-quality sandswithin the 100-Foot Sand formation. The existingopenhole well was cleaned, and slimhole wire-line logs and images were acquired. Image logsfrom neighboring wells were also examined(above). Interpretation of the complete dataset

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> A large cavern measuring 400 m highand 80 m across. The Eiffel Tower inParis, France would fit inside.

Top of zoneof interest

Best porosity

Bottom ofzone

10 ft

> Borehole resistivity image from the FMI Fullbore Formation MicroImagertool showing a high-porosity, high-resistivity target for the CNG Transmis-sion horizontal gas-storage well. The short-radius sidetrack, drilled withcoiled tubing, helped increase deliverability by 840%.

N O R T H S E A

Germany

Breitbrunn/Eggstattgas field

1000 m

Summer 2002 9

indicated a 14-ft [4-m] zone of high porosity dip-ping 3 to 4° SSW. The new well was planned toenter this zone and continue for a 500-ft [152-m]horizontal section.

The original wellbore casing dated back to the1920s, and was deemed too fragile for conven-tional rotary drilling. The sidetracking plan wasfurther complicated by the presence of a depleted“thief zone” behind the casing string set immedi-ately above the reservoir section. To avoid enter-ing the thief zone, the sidetrack would have tokick off in openhole using a cement plug insteadof a more accepted mechanical whipstock.

The sidetrack kicked off 5 ft [1.5 m] below the51⁄2-in. casing shoe with a Schlumberger VIPERcoiled tubing drilling steerable bottomholeassembly (BHA). A steerable BHA and motorwere deployed on 23⁄8-in. coiled tubing with awireline installed to drill the 43⁄4-in. horizontalwell. Because reservoir pressure had declined,the well ended up being drilled with a 200-psi[13.6-atm] overbalance pressure. The perfor-mance of this system surpassed expectationsand achieved build rates of up to 100° per 100 ft[30 m], which exceeded the planned 65° per100 ft. However, unexpectedly hard rock requiredseveral bit changes and slowed the rate of pene-tration, so the well plan was revised to stopdrilling 290 ft [88 m] after kickoff.

Two months after cleanup, well performancehad increased from 0.337 MMscf/D to2.83 MMscf/D [9650 m3/d to 81,050 m3/d], adeliverability increase of 840%.

After the successful results of this first side-track, CNG Transmission used coiled tubing todrill short-radius sidetracks in two other wells.The second well exhibited a 320% increase indeliverabilty, and deliverability of the third wellincreased by 2400%.

Drilling Under PressureWhile gas-storage reservoirs in the northeasternUSA tend to be in relatively shallow formations ofcompetent porous rock, facilities elsewhere in theworld experience drilling conditions and wellbore-stability problems that require different solutions.

In one example, Wintershall AG planned todrill a series of additional horizontal wells in theirunderground gas-storage reservoir in Rheden,Germany. To avoid mud losses in the reservoirsection, wells had to be drilled while storagepressure was at its highest. To ensure adequatewell control, Schlumberger, Wintershall and thedrilling contractor jointly developed a set of strictoperational procedures. These included preven-tive measures and emergency-response proce-dures to ensure the correct sequence of actionsto avoid critical situations.

Reservoir pressures were so high that in theearly stages of well construction, the drillstringwas not heavy enough to run in without beingpushed. Tripping pipe out for a BHA or bit changeand pushing the BHA back into the hole underhigh pressure required a snubbing unit to pushthe BHA downhole. The Sedco SN24 snubbingunit selected for the job had to undergo structuralmodifications approved by the responsible min-ing authorities to fit into the derrick of the drillingrig. Once the drillstring weight was high enoughto overcome the gas pressure in the wellbore, thestring could be run without snubbing-unit assis-tance. At that point, the snubbing unit could berigged down and removed from inside the rigmast, and the drilling crew could continue withnormal drilling operations.

The snubbing unit was required whenevertripping out of the hole until reaching total depth(TD) and completing the well at TD. The lastoperation with the Sedco SN24 unit was the run-ning of a 7-in. liner. This procedure is now certi-fied and available for future undergroundgas-storage drilling applications.

Imaging While Drilling The Breitbrunn/Eggstatt gas field in Bavaria,Germany, was discovered in 1975. The field pro-duced from vertical wells in four sands until1993, when the uppermost layer, Layer A, wasconverted into a gas-storage reservoir. In 1996,demand for natural gas during winter months led

to a campaign to double the storage capacity ofthis anticlinal reservoir by additional drilling intoLayers C and D, two deeper, less homogeneoussands.4 The deeper layers consist of isolatedsand lenses that could suffer sanding problemsduring production cycles. Intersecting as manysand lenses as possible required drilling horizon-tal wells with real-time logging-while-drilling(LWD) data for geosteering. LWD data would alsohelp optimize trajectory orientation to avoidazimuths prone to sanding.

Geological, petrophysical and geomechanicalstudies conducted before drilling improved theaccuracy of the reservoir structural model, helpedassess sand distribution and wellbore stability,and aided in the selection of drilling mud andLWD tools that would allow successful wellsteering within the thin—5- to 15-m [16- to 49-ft]—reservoir layers. The structural modelachieved 99.9% depth accuracy, or maximuminaccuracy of 1.5 m, by including resurveyed welllocations, directional surveys and log-derivedmarkers from existing wells.

Petrophysical and stratigraphic evaluationpredicted that reservoir sands would be presentas isolated lenses. To penetrate as many lensesas possible, well trajectories were designed ingentle U-shaped profiles to traverse Layers C andD from top to bottom and back to the top withineach horizontal section (above).

3. Stiles EK, DeRoeun MW, Terry IJ, Cornell SP and DuPuy SJ:“Coiled Tubing Ultrashort-Radius Horizontal Drilling in aGas Storage Reservoir: A Case Study,” paper SPE 57459,presented at the SPE Eastern Regional Meeting,Charleston, West Virginia, USA, October 20–22, 1999.

4. Rohler H, Bornemann T, Darquin A and Rasmus J: “TheUse of Real-Time and Time-Lapse Logging-While-DrillingImages for Geosteering and Formation Evaluation in theBreitbrunn Field, Bavaria, Germany,” paper SPE 71733,presented at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September 30–October 3, 2001.

< The Breitbrunn/Eggstattgas field in Bavaria, Germany,converted to gas storage in1993. In 1996, the addition ofsix horizontal wells doubledstorage capacity. Horizontalwells are the best way tointersect the maximum num-ber of the isolated sands thatconstitute the gas-storagelayers. Here, a gently curvingwell trajectory traverses thetarget layer from top to bot-tom and back again (inset).

(continued on page 12)

10 Oilfield Review

Natural gas is not the only type of gas that iseconomically worthwhile to store in caverns.Compressed air, which is also needed by power-generating plants, can also be stored in com-pressed-air energy storage (CAES) facilities.

The basic idea of CAES is to store off-peakenergy produced by nuclear or coal-fired unitsas compressed air to be used in high-demandperiods. During low-cost, off-peak load periods,a motor consumes power to compress and storeair in underground salt caverns (left). Duringpeak load periods, the compressed air is withdrawn to burn natural gas in surface combustion chambers.

In pure gas-turbine power stations, about two-thirds of the output is used to compress the combustion air. In a CAES power station, no additional compression is necessary, becausethe air is already compressed. A CAES facilitycan use all output for power generation.

To date, two CAES plants have been built, one at Huntorf in 1978, and the second atMcIntosh, Alabama, USA, in 1991 (next page, top).1

A third is being planned for a 10 million m3

[353 MMcf] limestone mine in Norton, Ohio, USA.The two compressed-air storage caverns atHuntorf are about 250 m tall and 60 m across, fora total volume of 310,000 m3 [11 MMcf].

To monitor gas-storage cavern stability, asonar tool performs regular surveys of the cav-ern shape to assure storage-facility longevity.Frequent pressure and temperature changesassociated with air injection and withdrawal can affect salt stability. To conduct work on the wellheads or production strings, it is sometimesnecessary to reduce cavern air pressure at theHuntorf facility to atmospheric pressure. Thispressure reduction could allow the salt to flowplastically, a phenomenon known as salt creep.Also, stresses in the outlying salt volume cancause large amounts of deformation. One cavernin Mississippi is reported to have suffered a 50%loss in volume due to salt convergence.

Surveying cavern contours of the HuntorfCAES facility has been difficult because theultrasonic tools used in natural-gas caverns have

Storing Compressed-Air Energy

> Corrosion of casing in the Huntorf salt-cavern CAES facility. Evenfiberglass-reinforced plastic (FRP), which replaced the original steelcasing in the 1980s, has experienced corrosion. Logging for casingevaluation can verify the effectiveness of corrosion-avoidance mea-sures, such as injection of dry air between steel and FRP.

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> Power generation at the Huntorf compressed-air energy storage(CAES) facility during a 24-hour period. During off-peak periods, air iscompressed and stored underground (pink). During peak periods, thecompressed air is withdrawn (blue) and burned with natural gas togenerate electricity.

Summer 2002 11

inadequate range in humid CAES caverns.Instead, surveying with a heated laser toolshows how little the contours of the cavern wallhave changed during the 20 years of operation(below right).

A critical aspect when designing the compressed-air wells was the specification for extremely high withdrawal rates with lowpressure losses. This required a 241⁄2-in. lastcemented casing size and a 21-in. production tub-ing string. Because there is no packer sealing thetubing-casing annulus, the last cemented casingstring is open to corrosion. Water in the sump ofundissolved components on the cavern floor saturates the compressed air, making it highlycorrosive. At Huntorf, attempts to counteract cor-rosion of the final casing are made by injectingdry air into the annulus.

To further reduce the impact of corrosion, the production string inside the last cementedcasing was made of extra-thick steel. However,after only a few months of operation, seriouscorrosion problems became apparent with theappearance of rust in filters upstream of the gasturbine. Fiberglass-reinforced plastic (FRP)replaced the 133⁄8-in. steel production casing inthe 1980s. Now, however, even the FRP stringsare experiencing partial destruction (previouspage, bottom).

To replace the FRP in one well, the damagedsection was removed, and the 241⁄2-in. lastcemented steel casing was cleaned and theninspected using METT MultifrequencyElectromagnetic Thickness Tool logs to assesswall thickness. Because of the large casingdiameter, the tool was used outside its usualmeasurement range of up to 133⁄8 in. Evaluationof the logs indicated that the corrosion-protec-tion measures of injecting dry air between thesteel and FRP casings had successfully inhibitedcorrosion of the steel casing. No pitting or corro-sion was seen on the steel surface.

Dept

h, m

20 m 0 m 20 m 20 m 0 m 20 m600

650

700

750

1984 sonar2001 laser

Cavern-Shape Monitoring

> Monitoring salt-cavern shape and size. The similarity between the contoursdetected with a sonar tool in 1984 and those seen by laser measurements in2001 show how little the two caverns have changed shape in nearly 20 yearsof operation.

1. Crotogino F, Mohmeyer KU and Scharf R: “Huntorf CAES:More Than 20 Years of Successful Operation,” presentedat the Solution Mining Research Institute Meeting,Orlando, Florida, USA, April 15–18, 2001.

Aerial View of the Huntorf CAES Plant

Air-storagecavern 1

Air-storagecavern 2

Power plant

> Compressed-air energy storage facility andpower plant at Huntorf, Germany.

Well trajectories were also designed to mini-mize wellbore instability and sanding. A geome-chanical study indicated the maximum horizontalstress is oriented N-S, minimum horizontal stressis oriented E-W, and the intermediate stress isvertical. Based on this information, and assumingisotropic rock strength, wells would be designedto trend N-S. However, rock-strength testsshowed distinct strength anisotropy, with maxi-mum strength in the N-S direction and reachingthree times the minimum-strength value. In addi-tion, stress was considered likely to increase onthe flanks of the anticline. Wells placed closer tothe anticlinal axis, away from the flanks, wouldbe more stable. This led to a final selection ofNE-SW, along the anticlinal axis, as the optimalwell azimuth.

Geomechanical analysis also influenced thechoice of drilling mud. Sometimes, foamed mudsare selected for underbalanced drilling to preventinvasion in depleted reservoirs destined tobecome gas-storage fields. In this case, a water-base mud would provide better borehole stabilityand produce a thin mudcake on the borehole wallto reduce invasion.

This type of mud system would allow all con-ventional LWD logging and imaging techniquesto be performed with real-time data transmis-sion. The GVR GeoVision Resistivity tool, which isa recent version of the RAB Resistivity-at-the-Bittool, was selected because of its ability to differ-entiate sand lenses from bounding shales. TheADN Azimuthal Density Neutron tool was chosento assist in identification of clay features and car-bonate concretions. Together, these tools made itpossible to assess porosity and sand content

while drilling the 81⁄2-in. horizontal sections downand up within the C and D layers.

Computed dips from GVR real-time imagesdefined the relative position of the boreholewithin the reservoir (below). Drilling up- or down-section is easily recognizable on these images.The sinusoidal bed boundaries point upholewhen drilling down-section, and downhole whendrilling up-section.5

After drilling, all LWD, wireline and core datawere analyzed for the final petrophysical evalua-tion. Zones of highest permeability were selectedfor perforation, as long as the geomechanicaldata indicated that sand-free production wouldbe possible. Oriented perforating guns weredeployed to place perforations in sand and not,for example, in an underlying shale lens or a car-bonate concretion.6

With these techniques, three horizontal wellswere drilled and completed in each of the twoinhomogeneous sands. Each well exceeded 1000 m[3280 ft] in length, and together, the six wellsdoubled Breitbrunn storage capacity to 1.085 bil-lion m3 [38.3 Bcf].

Sand Control for Gas-Storage WellsSand control can be a major concern in somegas-storage wells, especially since they experi-ence repeated cycles of high-rate injection andproduction. Controlling sand production was aprimary objective for Taiwan Petroleum andExploration, a division of the Chinese PetroleumCorporation, when they initiated a project in1997 to deepen six wells in the Tiehchenshanreservoir and establish a gas-storage facility.

12 Oilfield Review

Tubing hanger

Safety valve

Expansionjoint

Sliding sleeve

Snap latchseal assembly

Packer

Flapper valve

95/8-in.casing shoe

Gas-storagezone

> A typical gravel-pack completion (not to scale)in the six-well Tiehchenshan gas-storage project,Taiwan. The storage formation was a poorly consolidated sandstone, and each well requiredsand-control treatment to sustain high gas-injection and withdrawal rates.

Real-Time GVR GeoVision Resistivity Image

Drilling direction

10 m

> A real-time GVR GeoVision Resistivity image from a horizontal well in the Breitbrunn gas-storagefield. Bed-boundary dips from the GVR image define the relative position of the borehole within thereservoir. When drilling down through a layered section, bed boundaries point uphole. Bed boundariespoint downhole when drilling up through a section. In this image, the bit is moving from right to left,drilling down through the section.

8. Brown KG and Sawyer WK: “Novel Surveillance HelpsOperators Track Damage,” paper SPE 75713, presentedat the SPE Gas Technology Symposium, Calgary, Alberta,Canada, April 30–May 2, 2002.

9. Brown KG and Sawyer WK: “Practical Methods toImprove Storage Operations—A Case Study,” paper SPE57460, presented at the SPE Eastern Regional Meeting,Charleston, West Virginia, USA, October 20–22, 1999.

Summer 2002 13

The storage formation at 2800-m [9184-ft]depth is a poorly consolidated sandstone withnegligible shale content. Average porosity is20% and permeability is 250 mD. To sustain thespecified maximum injection and withdrawal rateof 28.2 MMscf/D [808,000 m3/d] per well, all sixwells would be completed with openhole gravelpacks. Each well had already been predrilledwith 95⁄8-in. production casing cemented justabove the reservoir.

The Tiehchenshan project allotted 12 days perwell for a total of 72 days to deepen the sixwells. The work scope included cleaning the 95⁄8-in. casing, drilling an 81⁄2-in. openhole sectionfor about 30 to 40 m [100 to 130 ft], coring five ofthe six wells, placing gravel pack, running a finalcompletion string and cleaning up the wells (previous page, left).

The project was completed in 60 days withtwo rigs and no lost-time incidents. Completionspecifications included a pickle treatment of10 bbl [1.6 m3] of 15% HCl, corrosion inhibitorand iron-chelating agent.7 Then followed a 20-bbl[3.1-m3] scrubber treatment of 40 pounds perthousand gallons (ppt) hydroxyethyl cellulose(HEC) gel containing 400 lbm [181 kg] of20/40 sand.

The gravel pack consisted of 10 bbl of 40-pptHEC gel pad, followed by circulating 40-ppt HECgel and gravel concentration of 1 pound proppantadded (ppa) per gallon of slurry. Some wells hadslurry packs of 80-ppt HEC gel and 4 ppa per gallon of slurry. Post-pad treatment was 5 bbl

[0.8 m3] of 40-ppt HEC gel. The completion fluidleft in the casing annulus for each well was amixture of 8.47-ppg 3% potassium chloride [KCl]with IDFILM 820X corrosion inhibitor to minimizebacteria and corrosion buildup throughout the lifeof the wells. Each well was cleaned up and flow-tested with positive results.

The gravel packs have successfully preventedsand production during the three years of gasproduction since these wells were constructed.The wells have not yet been used for gas injec-tion, but throughout this time, well deliverabilityhas remained at the high levels initially achievedbecause of the successful gravel packs.

Monitoring Gas-Storage WellsAll gas-storage facilities require some type ofmonitoring to make sure wells can deliver oraccept gas at required flow rates. High flow ratesexperienced during gas withdrawal can cause for-mation damage in the near-wellbore region.Similarly, well damage may occur during high-rateinjection. Damage may also result from switchingfrequently from withdrawal to injection.

Well monitoring in porous rock systems tradi-tionally consists of performing surface tests ofbackpressure every 1 to 2 years. A surface back-pressure test consists of shutting the well in fora few hours for stabilization and then alternatelyflowing and shutting in the well over a 4- to 8-hour period. Flow rate is controlled and surfacepressures are recorded, typically every 5 to 10 minutes, during flow and shut-in periods.

Data from a conventional backpressure testcan be used to predict flow rate, or deliverability,for any reservoir pressure and wellhead pressure.Thus, any damage that has occurred since thelast test will be evident. However, infrequenttesting may fail to identify wellbore damage intime to avoid lost deliverability and also canmake it difficult to determine the cause of dam-age. More frequent testing using downhole pres-sure gauges is usually considered too expensive.In the surface tests, individual wells are flowedat a variety of rates to determine well deliver-ability and to detect any damage incurred sincethe last test.

Engineers at Schlumberger Data and ConsultingServices have developed a new way to useresults from surface measurements to quantifywellbore damage over time.8 Only one initialpressure-transient test analysis (PTTA) usingdata from a downhole gauge is required. Thenew method has been tested using data from a gas-storage well in a sandstone reservoir in theeastern USA.

The well selected for validation of the newmethod was initially tested in June 1996. A deliv-erability test was conducted with a bottomholepressure gauge installed. Pressure-transient testanalysis of the bottomhole gauge data helped todetermine the well’s mechanical skin, sm, andnonDarcy factor, D, as of June 1996. The totalskin, sT, is given by sT = sm + Dq, where q is thewell flow rate. The product Dq is called the non-Darcy skin and is caused by high flow velocitiesnear the wellbore.

The well was subsequently tested in June1997, and two days later it was hydraulicallystimulated. Two additional tests were conductedin September 1997 and May 1998. In each ofthese three tests, a deliverability test was con-ducted and surface pressures were recorded. Tovalidate the new method, a bottomhole pressuregauge simultaneously provided downhole datafor determination of mechanical skin and non-Darcy factor. These values were then calculatedfrom the surface data alone and compared withmeasured PTTA values (above left).

The new method makes it reasonable for oper-ators to monitor wells more frequently at minimalcost. Implementation of this technique may pro-vide insight into the source of damage in gas-stor-age wells, allowing repairs or mitigation beforedeliverability declines to uneconomic levels.

In another study, Schlumberger consultantshave shown how multirate flow tests can helpdetermine reservoir quality, quantify inventoryvolume, construct a total system model, catalogdownhole and surface-facility bottlenecks, andeven determine the horsepower required to cyclethe working gas multiple times per year.9

Another source of valuable monitoring infor-mation comes from wellhead electronic flow

5. Bonner S, Fredette M, Lovell J, Montaron B, Rosthal R,Tabanou J, Wu P, Clark B, Mills R and Williams R:“Resistivity While Drilling: Images from the String,”Oilfield Review 8, no. 1 (Spring 1996): 4–19.

6. Almaguer J, Manrique J, Wickramasuriya S, Habbtar A,López-de-Cardeñas J, May D, McNally AC and Sulbarán A:“Orienting Perforations in the Right Direction,” OilfieldReview 14, no. 1 (Spring 2002): 16–31.

7. A pickle treatment uses a chemical blend, usually acidand inhibitor, to remove rust and scale from tubularsbefore pumping a gravel-pack treatment.

Skin

Skin-5 0 5 10 15 20

-5

0

5

10

15

20

Calculated mechanical skinfrom deliverability testsMeasured mechanical skinfrom PTTA

> Comparison of mechanical skin measuredby pressure-transient test analysis (PTTA)with skin calculated from deliverability tests.The good match proves that calculated val-ues can be used in place of measured values.The method requires initial measurementswith a downhole pressure gauge.

measurements (EFM). EFM equipment measures,stores and transmits gas rate and pressure datafrom the wellhead to an office computer. Thesesystems are not yet commonly installed in gas-storage wells, but are becoming more popular.

An EFM system installed in the Belle River Mills gas-storage field in Michigan in themid-90s helped engineers detect operationalproblems that rendered several wells inopera-ble.10 The measurements also helped assess theimpact of subsurface safety valves on well deliv-erability and formed part of an automated systemdesigned to alert field operators to deterioratingwell performance.

Michigan Consolidated Gas Company oper-ates the Belle River Mills field, a Niagaran-agereef structure that was discovered in 1961 andconverted to gas storage in 1965. The field has 23active injection-withdrawal wells capable of producing in excess of 1.2 Bscf/D [34 million m3/d]during peak flow periods. Wide variations in flowrate are common within a single day.

Early reservoir-surveillance methods con-sisted of backpressure tests every three to fiveyears to assess well deliverability, and differen-tial pressure tests two to four times per year todetermine the contribution of each well to totalfield flow.

Installation of wellhead EFM devices nowallows operators to continuously monitor welldeliverability and all flow parameters. A computernetwork links the wells and polls them once perhour. The hourly readings are compressed andtransferred to the corporate office once a day.These frequent updates help identify operationalproblems, such as valve malfunction, in additionto chronic problems, such as wellbore damage.

One way to identify anomalous well perfor-mance is through bubble plots of relative produc-tion rates from EFM data. The OFM productionmanagement software system can be used tomonitor well performance. A bubble plot for atypical day at the Belle River Mills field showslower withdrawal rates from wells on the flanksof the reef, where rock quality is poor, but allwells are contributing to production (above left).On another day, several wells exhibited problems(left). Wellsite inspection revealed that safety-valve control lines had lost hydraulic pressure,resulting in 150 MMscf/D [4.29 million m3/d] oflost deliverability throughout the field. Detectingthis problem within a day helped to maximizedeliverability at minimal cost.

In addition to pressure measurements formonitoring gas storage, some experiments inseismic monitoring have been conducted in

14 Oilfield Review

Bubble Map Showing Production Problems

> A bubble plot showing production problems detected by electronic flowmeasurements (EFM) in the Belle River Mills gas-storage field. Several wellsin the high-quality central portion of the field show lower production rates(smaller bubbles). Some wells show no production (open circles). Investigationexposed problems with safety-valve control lines, which were quickly repaired.

Typical Bubble Map of Withdrawal Rate

> A bubble plot showing relative production rates from wellhead electronicflow measurements (EFM) on a typical day in the Belle River Mills gas-storage field. Lower production (smaller bubbles) is expected on the flanks, or edges, of the structure where reservoir quality is low. The center of the field shows higher production (larger bubbles). An open circle indicates awell with no production.

Summer 2002 15

France, where the Institut Français du Pétroleand Gaz de France have monitored acoustic emis-sions in underground gas-storage facilities.11

Newer experiments have monitored gas-columnheight and saturation using time-lapse surfaceseismic and borehole seismic imaging.12

Rehabilitating Damaged Gas-Storage WellsThe American Gas Association estimates a deliv-erability loss of about 3 Bscf/D [85.9 million m3/d]in the more than 15,000 gas-storage wells oper-ating in the USA. Gas-storage operators spendmore than $100 million annually to restore lostdeliverability either by remediation or drillingnew wells.

Some of the damage mechanisms, such asinvasion and sanding, are familiar to E&P opera-tors, while other mechanisms, such as bacterialgrowth or compressor oil plugging pores, aremore specific to gas injection and storage (right).The Gas Technology Institute (GTI) recently con-ducted a research project to investigate damagemechanisms in gas-storage wells.13 To supplydata for this investigation, gas-storage operatorsevaluated cores, fluids and tests from wells inmore than 10 storage fields. Four main types ofdamage were identified:• bacteria• inorganic precipitates, such as iron com-

pounds, salts, calcium carbonate and bariumsulfate

• hydrocarbons, organic residue and productionchemicals

• particulates.In the study wells, sand production, mechani-

cal obstruction, completion- and stimulation-fluidproblems, and relative-permeability effects wereless frequent problems.

All these damage mechanisms require differ-ent stimulation methods to restore injectivity anddeliverability, and over the years, a great deal ofexperience has been accumulated on the diagno-sis of damage mechanisms and design of stimu-lation techniques.

To capture this knowledge and make it avail-able to engineers in the gas-storage industry,Schlumberger and the GTI developed theDamageExpert computer model for diagnosingformation damage.14 The model, designed forgas-storage wells, combines gas-storage-domainknowledge bases, fuzzy logic and expert-systemtechnologies. Based on user input, the programhelps diagnose the most likely type of formationdamage and then helps select the best stimula-tion and fluid treatment.

The first step in the system development con-sisted of building a knowledge base. This in turnconsists of two parts: knowledge acquisition andknowledge representation. Knowledge acquisi-tion is the process of extracting and organizingknowledge from experts in the domain and fromtechnical literature. For this system, the knowl-edge comprised information and experience fromoperators, service companies and other expertson formation-damage mechanisms in gas-storage wells as well as the corresponding treat-ment methods.

Next, the acquired knowledge is represented,or structured, in a way that makes the problemeasier to solve. In this case, knowledge baseswere built for four steps of the problem-solvingsequence: candidate selection, damage-mecha-nism diagnosis, treatment recommendation andtreatment evaluation.

The domain knowledge was representedusing fuzzy logic combined with production rules,neural networks and genetic algorithms. Fuzzy

logic is a way of representing knowledge that isdifficult to capture in a strict rules-based system.Classical binary rules-based logic solves prob-lems by filling in statements such as, “If condi-tion A is true, then situation B exists.” The

10. Brown KG: “The Value of Wellhead Electronic FlowMeasurement in Gas Storage Fields,” paper SPE 31000,presented at the SPE Eastern Regional Meeting,Morgantown, West Virginia, USA, September 19–21, 1995.

11. Deflandre J-P, Laurent J and Blondin E: “Use ofPermanent Geophones for Microseismic Surveying of aGas Storage Reservoir,” presented at the 55th EAEGMeeting and Technical Exhibition, Stavanger, Norway,June 7–11, 1993.

12. Dumont M-H, Fayemendy C, Mari J-L and Huguet F:“Underground Gas Storage: Estimating Gas ColumnHeight and Saturation with Time Lapse Seismic,”Petroleum Geoscience 7, no. 2 (May 2001): 155–162.

13. GRI: Investigation of Storage Well Damage Mechanisms,GRI-98/0197 (April 1999). The Gas Technology Institute(GTI) was formerly known as the Gas Research Institute(GRI).

14. Xiong H, Robinson B and Foh S: “Using an Expert Systemto Diagnose Formation Damage Mechanisms and DesignStimulation Treatments for Gas-Storage Wells,” paperSPE 72374, presented at the SPE Eastern RegionalMeeting, Canton, Ohio, USA, October 17–19, 2001.

Particulates

Hydrocarbon residue

Inorganic precipitates

Bacteria

> Main types of damage in gas-storage wells. Operators identified four main mechanisms that plugpores and impair deliverability: bacteria, inorganic precipitates, hydrocarbon residue and particulates.

statement can be only true or false. The mathe-matical values for the truth can be only one fortrue or zero for false. Under fuzzy logic, truth val-ues can range between zero and one, and cantake on linguistic variables, such as highly, large,somewhat and rarely. Fuzzy logic provides a wayto help emulate the thought process of an engi-neer who is diagnosing formation damage anddesigning a removal treatment.

Information flows through seven modulesduring the diagnosis and treatment-design pro-cess (left). The data-input module receives infor-mation such as well identification, dimensions,completions and history, along with reservoir rockand fluid-property data. All subsequent modulesuse this input information.

Next, the damage-mechanism diagnosis mod-ule analyzes the input information to identifypossible types of wellbore and formation dam-age. Mechanisms are ranked from most likely toleast likely. This module can be bypassed if theuser is confident that the damage mechanism is known.

The treatment-feasibility module determineswhether the well is a good candidate for damage remediation. This is followed by the treatment-selection module, which recommends the best available treatment for removing the identi-fied damage.

The treatment-fluid module helps select thebest fluid to use for a matrix treatment or well-bore wash. The module checks on formation andfluid compatibility, and specifies the necessaryfluid additives to avoid undesirable chemicalreactions. The pumping-schedule module recom-mends a combination of injection rate and fluidvolume for each zone to be treated. And, finally,the reporting module issues reports from any ofthe other modules.

The expert system was tested on several gas-storage wells, and information was fed backto improve the system. One example well wascompleted openhole with cemented casingabove the gas-storage sandstone reservoir. Thewell had moderate deliverability at 2500 Mscf/D[71,600 m3/d], and its withdrawal capacity haddeclined by 53%.

The damage-mechanism module indicatedthat plugging of pores and relative-permeabilityeffects were the dominant causes of damage tothe wellbore (left). The treatment-selection mod-ule proposed a wellbore wash or matrix treat-ment with nearly even likelihood of success (nextpage, top). Once the user selected a matrix treatment,

16 Oilfield Review

> Diagnosing storage-well damage. Given the input information, the Damage-Expert system determined that plugging and relative-permeability effectswere the dominant causes of damage to the wellbore, along with iron oxide[Fe2O3], calcium carbonate [CaCO3], iron sulfide [FeS2] and chloride scales.

Damage-mechanism moduleWell informationdatabase

Fluidsdatabase

Knowledge bases

Data-input module

Reporting module

Pumping-schedule module

Treatment-fluid module

Treatment-selection module

Treatment-feasibility module

> Modules of the DamageExpert computer model for diagnosing damagemechanisms in gas-storage wells.

Summer 2002 17

the expert system suggested stimulation fluidsand a pumping schedule (bottom right).

The well was stimulated with the recom-mended treatment, which included surfactant,iron inhibitor, corrosion inhibitor and divertingagent. After the treatment, gas deliverability wasfive times greater than before.

Beyond StorageUnderground gas storage is just one of the indus-tries that is developing to meet the world’s grow-ing and rapidly changing energy needs. InEurope, for example, the European Union (EU)Parliament Gas Act of 1998 requires all countriesto liberalize their gas and electricity sectors overthe next decade. Success of this type of deregu-lation—designed to increase competition anddecrease total cost—will demand new efficien-cies in the gas-supply chain.

Full gas supply-chain management meansreal-time monitoring and control of the transportof gas from the wellhead, via the pipeline andliquified natural gas (LNG) grid, through storagefacilities to the burner tip of the end consumer. Itwill also include information technology servicesto facilitate asset management, third-partyaccess, customer care, billing and trading.SchlumbergerSema Energy & Utilities is design-ing and implementing this type of systems solu-tion for customers in many projects worldwide.Such large-scale integration projects could ini-tially entail developing a satellite-network solu-tion to connect producing gas fields, gatheringand pipeline stations, underground gas-storagesites and gas-export terminals to a centraldatabase. The ultimate project goal would be toinstall Internet-accessible gas-trading andexchange hubs in the major consumer areas andat export border check-points, similar to theSchlumbergerSema-designed and operated elec-tricity trading hub that is currently in place forAPX in Amsterdam, The Netherlands.

The anticipated rise in gas consumption andcontinued deregulation will create opportunitiesand bring changes in business practices for oiland gas E&P companies, gas-transport and stor-age companies, gas-trading companies, utilitiesand service companies. Making the most ofthese opportunities will require vigilant technol-ogy development and application of tools andservices that increase efficiency and value. —LS

> The treatment-selection module showing highest confidence in the successof two possible treatments—wellbore wash and matrix treatment. The userselected matrix treatment and moved to the next module for fluid selection.

> Fluid selection and pumping schedule proposed by the DamageExpert sys-tem. The expert system recommends parameters for each stage of the treat-ment, including stage volume, injection rate and chemical composition.