Oilfield Review Summer 2008 - Schlumberger - Oilfield...

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34 Oilfield Review Sand Injectites Eric Braccini Total E&P Angola Luanda, Angola Wytze de Boer Marathon Oil (United Kingdom) Ltd. Aberdeen, Scotland Andrew Hurst Mads Huuse Mario Vigorito University of Aberdeen Aberdeen, Scotland Gerhard Templeton Maersk Oil North Sea UK Limited Aberdeen, Scotland For help in preparation of this article, thanks to Aimen Amer, Luanda, Angola; Robert S. Freeland, University of Tennessee, Knoxville, USA; Gretchen Gillis, Sugar Land, Texas, USA; Karen Sullivan Glaser and Matthew Varhaug, Houston; Lars Hamberg and Cecilie Dybbroe Tang, DONG Energy, Hørsholm, Denmark; Patrice Imbert, Total E&P, Pau, France; Eric Jameson, Marathon Oil, Aberdeen; David McCormick, Josephine Ndinyah and Richard Plumb, Cambridge, Massachusetts, USA; David Mohrig, The University of Texas, Austin; Chris Murray, Pacific Northwest National Laboratory, Richland, Washington, USA; William Schweller, Chevron Energy Technology Company, San Ramon, California, USA; and Ian Tribe, Aberdeen. FMI (Fullbore Formation MicroImager), OBDT (Oil-Base Dipmeter Tool), OBMI (Oil-Base MicroImager), PeriScope, Q-Marine and UBI (Ultrasonic Borehole Imager) are marks of Schlumberger. Sandstone dikes and sills, known as sand injectites, have long been considered mere geological oddities. However, many operators are beginning to understand the impact—both positive and negative—that injectites can have on E&P endeavors. By using outcrop studies, core and log data and careful seismic illumination, companies are now finding that some of these geological anomalies can be attractive exploration targets and of huge significance when planning and optimizing hydrocarbon recovery. > Common sand-injection features. Feature A is a depositional sand body that is also the parent body for many of the injectites. B is a thick sill. C is a complex of thin sills and dikes. D is a set of sills that link with dikes in a stepping fashion. E is a large, irregular intrusive body that contains clasts of host rock. F is a sill from Parent Body A that is crosscut by a dike from Parent Body J. G denotes sand extrusions and volcanoes. H represents gas seeps. I indicates conical sand injections. (Adapted from Hurst and Cartwright, reference 2.) 100 to 500 m Modern seafloor Ancient seafloor A B C D E F G G H H 20 to 100 m J

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34 Oilfield Review

Sand Injectites

Eric BracciniTotal E&P AngolaLuanda, Angola

Wytze de BoerMarathon Oil (United Kingdom) Ltd.Aberdeen, Scotland

Andrew HurstMads HuuseMario VigoritoUniversity of AberdeenAberdeen, Scotland

Gerhard TempletonMaersk Oil North Sea UK LimitedAberdeen, Scotland

For help in preparation of this article, thanks to Aimen Amer,Luanda, Angola; Robert S. Freeland, University of Tennessee,Knoxville, USA; Gretchen Gillis, Sugar Land, Texas, USA;Karen Sullivan Glaser and Matthew Varhaug, Houston; LarsHamberg and Cecilie Dybbroe Tang, DONG Energy, Hørsholm,Denmark; Patrice Imbert, Total E&P, Pau, France; Eric Jameson,Marathon Oil, Aberdeen; David McCormick, Josephine Ndinyahand Richard Plumb, Cambridge, Massachusetts, USA; David Mohrig, The University of Texas, Austin; Chris Murray,Pacific Northwest National Laboratory, Richland, Washington,USA; William Schweller, Chevron Energy Technology Company,San Ramon, California, USA; and Ian Tribe, Aberdeen.FMI (Fullbore Formation MicroImager), OBDT (Oil-BaseDipmeter Tool), OBMI (Oil-Base MicroImager), PeriScope, Q-Marine and UBI (Ultrasonic Borehole Imager) are marks of Schlumberger.

Sandstone dikes and sills, known as sand injectites, have long been considered

mere geological oddities. However, many operators are beginning to understand the

impact—both positive and negative—that injectites can have on E&P endeavors.

By using outcrop studies, core and log data and careful seismic illumination, companies

are now finding that some of these geological anomalies can be attractive exploration

targets and of huge significance when planning and optimizing hydrocarbon recovery.

> Common sand-injection features. Feature A is a depositional sand body that is also the parent bodyfor many of the injectites. B is a thick sill. C is a complex of thin sills and dikes. D is a set of sills thatlink with dikes in a stepping fashion. E is a large, irregular intrusive body that contains clasts of hostrock. F is a sill from Parent Body A that is crosscut by a dike from Parent Body J. G denotes sandextrusions and volcanoes. H represents gas seeps. I indicates conical sand injections. (Adapted fromHurst and Cartwright, reference 2.)

100 to 500 m

Modern seafloor

Ancient seafloor

A

B

C

D

E

F

G

G

H

H

20 to 100 m

J

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Sandstones and other clastic rocks are createdfrom wind- and waterborne sediments that settleunder the force of gravity. Younger sediments aredeposited on top of older ones. This observationis a cornerstone of geology.

Most sedimentary sequences retain thisarrangement unless faulting or folding placesolder above younger rocks. However, anothermechanism can disrupt the natural order;overpressured sediments can become remobil -ized and force their way upward, intruding intooverlying layers as the fluids carrying them seeklower pressures.

Structures formed by sediment injection arecalled injectites, or clastic intrusions. Becausethey resemble intrusive and extrusive igneousfeatures, much of the vocabulary for describinginjectites has come from igneous geology(previous page). Sills are emplaced parallel tobedding, whereas dikes cut through bedding. Thestrata containing the intrusion are called hostrock, and the layers that feed the intrusion arethe parent beds. In contrast, depositional bedsare those that have formed by settling oftransported sediment, not by injection. Sand-injection features exhibit size scales frommillimeters to kilometers, and have been seen incores, borehole image logs, seismic sections,outcrops, aerial photographs and satelliteimages. They have even been tentativelyidentified on photographs of Mars.1

E&P companies are learning that many oiland gas reservoirs in ordinary depositionalsandstones have connections to injectites. This isimportant for two main reasons. First, injectedsand can add volume to a reservoir, and add it inlevels that are structurally higher than the mainreservoir. Furthermore, injected sands typicallyhave high porosity and permeability, formingexcellent pay zones. Detecting the location andshape of injectites may help pinpoint additionalreserves and improve drilling success.

The second reason for interest in injectites ishydraulic communication. Injectites can improveconnectivity between reservoir layers, which mayallow reserves to be drained with fewer wells andless cost. However, increased connectivity canalso have a negative impact. The presence ofinjectites indicates a breach in the caprock thatnormally seals hydrocarbons within a reservoir. Ifa reservoir seal has been breached, the oil andgas might have escaped or be in communicationwith another reservoir. Injectites can also affectconnectivity with aquifers. These are importantconsiderations for optimizing field developmentand modeling reservoir behavior.

In this article, we review some of what hasbeen learned about injectites from outcropstudies and subsurface exploration. We alsodiscuss a few of the known hydrocarbonreservoirs currently believed to be associatedwith sand injectites and describe the impact ofinjectites on their development.

Early RecognitionClastic intrusions have been recognized inoutcrops, mines and subsurface data all aroundthe world (above).2 They have been described ingeological literature as far back as 1821.3 Duringhis voyage from 1832 to 1836 on the HMS Beagle,

Charles Darwin described a dike in easternArgentina as remarkable, slightly tortuous, andformed chiefly of rounded grains of quartz.4 Overthe next 170 years, geologists continued to reportthe presence of sandstone and other clastic dikesand speculate about their origin.5

In the early days of injectite observation, itwas believed that clastic intrusions could formonly if a large crack was open to the surface andfilled with sediments from above. Some clasticdikes, called Neptunian dikes, do form in thismanner, when extreme pressures from glaciersor other heavy depositional loads forcesediments down into underlying layers. It was

1. http://mars.jpl.nasa.gov/mgs/msss/camera/images/science_paper/f5/ (accessed July 11, 2008).

2. Hurst A and Cartwright J: “Relevance of Sand Injectitesto Hydrocarbon Exploration and Production,” in Hurst Aand Cartwright J (eds): Sand Injectites: Implications forHydrocarbon Exploration and Production, AAPGMemoir 87. Tulsa: AAPG (2007): 1–19.Ribeiro C and Terrinha P: “Formation, Deformation and Chertification of Systematic Clastic Dykes in a Differentially Lithified Carbonate Multilayer. SW Iberia,Algarve Basin, Lower Jurassic,” Sedimentary Geology 196,no. 1–4 (March 15, 2007): 201–215.Neuwerth R, Suter F, Guzman CA and Gorin GE: “Soft-Sediment Deformation in a Tectonically ActiveArea: The Plio-Pleistocene Zarzal Formation in the Cauca Valley (Western Colombia),” Sedimentary Geology 186, no. 1–2 (April 15, 2006): 67–88.Dharmayanti D, Tait A and Evans R: “Deep-Water Reservoir Facies of the Late Jurassic Angel Fan, DampierSub-Basin, Australia,” Search and Discovery Article 30044,posted November 4, 2006, http://www.searchanddiscovery.net/documents/2006/06127dharmayanti/index.htm(accessed May 21, 2008).

Chi G, Xue C, Lai J and Qing H: “Sand Injection and Liquefaction Structures in the Jinding Zn–Pb Deposit,Yunnan, China: Indicators of an Overpressured Fluid System and Implications for Mineralization,” EconomicGeology 102, no. 4 (June–July 2007): 739–743.Truswell JF: “Sandstone Sheets and Related Intrusionsfrom Coffee Bay, Transkei, South Africa,” Journal of Sedimentary Petrology 42, no. 3 (September 1972): 578–583.

3. Strangways WTHF: “Geological Sketch of the Environs ofPetersburg,” Transactions of the Geological Society ofLondon 5 (1821): 392–458. Cited in Newsom JF: “ClasticDikes,” Bulletin of the Geological Society of America 14(1903): 227–268.

4. Darwin CR: Geological Observations on South America.Being the Third Part of the Geology of the Voyage of theBeagle, Under the Command of Capt. Fitzroy, R.N. Duringthe Years 1832 to 1836. London: Smith Elder and Co. 1846.The Complete Work of Charles Darwin Online http://darwin-online.org.uk/content/frameset?viewtype=side&itemID=F273&pageseq=164 (accessed May 20, 2008).

5. Diller JS: “Sandstone Dikes,” Bulletin of the GeologicalSociety of America 1 (1889): 411–442.Newsom JF: “Clastic Dikes,” Bulletin of the GeologicalSociety of America 14 (1903): 227–268.

> Locations of clastic intrusions identified in outcrops, mines and subsurface data. (Adapted fromHurst and Cartwright, with additional data from Ribeiro and Terrinha; Neuwerth et al; Dharmayanti et al; Chi et al; and Truswell, reference 2.)

Injectite location

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not until 1869 that a geologist proposed thatsediments could be intruded from below.6

An 1899 investigation of sandstone dikes innorthern California concluded that the intrusionsin question must have been formed by sand fillingfissures from below.7 The study noted that not allthe dikes reached the surface and includeddescriptions of fine-scale banding with parallelarrangements of mica plates and coarse and finesand along the sides of dikes. Some sandstoneintrusions also contained fragments of the hostrock. Geologists still use these characteristics,among others, to help distinguish clastic sills anddikes from depositional beds.

Another early observation on sandstone dikessuggested that oil could migrate through them toshallower reservoirs, or leak to the surface.8

Highly pressurized hydrocarbons have beenconsidered a possible source of the pressure andfluids responsible for injectite formation.9 Thisand other proposed causes of injectite formationare discussed later in this article.

Geologists and other E&P professionals arerevisiting surface exposures of injectites in thehopes of using them as analogs, or models, forinjectites encountered in the subsurface. Someof the larger outcrops, which appear to havespatial scales approaching those of majorsubsurface injectites, occur in the Panoche Hillsand near the Santa Cruz coast, both in California;the Magallanes basin, southern Chile; andTabarka, Tunisia. In this article, we describesome features of the injectites of the PanocheHills, what they suggest about injectite originsand how they can be used to better understandsubsurface injectites.

Outcrop ObservationsThe Panoche Hills are on the western edge ofCalifornia’s San Joaquin Valley. Sand-injectionfeatures were first recognized there in the early1900s, and have been studied by many groups.10

The vast network of sandstone sills and dikescrops out over an area greater than 350 km2

[135 mi2] and is observable in outcrop and aerialand satellite photographs (above left).

The sediments in the study area—the GreatValley sequence—were eroded from the SierraNevada mountains to the east during the LateJurassic and Cretaceous. These sediments, insome places 12 km [7.4 mi] or more thick, werelaid down in deep water as submarine fans andturbidites with interbedded siltstones andclaystones. Mud-rich sediments up to 1 km [0.6 mi] thick were deposited atop the sandyunits, creating a low-permeability seal.

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> Sand injectites of the Panoche Hills, California. This network of light-colored sandstone dikes andsills emplaced in darker mudstone extends for another 700 m [2,300 ft] to the north. Apparent beddingis horizontal; sills are aligned horizontally and dikes crosscut bedding. The inset (bottom left ) showsan interpretation of dike and sill arrangement (black lines).

CaliforniaPanoche Hills

500 m

1,640 ft

North South

> Light-colored sandstone sills in darker mudstone. Sills with thicknessesup to 6 m were injected into mudstone and are linked by steps, essentiallydikes, that cut across bedding.

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In the Early Paleocene, a major injectionevent formed the giant Panoche injectitecomplex. This event emplaced fine- to medium-grained sands from Cretaceous submarine fansinto overlying mud-rich sediments. The injectitecomplex has a stratigraphic thickness of morethan 1,200 m [3,940 ft], and probably exceeded1,600 m [5,250 ft] before compaction.

Parts of the complex are dominated bystaggered sills—sills that rise from one level toanother in steps—at least 6 m [20 ft] thick(previous page, bottom). Some sills appear to befilled with mainly clean sand, while otherscontain rafts, or large inclusions, of clay-rich hostrock (right). Where sills have intruded, the hostrock is “jacked up,” showing apparentthickening. In portions of the complex, longdikes extend up to 1,200 m in length (belowright). In general, dike thickness decreases withdistance from the parent bed.

Some of the dikes reached the ocean floor,extruding sand onto the paleo-seabottom.Identification and dating of marine fossils alloweddetermination of an approximate timing of theinjection event. Isotopic analysis of calcitedeposited during fluid expulsion through theinjectites indicates that fluids seeped to the surfaceover a 2-million-year interval during the Danianstage, approximately 62 to 65 million years ago.11

6. Wurtz H: “On the Grahamite of West Virginia and the New Colorado Resinoid,” Proceedings of the AmericanAssociation of Science 18 (1869): 124–135. Cited in Newsom, reference 5.

7. Diller, reference 5.8. Newsom, reference 5.

Anderson R and Pack RW: “Geology and Oil Resources of the West Border of the San Joaquin Valley North of Coalinga, California,” US Geological Survey Bulletin 603 (1915).

9. Jenkins OP: “Sandstone Dikes as Conduits for OilMigration Through Shales,” AAPG Bulletin 14, no. 4 (April 1930): 411–421.

10. Anderson and Pack, reference 8.Jenkins, reference 9.Zimmerman J Jr: “Tumey Sandstone (Tertiary), Fresno County, California,” AAPG Bulletin 28, no. 7 (July 1944): 953–976.Payne MB: “Type Moreno Formation and OverlyingEocene Strata on the West Side of the San JoaquinValley, Fresno and Merced Counties,” California Divisionof Mines and Geology, Special Report 9 (1951).Smyers NB and Peterson GL: “Sandstone Dikes and Sills in the Moreno Shale, Panoche Hills, California,”GSA Bulletin 82, no. 11 (November 1971): 3201–3208.Friedmann J, Vrolijk P, Ying X, Despanhe A, Moir G andMohrig D: “Quantitative Analysis of Sandstone IntrusionNetworks, Panoche Hills, CA,” presented at the AAPG Annual Meeting, Houston, March 10–13, 2002.Vigorito M, Hurst A, Cartwright J and Scott A: “Regional-Scale Subsurface Sand Remobilization: Geometry andArchitecture,” Journal of the Geological Society 165, no. 3 (2008): 609–612.

11. Minisini D and Schwartz H: “An Early Paleocene ColdSeep System in the Panoche and Tumey Hills, CentralCalifornia, U.S.A.,” in Hurst A and Cartwright J (eds):Sand Injectites: Implications for HydrocarbonExploration and Production, AAPG Memoir 87. Tulsa:AAPG (2007): 185–197.

> A sandstone sill with large inclusions of host rock. The sill of light-colored sand contains large rafts, or inclusions, of darker mudstone hostrock that have been ripped up during intrusion. The inclusion nearest thegeologist has retained its horizontal orientation, but the inclusions to theleft have rotated. With this style of sill emplacement visible in outcrop, it iseasy to imagine that in the subsurface, large inclusions would have anunexpected and negative impact on wellbore stability and might be avoidedby acquiring the appropriate LWD measurements.

> Long dikes extending into the distance. These sandstone dikes (D)extend from the geologists in the foreground across several ravines andhills, approximately 1,200 m to the east (into the photograph). They aremore competent than the surrounding host rock, and so do not erode aseasily. The light-colored sill (S) in the foreground is the top of the sillcomplex seen in the photograph at the bottom of the previous page.

DD

D

S

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The whole sequence was tilted toward theeast in the Paleocene during regional uplift thatalso formed the Coast Ranges to the west of theSan Joaquin Valley, at the same time as thedevelopment of the San Andreas transformmargin. Because of this tilt and subsequenterosion, the entire injection section, from parentrock to extrusion on the seafloor, can be seen in outcrop.

Another feature of the Panoche injectitecomplex is the presence of crosscutting dikes of different mineralogy (above). This indicates that several parent beds sourcedinjections independently during a single phase of sand injection.

The distribution and orientation of injectitesat the Panoche site provide some insight into thestate of stress at the time of sand intrusion. In

general, fractures open in planes perpendicularto the least principal stress. Therefore, wheresills dominate the injection style, the minimumstress direction was vertical. The alignment ofdikes over a great distance indicates that theywere emplaced when the least principal stresswas acting mainly in one horizontal direction.The presence of dikes in all directions, and ofdikes along with sills, indicates isotropic stressconditions.12 All these scenarios were active indifferent parts of the Panoche injectite complex.

Mechanics of Sand IntrusionThe mechanics of large-scale sand intrusion arenot well-known. One approach considersinjectites as natural examples of the inducedhydraulic fractures performed to stimulatereservoirs.13 With this approach, injection can bemodeled if the conditions of the injection eventare known or assumed. However, in most cases,neither the background conditions—such asfluid source, mode of sediment transport, depthand pore pressure of the parent sand, stressregime, and intrusion-emplacement depth andgeometry—nor the triggering mechanisms arewell understood. It also is not clear whetheroverpressured fluid initiates the fractures, whichare later filled with sand—analogous toproppant filling hydraulic fractures—or if thesand-laden fluid is the fracturing agent.

In spite of these limitations, there is somegeneral agreement about the three mainingredients required for generation of sandintrusions.14 The first is the occurrence ofunconsolidated sand encased in low-permea bilitymudstones. The size of the intrusion depends inpart on the amount of sand available. Small sand-rich channels can exhibit injection wings, but forlarge-scale intrusions, a greater volume of sandmust be present. Extremely large volumes ofinjected sand have been encountered—in somecases, 10 to 100 million m3 [350 million to 3.5 billion ft3].15 Also required are large volumesof fluid to transport the sand upward.

The second condition is overpressure causedby one or more mechanisms, such as disequi -librium compaction, lateral or deep pressuretransfer, fluid buoyancy and salt diapirism.Disequilibrium compaction arises when fluid-filled sand buried under low-permeabilitymudstone cannot expel pore fluids and compactnormally. Lateral pressure transfer, in the form oflarge-scale slumping, may impart overpressure toa buried sand body. Deep pressure transfer ariseswhen high overpressures from deep within asedimentary basin reach shallower levels.Migrating hydrocarbons, which are more buoyant

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> Evidence of multiple parent beds. A golden-orange intrusion trendingfrom lower left to upper right is cut by a whiter intrusion that intersects itnearly perpendicularly at the feet of the geologist (arrow). Sand intrusionsof different colors indicate sources from multiple parent beds. Crosscuttingimplies multiple injection episodes.

> One set of well data, two models of sandstone distribution. Interpretation of well data depends onworking models. Log interpretation that originally predicted a distribution of thin, “ratty” sands abovethe main reservoir (top) may be modified if injectites are included in the interpretation (bottom).(Adapted from Hurst, reference 32.)

Ratty sands (depositional)

Blocky sands (depositional)“M

igration noise”

Differential compaction

“Migration noise”

Ratty sands(injected)

Blocky sands (injected)Sand wingSand

wing

Jacked-up host rock

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than water, could enter water-filled sand andincrease fluid pressure. Rising salt diapirs maycreate overpressure by pushing fluids ahead ofthem.16 Any of these mechanisms, alone or inconcert, could cause enough overpressure toinduce liquefaction, the condition in which thefluid—not the sand grains—bears theoverburden pressure, thereby reducing the shearstrength of the sand-fluid mixture to zero.

The third requirement is a triggering event,such as an earthquake, meteorite, comet orasteroid impact, volcanic eruption or landslide.These triggering events could induce a transientbuildup of overpressure, and also fluidization, orflow of the liquefied system.

Recognizing Subsurface Sand InjectitesSand injectites occur on size scales ranging frommillimeters to kilometers and typically juxtaposematerials with different physical properties.

These characteristics allow subsurface sand-injection features to be recognized in cores,wellbore image logs and seismic sections.

Injectites have been identified in cores fromoil fields in several areas, including the NorthSea, the Gulf of Guinea and offshore Australia.17

In cores, dikes are easier to recognize than sillsbecause of their clear discordance with host-rockbedding (above).18 For sills, in which theinjectite-host rock contacts are parallel,additional criteria, which also apply to dikes,may be used.19 These include homogenization, orlack of primary depositional structures, causedby fluidization. However, there may be internalstratification inconsistent with bedding andconsistent with remobilized sand, such as flowlaminae and alignment of grains or closerpacking of grains near injectite walls. Anotherindicator is the presence of host-rock clasts,which typically are angular. Fluid-escape

features, such as upward-merging structures,may be seen. In some cases, the intruding sandmay be affected by diagenesis, staining,cementation or residual oil in a manner that isdifferent from the host rock.

Because boreholes sample a relatively smallvolume of the subsurface, cores may undersampleinjectite volumes. If a borehole encounters aninjected sandstone, it is likely that there are moreinjectites nearby that have not been sampled.

Recognizing injectites in well logs often is notstraightforward. Injected sands generally do nothave a unique signature on resistivity or gammaray logs, and are frequently mistaken for thin, or“ratty,” sands (previous page, bottom). Therefore,one possible indicator of injectites is thepresence of thin sands above a massive sand body.Another sign is the presence of sand in unusualstratigraphic settings. Also, injectites tend to bethinner the farther they are from the parent sand.

12. Sand intrusion under isotropic stress conditions has alsobeen observed in Texas. For more: Diggs TN: “AnOutcrop Study of Clastic Injection Structures in theCarboniferous Tesnus Formation, Marathon Basin, Trans-Pecos Texas,” in Hurst A and Cartwright J (eds):Sand Injectites: Implications for HydrocarbonExploration and Production, AAPG Memoir 87. Tulsa: AAPG (2007): 209–219.

13. Jolly RJH and Lonergan L: “Mechanisms and Controlson the Formation of Sand Intrusions,” Journal of theGeological Society 159, no. 5 (2002): 605–617.

14. Huuse M, Cartwright J, Hurst A and Steinsland N:“Seismic Characterization of Large-Scale SandstoneIntrusions,” in Hurst A and Cartwright J (eds): SandInjectites: Implications for Hydrocarbon Exploration andProduction, AAPG Memoir 87. Tulsa: AAPG (2007): 21–35.

15. Hurst and Cartwright, reference 2.16. Marco S, Weinberger R and Agnon A: “Radial Clastic

Dykes Formed by a Salt Diapir in the Dead Sea Rift,Israel,” Terra Nova 14, no. 4 (2002): 288–294.

17. Braccini E and Penna E: “Sand Injections in AngolaDeep Offshore,” presented at the 5th Annual AngolaFormation Evaluation Forum, Luanda, Angola, October 26–27, 2005.Dharmayanti et al, reference 2.

18. Briedis NA, Bergslien D, Hjellbakk A, Hill RE and Moir GJ:“Recognition Criteria, Significance to Field Performance,and Reservoir Modeling of Sand Injections in the BalderField, North Sea,” in Hurst A and Cartwright J (eds):Sand Injectites: Implications for HydrocarbonExploration and Production, AAPG Memoir 87. Tulsa: AAPG (2007): 91–102.

19. Hurst A, Cartwright J and Duranti D: “FluidizationStructures Produced by Upward Injection of SandThrough a Sealing Lithology,” in Van Rensbergen P, Hillis RR, Maltman AJ and Morley CK (eds): SubsurfaceSediment Mobilization, Geological Society SpecialPublication 216. London: Geological Society (2003): 123–138.

> Cores with sand-injection features. The core on the left shows an injected sand with fluid-escape structures (courtesy of A.Hurst), which are subvertical tracks caused by fluid rising through unconsolidated sediments (inset ). The coin is approximately2 cm [0.8 in.] in diameter. The next core, from a Total E&P well offshore Angola, contains an oil-bearing sand dike (dark gray) in shale (light gray). The core on the right, also from Total E&P Angola, shows brecciated host rock (light gray) in injected sand(dark gray), along with a close-up view.

cm

0

10

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Injected sand often is very well sorted andhas 30% or more porosity. Permeabilities arecommonly in the darcy range. However, in someinstances, injected sands have lower porosity,higher density and higher sonic velocities thantheir parent sands or other nearby depositionalsands.20 These criteria have been used todistinguish injectite from depositional facieseven when the injectite intrudes an unrelateddepositional sand.21

Borehole imaging tools, such as the FMIFullbore Formation MicroImager, the OBMI Oil-Base MicroImager and the UBI UltrasonicBorehole Imager, can detect sand injectites thatare discordant with host-rock bedding.Geologists at Total E&P Angola have used thesetools to image injectites in the Gulf of Guinea(left).22 Image logs provide an important linkbetween core-scale and larger-scale logmeasurements (below left).

At the seismic scale, sand-injection featuresare sometimes difficult to detect, because theyoften have a low acoustic impedance contrastwith the host-rock mudstones. Imaging of thesefeatures improves when contrast is high, as inthe case of high-porosity hydrocarbon-chargedsands juxtaposed with low-porosity, high-densityhost rock. For improved imaging in cases of lowacoustic impedance contrast, traditionallystacked compressional-wave processing may beaugmented with angle-stack processing,inversion and analysis of amplitude variationwith offset (AVO).23 The analysis of shear wavesobtained from ocean-bottom cable (OBC)acquisition can also reveal injection features notseen in compressional-wave data.24

The size of a feature that can be resolved byseismic methods depends on the densities andporosities of the layers through which theseismic waves travel, and on frequencybandwidth, spatial sampling, migration apertureand noise.25 In typical North Sea conditions,structures a few meters in size may be detected,and thicknesses in the range of 10 to 40 m [33 to131 ft] may be resolved, or quantified. Improve -ments in imaging achieved with application ofnew acquisition technology, such as the Q-Marinesingle-sensor system, are helping to resolve evensmaller features.26

A variety of injection styles has been observedin seismic data from the North Sea and off thewest coast of Africa. Injectite shapes can includewings, dipping structures that crosscut bedding,mounds, cuspate forms and cones (next page).27

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> Sand injections in a UBI Ultrasonic Borehole Imager log. The UBI image(Track 3) shows sand injections from X,X02.5 to X,X03.0 m and from X,X04.0to X,X04.5 m (brackets) with high dips relative to the low dip of the host rock.The injectites sometimes correspond to slight decreases in gamma ray(green, Track 1). The high dip can also be seen in Track 1 (circle). Dips seenin the OBDT Oil-Base Dipmeter Tool image (Track 2) corroborate thoseinterpreted from the ultrasonic measurements (Adapted from Braccini andPenna, reference 17, courtesy of Total E&P Angola.)

OBDT Image UBI Image

0 0360 360

Dip, deg0 45 90

Gamma Ray0 200gAPI

X,X02.0

X,X03.0

X,X03.5

X,X04.0

X,X04.5

X,X02.5

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> Correlating image logs and core in a Total E&P well in the Gulf of Guinea.Dips and images have been acquired with the OBMI Oil-Base MicroImagertool. Steeply dipping features corresponding to tadpoles circled in red(Track 1) indicate injections at high angles relative to the gently dippinghost rock. In the OBMI images (Tracks 2 and 3), dark colors correspond tolow resistivity (shales) and light colors correspond to high resistivity(sands). The colors of the sinusoids interpreted in the OBMI imagescorrespond to the colors of the dip tadpoles in Track 1. The corephotograph (right ) shows a high-angle contact between injected sand(light gray) and host rock (dark gray). (Adapted from Braccini and Penna,reference 17, courtesy of Total E&P Angola.)

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Oil Fields with InjectitesMany oil fields in the North Sea are linked toinjectites or contain sand-remobilization features.In some cases, thin intrusive sands above the mainreservoir have been identified through coresampling in exploratory wells but have beenignored or misunderstood. In other cases, seismicimaging helped identify large-scale injectionwings that were later found to contain hydro -carbons. Often these fields are centered on one orseveral large, deepwater sandstone unitsdeposited as turbidites or gravity flows. Thedistribution and size of injected sandsremobilizing from the parent sand bodies varywidely, as does the impact of sand injection onfield development.

The first North Sea oil discovery—Balderfield, in 1967—underwent more than 30 years ofexploration and appraisal before production.28

This geologically complex field comprises sevenoil accumulations in deepwater sands separatedand trapped by mudstones and volcanic tuff. In1969, centimeter-scale sand injections were firstrecognized in core from an early explorationwell, but were considered to be insignificant.29

Since then, more than 150 sand-injectionfeatures have been identified in core, log andseismic data of the Balder field, the largest witha thickness of 11 m [36 ft]. Postdepositional sandremobilization—sand withdrawal, diapirism andinjection—caused juxtaposition of sand on sand,creating widespread intrareservoir connectivity.Accumu lations in sand injectites may account formore than 25% of the oil in place in the Balderfield, and all the sands appear to be in pressurecommunication. In some areas of the field, it isimpossible to obtain reasonable history-matcheswithout adding a sand-injection component tointrareservoir connectivity.30 Incorporating sandinjectites in the full-field reservoir model helpedachieve sufficient matches with productionhistory and is expected to assist in maximizingtotal ultimate recovery from the field.

Perhaps the best-known example of a reservoiraffected by sand injection is the Alba field in theUK sector of the North Sea. The high-porosityturbidite channel sands of the Alba field werediscovered in 1984 while drilling for a deepertarget—the Brittania field. Production from Albafield began in 1994. As in the case of the Balderfield, sand-injection features were observed incores early on, but not considered important.

In 1998, a full-field 3D multicomponentseismic survey using OBCs revealed dippingreflections at the margins of the main channel.These structures had not been imaged by earlier,

20. Fretwell PN, Canning WG, Hegre J, Labourdette R andSweatman M: “A New Approach to 3D GeologicalModeling of Complex Sand Injectite Reservoirs: The Alba Field, United Kingdom Central North Sea,” in Hurst A and Cartwright J (eds): Sand Injectites:Implications for Hydrocarbon Exploration andProduction, AAPG Memoir 87. Tulsa: AAPG (2007): 119–127.

21. Duranti D, Hurst A, Bell C, Groves S and Hanson R:“Injected and Remobilised Eocene Sandstones from the Alba Field, UKCS: Core and Wireline LogCharacteristics,” Petroleum Geoscience 8, no. 2 (May 2002): 99–107.Hurst et al, reference 19.

22. Braccini and Penna, reference 17.23. McHugo S, Cooke A and Pickering S: “Description of a

Highly Complex Reservoir Using Single Sensor SeismicAcquisition,” paper SPE 83965, presented at SPEOffshore Europe, Aberdeen, September 2–5, 2003.

24. MacLeod MK, Hanson RA, Bell CR and McHugo S: “The Alba Field Ocean Bottom Cable Seismic Survey:Impact on Development,” The Leading Edge 18, no. 11(November 1999): 1306–1312.

25. Huuse et al, reference 14.Huuse M and Mickelson M: “Eocene SandstoneIntrusions in the Tampen Spur Area (Norwegian North

Sea Quad 34) Imaged by Seismic Data,” Marine andPetroleum Geology 21, no. 2 (February 2004): 141–155.

26. McHugo et al, reference 23.27. Molyneux S, Cartwright J and Lonergan L: “Conical

Sandstone Injection Structures Imaged by 3D Seismic in the Central North Sea, UK,” First Break 20, no. 6 (June 2002): 383–393.Davies RJ: “Kilometer-Scale Fluidization StructuresFormed During Early Burial of a Deepwater SlopeChannel on the Niger Delta,” Geology 31, no. 11(November 2003): 949–952.Hamberg L, Jepsen A-M, Ter Borch N, Dam G,Engkilde MK and Svendsen JB: “Mounded Structures of Injected Sandstones in Deep-Marine PaleoceneReservoirs, Cecilie Field, Denmark,” in Hurst A andCartwright J (eds): Sand Injectites: Implications forHydrocarbon Exploration and Production, AAPG Memoir 87. Tulsa: AAPG (2007): 69–79.

28. “History of the North Sea,” Norwegian PetroleumDirectorate, http://www.npd.no/English/Emner/Geografiske+omraader/Nordsjoen/NordsjoenHistorikk.htm (accessed July 8, 2008).

29. Briedis et al, reference 18.30. Briedis et al, reference 18.

> Seismic expressions of sand injection. Seismic imaging captures a range of injectite features.Mounded and cuspate forms appear in the top surfaces of injected sand (top left and top right ). A 3Dview (top left ) shows the top of a sand wing (blue) that rises steeply to the left. (Courtesy of MarathonOil UK.) At top right is a seismic section. (Adapted from Hamberg et al, reference 27, courtesy ofDONG E&P Exploration.) A conical intrusion in the shape of a “V” is seen above a thick depositionalsandstone (bottom left ). Vertical exaggeration is seven times. (Adapted from Huuse and Mickelson,reference 25.) An injectite with dipping wings that crosscut bedding is revealed in an inversionsection (center right ). (Courtesy of Marathon Oil UK.) A 3D view of a saucer-shaped injection from theNorth Sea (bottom right ) is color-coded from shallow (red) to deep (blue). (Courtesy of M. Huuse.)

~ 5 k

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conventional towed-streamer surveys because ofthe poor acoustic impedance contrast betweensand and shale. Chevron geophysicists inter -preted the wing-like features as sand injections.31

Two wells were subsequently drilled into theinjectite wings; the first encountered 150 m[492 ft] of oil-bearing sand and produced20,000 bbl/d [3,178 m3/d].32 The second wellintersected 20 m [66 ft] of sand in the westernpart of the field.

The multicomponent seismic dataset hasbecome the primary tool for planning these wellsand predicting reservoir quality in the Alba field.33

Shear-wave impedance data from the invertedseismic volume—calibrated with core and logdata—have been converted to quantitative sand-quality values for the purposes of constructinggeological models for well placement andreservoir models for simulating production.

Several other fields of the North Sea exhibitinjectite and remobilization features, includingChestnut, Grane, Sleipner Øst, Volund, Gryphon,Leadon, Harding and Jotun. Two of these, theGryphon and Volund fields, are examined in thefollowing sections.

Sand Wings in the Gryphon FieldThe Gryphon field—Maersk Oil 86.5% equity,Sojitz 13.5% equity—was discovered in 1987 inBlock 9/18b of the UK North Sea (below). Thediscovery well penetrated 190 ft [58 m] of oil-bearing sand in the Balder formation at a depth of5,700 ft [1,738 m].34 The main Gryphon reservoir,on production since 1993, comprises basin-floorturbidite sandstones of Eocene age. However,since 2004, operator Maersk Oil has also beenproducing oil from wells drilled into seismic-scalesand-injection wings extending from the mainreservoir. These features are developed at themargins of the Gryphon field where the Baldersand depositional system terminates.

Like most fields now known to be associatedwith sand-injection features, the Gryphon fieldwas initially thought to contain only depositionalsand formations. As more evidence wascollected, the interpretation evolved. Earlyexploration and appraisal drilling in the 1980sand 1990s revealed a complex distribution ofreservoir sands. For example, one well near thecenter of the field encountered more than 300 ft[91 m] of turbidite sand, while a well less than1,640 ft [500 m] north encountered almost nosand. Reservoir quality was excellent, with

porosity averaging 36% and permeabilityaveraging 7 D.35 Adding to reservoir complexity,small-scale injected sands, up to a fewcentimeters in thick ness, were seen above themain reservoir, but were not considered tocontribute signifi cantly to the reservoir volume.

Early seismic investigations—2D surveys in1985, 1987 and 1988, a 3D survey in 1990 and anOBC survey in 1999—detected the broadlymounded Gryphon structure, but limitations inthe seismic data quality made detaileddelineation difficult. Later, after Maersk Oilgained experience with injectites in the nearbyLeadon field, together with improvements inseismic processing and simultaneous inversionapplied by Maersk Oil to the long-offset seismicdata acquired in 2002, large-scale sand-injectionwings were identified on the edges of the field(next page, top right).36

The first injectite development target was asection of the major sand wing on the easternedge of the field. This target involved numerouschallenges including geosteering through adipping sheet-like sand body and managingwellbore stability in high-porosity, unconsol-idated sands. The uncertainty in the seismicallyderived position of the sand wing, possiblycaused by limitations in migrating its steeperdip, together with depth-conversion discrepancy,has an impact on the lateral position of a dippingsand wing. This proved to be a subsurface teamchallenge in geosteering along strike in thedipping sand wings.37

These difficulties were overcome by a teamapplying a combination of tools, such asprototype geosteering technology—Maersk Oilwas the first company in the UK sector of theNorth Sea to use PeriScope bed boundarymapper technology and to drill a dedicatedproduction well in an injection-wing target—anddetailed prewell scenario planning, includingwellbore-stability studies and extensive inter -disciplinary collaboration. An office-basedgeosteering team operated around the clock andcommunicated with the rig crew to integrateLWD data with the understanding of the injectitereservoir, enabling Maersk Oil geologists to makereal-time decisions to geosteer back into thesand wing after exiting the injectite to maximizethe amount of pay along the wellbore.

Wellbore-stability studies using data fromearlier Gryphon wells that penetrated the Balderformation—about one quarter of them hadexperienced mud losses—indicated that well -bore stability could not be achieved. Eitherbreakouts or mud losses could be managed, but

42 Oilfield Review

> Gryphon field, UK North Sea. Since 2004, the Gryphon field has been producing oil from horizontalwells geosteered into injected sands.

9/18b-34Z

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Summer 2008 43

not both. Drillers adopted a zero-loss strategy andworked toward managing borehole failure byoperating within a strict equivalent circulatingdensity (ECD) window.38 With the additional riskof exiting sand and encountering unstable shales,successful drilling required following provenpractices, such as adherence to swab and surgelimits during drilling, connections and tripping.

In 2004, the first Gryphon development wellto target an injection wing was drilledhorizontally for 1,420 ft [433 m] along the strikeof the wing, penetrating sand along 53% of itslength. LWD measurements indicated that theborehole trajectory was on the low side of therugose sand wing rather than in its center,explaining the multiple sand entries and exits.However, while the wellbore was within theinjection wing, the net-to-gross ratio was 100%.

The second well was designed to enteranother segment of the major sand wing on thewestern edge of the Gryphon field and tocontinue horizontally along the strike of thewing. The well entered the wing as expected, butexited through the base into the surroundinghost shale. Returning to the 12¼-in. boreholewith the PeriScope 15 bed boundary mapperconfirmed the position of the wellbore relative tothe sand wing.39 The PeriScope 15 tool usesazimuthal induction measurements to sense

resistivity contrasts up to 15 ft [4.5 m] from theborehole for real-time geosteering.

An openhole sidetrack was drilled 80 ft[24 m] to the west, landing in the sand wing asdesired (below). The sidetrack largely remainedwithin the injection wing for 1,440 ft [439 m],penetrating sand along 80% of a 1,800-ft [549-m]horizontal well section.40 Again, while thewellbore was within the injection wing, the net-to-gross ratio was 100%.

With the two successful wells drilled in 2004,production from Gryphon field more than

doubled, reaching 27,000 bbl/d [4,290 m3/d] by theend of that year. These results encouraged Maerskto drill additional wells, incorporating newknowledge about seismic positioning uncertainty.

In the 2005 drilling campaign, a lateral shiftwas applied to well paths to account for theuncertainty in seismic positioning. Also, newwells were planned to land a few hundred feetabove the wing and make a gradual, obliqueapproach; once the wing was found, casing wasset and the first operation in the 8½-in. sectionwas to veer along the strike of the wing. With

31. MacLeod et al, reference 24.Lonergan L and Cartwright JA: "Polygonal Faults andTheir Influence on Deep-Water Sandstone ReservoirGeometries, Alba Field, United Kingdom Central NorthSea," AAPG Bulletin 83, no. 3 (March 1999): 410–432.

32. Hurst A: “Sand Intrusions Reveal Increased Reserves,”GEO ExPro (October 2005): 12–20.

33. Fretwell et al, reference 20.34. Purvis K, Kao J, Flanagan K, Henderson J and Duranti D:

“Complex Reservoir Geometries in a Deep Water ClasticSequence, Gryphon Field, UKCS: Injection Structures,Geological Modelling and Reservoir Simulation,” Marine and Petroleum Geology 19, no. 2 (2002): 161–179.

35. Templeton G, McInally A, Melvin A and Batchelor T:“Comparison of Leadon and Gryphon Fields SandInjectites: Occurrence and Performance,” presented atthe 68th EAGE Conference and Exhibition, Vienna,Austria, June 12–15, 2006.

36. For more on simultaneous inversion: Barclay F, Bruun A,Rasmussen KB, Camara Alfaro J, Cooke A, Cooke D,Salter D, Godfrey R, Lowden D, McHugo S, Özdemir H,Pickering S, Gonzalez Pineda F, Herwanger J,Volterrani S, Murineddu A, Rasmussen A and Roberts R:“Seismic Inversion: Reading Between the Lines,” Oilfield Review 20, no. 1 (Spring 2008): 42–63.

37. Hart N, Ageneau G, Mattson P and Fisher A:“Development of the Gryphon Field Injection Wing—Technical Challenges and Risks,” paper SPE 108655,presented at SPE Offshore Europe, Aberdeen,September 4–7, 2007.

38. Hart et al, reference 37.39. Chou L, Li Q, Darquin A, Denichou J-M, Griffiths R,

Hart N, McInally A, Templeton G, Omeragic D, Tribe I,Watson K and Wiig M: “Steering Toward EnhancedProduction,” Oilfield Review 17, no. 3 (Autumn 2005): 54–63.

40. Hart et al, reference 37.

> Seismic interpretation of injection wings in the Gryphon field. Thereservoir is outlined in yellow. The injection wings are visible as dippingfeatures on the right side. The gas-, oil- and waterprone intervals of thereservoir are shaded light red, green and blue, respectively. Gamma raylogs (black) are displayed along well trajectories (orange).

Top Balder

A22

Massive sand

A2ZA19Z A24Z

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Top sand

> Landing a horizontal well in a sand wing. The first attempt to hit this injected sand overshot andcame out the other side. This successful well landed as planned, and stayed within the wing for 1,440 ft. LWD logs (bottom right ) helped drillers stay in the sand-injection wing. The PeriScope 15 image(bottom) shows that the well stayed mostly in the high-resistivity sand (yellow) but did encounter afew patches of low-resistivity claystone (brown). The sand and claystone zones are also evident inthe gamma ray (green) and resistivity (red) curves.

Wellbore

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these improvements, three additional wells weredrilled in 2005, and two more in 2007.

These wells encountered a range of reservoirqualities in different portions of the injectite. For example, the first well in 2005 was drilledinto a large, continuous sand that was easilynavigated, while the second well was challegingto geosteer and penetrated an overall loweramount of sand along hole (above).

By the middle of 2008, the seven wells thattargeted sand-injection features had produced14 million barrels [2.22 million m3] of oil and aredelivering approximately 80% of Gryphon field’sdaily production (below).41

Exploiting the injection-wing play has provedvery successful for Maersk Oil. The Gryphon fieldhas been rejuvenated, with further sand-wingtargets identified for drilling, and more

importantly, the subsurface injection-wingexpertise is being applied to other areas operatedby Maersk Oil in the North Sea.

Discovering Oil in a Sand-Injection ComplexA remarkable example of successful injectiteexploration is the giant sand-injection complexof the Volund field (formerly called Hamsun),discovered by Marathon and partner LundinNorway AS in 2004 in Norwegian Block 24/9. Thisdiscovery, believed to be the world’s firstdeliberate drilling into an injection feature notconnected to a producing field, containsestimated reserves of 40 to 50 million barrels[6.4 to 7.9 million m3] of oil equivalent.42

Before the Marathon partnership acquiredthe license in 2003, six exploration wells had beendrilled in Block 24/9 in the Norwegian sector ofthe North Sea (next page, top left). Wells 24/9-5and 24/9-6, drilled by Fina Exploration Norway in1993 and 1994, found minor oil columns in latePaleocene and Early Eocene mounded sands, butthese were not of economic interest.43

As operators elsewhere in the North Seabegan recognizing and developing sand-injection features associated with producing oil fields, interpreters revised their assessmentsof the seismic data covering the marginal oilfinds in Block 24/9. The basin-shaped structurewas identified as a clastic-intrusion complex with steeply dipping sands that could be highly connected.44

In an independent evaluation, Marathonreprocessed the 1996-vintage 3D seismic data tosee if offset-dependent amplitude variations

44 Oilfield Review

> PeriScope 15 LWD images from Gryphon wells drilled in 2005. The first well (top) encountered 1,733 ft[528 m] of continuous sand that was easily navigated (light color). The second well (bottom) penetrated673 ft [205 m] of a thinner sand of lower quality with several low-resistivity claystone zones (dark color).The green lines are the planned well paths, and the red curves are the actual well paths.

500 1,0000

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41. Hart et al, reference 37. 42. http://www.marathon.com/Global_Operations/

Exploration_and_Production/Norway/ (accessed July 2, 2008).

43. De Boer W, Rawlinson PB and Hurst A: “SuccessfulExploration of a Sand Injectite Complex: HamsunProspect, Norway Block 24/9,” in Hurst A andCartwright J (eds): Sand Injectites: Implications forHydrocarbon Exploration and Production, AAPG Memoir 87. Tulsa: AAPG (2007): 65–68.

44. Lawrence DA, Sancar B and Molyneux S: “Large-ScaleClastic Intrusion in the Tertiary of Block 24/9, NorwegianNorth Sea: Origin, Timing and Implications for ReservoirContinuity,” presented at the AAPG InternationalConference and Exhibition, Birmingham, England,September 12–15, 1999.Huuse M, Duranti D, Guargena C, Prat P, Holm K,Steinsland N, Cronin BT, Hurst A and Cartwright J: “Sand Intrusions: Detection and Significance forExploration and Production,” First Break 21 (September 2003): 33–42.

45. De Boer et al, reference 43.46. In a Class III AVO case, the sand has a lower acoustic

impedance contrast than the encasing shale and has alarge negative reflection coefficient at normal incidence.For more: Rutherford SR and Williams RH: “Amplitude-Versus-Offset Variations in Gas Sands,” Geophysics 54,no. 6 (June 1989): 680–688.

47. Quakenbush M, Shang B and Tuttle C: “PoissonImpedance,” The Leading Edge 25, no. 2 (February 2006):128–138.

> Sand-injection impact on production. Oil from the seven horizontal wells inGryphon field’s sand wings has revitalized production. Injection-wing wells nowaccount for about 13% of cumulative production from the field.

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might reveal information about fluid content inthe injected sands (above right).45 The increasedamplitudes on the far-offset stacked sectioncompared with those of the near offsets—known as a Class III AVO signature—are typicalof a hydrocarbon-filled, high-porosity sand in this area.46

However, it was important to increaseconfidence in the nature of the hydrocarbon andto confirm the likelihood of an oil-filled structure.Because developing a gas accumulation was not

economically viable at the time, furthergeophysical assessment of fluid type wasnecessary to limit risk before committing to drillthe prospect. Marathon geophysicists performedprestack 3D inversion for shear-wave and

compressional-wave impedances, which werecombined to yield sections of so-called Poissonimpedance (below).47 Inversion enhanced theinterpretability of the seismic data, clearlydelineating the 3D shape and internal structure

> Volund field, south of Alvheim field in Block 24/9 of the Norwegian NorthSea. Wells 24/9-5 and 24/9-6 (labeled 5 and 6, respectively), drilled in 1993and 1994, found insignificant amounts of oil. The labeled seismic line showsthe position of the seismic sections in the next two figures on this page.

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> Near-offset and far-offset seismic sections through the Volund sand-injection complex. Because of the particular contrast in acoustic propertiesbetween the injected sand and the host rock, the dipping wings of theinjectite are better imaged in the far-offset section (bottom) than in thenear-offset section (top). The bottom of the injection complex is interpretedin green. The top of the Balder shale is interpreted in yellow and is seen to“jack up,” or thicken, discontinuously in the center, where the injectedsands are thickest. The increased amplitudes on the far-offset stackedsection compared with those of the near offsets are typical of ahydrocarbon-filled, high-porosity sand in this area. Gamma ray logs(yellow) are displayed along well trajectories (black).

Volund Near-Offset Amplitudes

24/9-7A24/9-7

Balder shale

Volund Far-Offset Amplitudes

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> Inversion of Volund field seismic data. Inversion results for Poisson impedance depend on the background model used. An initial model with flat layersparallel to bedding (left ) produces an image of injection wings with poor continuity. An initial model that includes the “bathtub” shape of the injectite (right )yields sand wings with better continuity in their dipping sections and makes it easier to distinguish the injected sand from the host rock.

Poisson Impedance Inversion, Flat Model

24/9-7A24/9-7

Poisson Impedance Inversion, “Bathtub” Model

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of the injection feature (above). Calibration ofPoisson impedance values with well log dataallowed differentiation of sand-rich units fromsurrounding mudstones. The seismic inversionimages also revealed a flat spot, whichcorresponded to the oil/water contact (OWC)observed in Well 24/9-6, increasing confidencethat the sand injectite was filled with oil.

Analysis of outcrop analog data from centralCalifornia, including observations from thePanoche Hills injectites, gave Marathon inter -preters confidence in the size and geometry ofinjected sand bodies in the North Sea. Inoutcrop, clean injected sands of all sizes wereseen to be well-connected with each other andalso with poorer quality breccia-laden sands.Applying this concept to the subsurface prospectmade it likely that sand intervals of high net-to-gross values would be in hydrauliccommun i cation with zones of lower net-to-grossvalues, and that any hydrocarbon migrating intothe system would fill the structure and be inpressure communication.48

The first exploration well, Well 24/9-7,targeted the southern wing of the injectitecomplex and encountered an injected sand layerat a depth of 1,848 m [6,063 ft], within 2 m[6.6 ft] of the predicted reservoir top. Asexpected from the seismic interpretation, theborehole penetrated two major intrusive sanddikes. The upper one, unexpectedly containinggas, had a true vertical thickness of 32 m [105 ft],and the lower one, an oil-bearing zone, had a truevertical thickness of 12 m [39 ft]. Core recoveredfrom this well contained host-rock mudstone,injected sand and breccia with host-rock clasts(above right).

Following the discovery of oil in the first well,sidetrack Well 24/9-7A was drilled downdip tofollow the gas-filled dike into the oil column. Thetwo sand intrusions were again intersected, theupper one in the oil leg and the lower one now inthe water leg. Another sidetrack, 7B, probedupdip into the fringe of the injectite complex,

46 Oilfield Review

48. De Boer et al, reference 43.

> Core section from Well 24/9-7. The two mainreservoir facies are captured in this section: fine-grained sandstone (light gray) and breccia withdark, angular mudstone clasts. The mudstone atthe bottom of the section is a large clast.

0.6

m

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> Volund field injection-complex top, interpreted from seismic inversion data. This view is from westto east. Surface colors indicate depth; red is shallow and blue is deep. The line of the previouslyshown seismic section is white. Wells are black lines. Vertical exaggeration is approximately fourtimes. Wing height is 250 to 300 m [820 to 984 ft] and maximum wing dip is 25 to 30 degrees.

1 km0.62 mi

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and found several thin, gas-filled, centimeter-scale sands (above). This proved important forseismic calibration purposes. A third sidetrack,7C, drilled into the eastern portion of theinjectite complex, intersected a 49-m [160-ft]massive sand and penetrated the OWC in thelocation that was predicted by extrapolation ofdata recorded in Well 24/9-6. All the sand in theinterval corresponding to the Paleocene age isthought to be injected from the underlyingHermod parent sand.

The clean sands in the Volund reservoir haveporosities averaging 30% and permeabilities ofseveral darcies. Reservoir quality decreases with

height; thick massive sands in the deeper portionof the structure give way to thinner, predom -inantly low net-to-gross breccias toward theedges of the injection complex. Estimatingreserves and optimizing development of the fieldrequire predicting the 3D distribution ofreservoir facies within the intrusion structure.The seismic inversion results combined with logdata and rock physics analysis can be used asguides for generating various scenarios of faciesdistribution (below).

Development plans for the Volund fieldinclude three horizontal producing wells and onewater-injection well. Marathon geoscientists

have made continued use of outcrop analoginformation in planning these wells, foreseeingthe use of real-time LWD measurements togeosteer and anticipating borehole stabilityproblems when drilling through the injectedsand dikes.

Development drilling and production fromthe Volund field are expected to begin during2009. The field will be developed as a subseatieback to Alvheim field 10 km [6 mi] away.

> Correlation of logs from exploration and appraisal wells. Wells (top) are displayed at equaldistances, not at true horizontal locations. For each well, gamma ray is displayed with lithology, andresistivity is displayed with fluid content to the right and left of each well, respectively. Red is gas andgreen is oil. Sand content decreases upward within the wing. The Balder tuff and Balder shale arejacked up, showing apparent thickening to accommodate the injected sand. The inset (right ) indicatesthe location of the cross section relative to the injectite complex.

Hordaland group

Heimdal

Lista

Sele

Balder tuff

Balder shale

Injected sands

Hermod

24/9-6 24/9-7A 24/9-7 24/9-7B

7

7B

7A

6

> Distribution of reservoir facies within the Volund intrusion structure. A combination of seismic inversion results with rock physics analysis leads to anunderstanding of the distribution of connected breccia (left ) and connected sand (center). Their sum produces the total connected reservoir volume (right ).

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Effects of InjectitesKnowing from the start that a reservoir isaffected by clastic intrusions has a significantimpact on field development. The excellentconnectivity typical of injectites allows reservoirsto be developed with fewer wells. One operatingcompany acknowledged that a reservoir offshorewest Africa could have been developed with halfthe number of wells if the extent of connectivitycaused by injectites had been known in advance.Operators in several areas are benefitting fromthe experiences of North Sea pioneers byincorporating injectite-related connectivity intheir development-drilling plans.

Evidence of hydrocarbon migration throughfluid-injection structures can be seen inoutcrop. For example, oil-filled sand intrusionscrop out on the beach north of Santa Cruz,California (left). These large sills are sourcedfrom sand deeper in the section, which traveledto the surface through dikes and then filled with hydrocarbon.

The additional connectivity caused by sandinjectites must be considered not only foroptimal production, but also when reservoirs areput to other uses. For example, the Sleipner Østfield in the Norwegian North Sea is a potentialsite for future storage of gas from nearby wellsafter it has exhausted producible reserves.49 Thenine reservoir zones of high-quality sand areseparated by mud-prone zones that can becorrelated throughout the field. However,pressure data show that the sands are inpressure communication. Sandstone dikes andsills have been seen in cores from several wells,and may be responsible for the enhanced verticalpermeability seen in the pressure data. OperatorStatoilHydro believes that assessment of theeffects of injectites on reservoir behavior will becritical in the optimization of recovery during thelate-stage development.

Another application in which clasticinjectites may have an effect is waste storage.For instance, the Hanford site in the state ofWashington has been used by the US Departmentof Energy for storage of contaminants in surfacetanks.50 Developing plans for eventual closure ofthe tank farms requires accurate models for fluidtransport, including the effect of clastic dikes onfluid flow.51 Thousands of clastic dikes arepresent at the surface and below the Hanford site(left). Understanding how this network of fine-grained dikes behaves during periods of low andhigh fluid flow is key to optimizing the design ofremedial systems that may be needed.

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> Clastic dike in Hanford, Washington. The fine-grained dike (brown) wasemplaced in fine- to medium-grained host rock (gray). The dike is 0.7 m [2.3 ft] wide on the lowest face. (Photograph from Murray et al, reference 51.)

> Oil-filled outcrop north of Santa Cruz, California. The sandstone (dark)between two mudstones (light) originated from parent sand layers deeper inthe section and rose through nearby dikes (not shown). Oil, now biodegradedand heavy, causes the darkening of the sandstone. Large inclusions of light-colored mudstone can be seen encased in the sandstone.

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Other near-surface studies have helpedidentify some of the mechanisms that triggersediment injection.52 Investigations of sandinjectites emplaced during historically docu -mented earthquakes show a clear connectionbetween seismic triggering and widespreadoccurrence of clastic dikes, sand “blows” andother fluid-escape features.53

For example, in 1811 and 1812, the area nearNew Madrid, Missouri, USA, experienced threelarge earthquakes—each with magnitude 8 orhigher. During these seismic episodes, sandysediments in the shallow subsurface wereliquefied and vented to the surface over an areaexceeding 3,600 mi2 [9,320 km2].54 Extruded sandand associated dikes can be seen in excavations

(left). These seismically induced features can beused to infer the location and strength ofpaleoearthquakes. This information is importantfor designing buildings and other structures inareas that experienced seismic activity predatingwritten records.55

Sand Intrusions ElsewhereThe marked impact of sand injection in the NorthSea leads many explorationists to wonder ifinjectites are influential in other basins.Although literature on injectites is sparse forother areas, the reported occurrences in the Gulfof Guinea and offshore northwest Australiaindicate that sand-injection features are playinga role beyond the North Sea.

Other major oil-producing regions, such asoffshore Brazil and the Gulf of Mexico, report fewor no occurrences of injectites, and this leadsgeologists to wonder why. In the Gulf of Mexico,only a few cores have revealed finger-sized sandintrusions. Some experts believe that injectitesexist, but haven’t been identified. Others arguethat sedimentary conditions there, such as claymineralogy and sand grain-size distribution, arenot conducive to injectite formation.

Although clastic injectites have not beenconsidered significant in the Gulf of Mexico, theregion exhibits other fluid-escape features, in theform of shallow water flows that expel fluid at theseafloor. Fluid escape through shallow waterflows might be precursory to sediment extrusionon the seafloor. Fluid and sediment expulsiononto the seafloor can undermine surfaceinstallations, and the overpressured units fromwhich they spring make drilling and completingwells difficult.56

To better understand the conditions thatcause shallow water flows, an expedition of theInternational Ocean Drilling Program investi -gated overpressured sediments in the area of theUrsa field in the Gulf of Mexico.57 High-resolutionseismic data showed no obvious sand-injectionstructures, but may have detected incipient dikeformation. Pressure measurements in over -pressured formations indicated that fluidpressures are high, but insufficient to fracturethe overburden, and so not yet ready to form sand injectites.

Although the Gulf of Mexico and other areasare not yet known to be significantly affected bysand injections, as more geoscientists considerthe possible presence of injectites wheninterpreting data, injectites will be identifiedmore often. Recognizing injection features incore, logs and seismic data requires anawareness of these features, a perceptive mindand a trained eye. —LS

> Excavated sand dike. This sand dike, associated with the 1811 and 1812 New Madrid earthquakes,fills a fissure that is 200 ft [61 m] long. (Photograph courtesy of Carl Wirwa, Tennessee WildlifeResources Agency, Alamo, Tennessee, reference 53.)

49. Satur N and Hurst A: “Sand-Injection Structures inDeep-Water Sandstones from the Ty Formation(Paleocene), Sleipner Øst Field, Norwegian North Sea,” in Hurst A and Cartwright J (eds): Sand Injectites:Implications for Hydrocarbon Exploration and Production,AAPG Memoir 87. Tulsa: AAPG (2007): 113–117.

50. “Hanford State of the Site 2007 Meetings,” http://www.hanford.gov/?page=651&parent=0 (accessed July 22, 2008).

51. Murray CJ, Ward AL and Wilson JL: “Influence of ClasticDikes on Vertical Migration of Contaminants in theVadose Zone at Hanford,” Pacific Northwest NationalLaboratory Report PNNL-14224 prepared for theDepartment of Energy, March 2003.

52. Obermeier SF: “Seismic Liquefaction Features: Examplesfrom Paleoseismic Investigations in the ContinentalUnited States,” USGS Open File Report 98-488. http://pubs.usgs.gov/of/1998/of98-488/ (accessed July 8, 2008).

53. Obermeier SF: “The New Madrid Earthquakes: An Engineering-Geologic Interpretation of RelictLiquefaction Features,” USGS Professional Paper 1336-B, 1989.

54. http://web.utk.edu/~freeland/projects/sb.htm (accessedJune 12, 2008).

55. Obermeier SF: “Use of Liquefaction-Induced Features for Seismic Analysis—An Overview of How SeismicLiquefaction Features Can Be Distinguished from OtherFeatures and How Their Regional Distribution andProperties of Source Sediment Can Be Used to Infer theLocation and Strength of Holocene Paleo-Earthquakes,”Engineering Geology 44, no. 1 (1996): 1–76.

56. Myers G, Winkler C, Dugan B, Moore C, Sawyer D,Flemings P and Iturrino G: “Ursa Basin Explorers ShineNew Light on Shallow Water Flow,” Offshore Engineer(September 2007): 88–93.

57. Moore JC, Iturrino GJ, Flemings PB, Hull I and Gay A:“Fluid Migration and State of Stress Above the Blue Unit,Ursa Basin: Relationship to the Geometry of Injectites,”paper OTC 18812, presented at the Offshore TechnologyConference, Houston, April 30–May 3, 2007.

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