GEOLOGIC NOTES

The influence of fracture cements

western Qaidam Basin,

but also enhance the free fluid index and the free fluid sat-uration measured by nuclear magnetic resonance and deter-

faults,

AUTHORS

Lianbo Zeng State Key Laboratory ofPetroleum Resource and Prospecting, ChinaPetroleum University, Beijing, China;lbzeng@sina.com

Lianbo Zeng is a professor of geology in theKey State Laboratory of Petroleum Resourceand Prospecting in China Petroleum University.He received his M.S. degree from the ChinaUniversity of Geosciences and his Ph.D fromthe China Petroleum University. His interestsinclude tectonic stress fields, natural fracturesystems, and low-permeability reservoircharacterization.

Xiaomei Tang College of Geosciences,China University of Petroleum, Beijing, China;tangxiaomei98@yahoo.com.cn

Xiaomei Tang received her B.A. and M.S. de-grees from Yangtze University and is now adoctoral student at the China University ofPetroleum. Her recent interest is in the studyand evaluation of fractured reservoirs.

Tiecheng Wang Research Institute ofPetroleum Exploration and Development,Qinghai Oil Field Branch, PetroChina Com-pany Limited, Dunhuang, China;wtcqh@petrochina.com.cn

Tiecheng Wang is a senior geologist forPetroChina Company Limited. His researchfocuses on the exploration and development offractured reservoirs in the western QaidamBasin, northwestern China.

Lei Gong College of Geosciences, ChinaUniversity of Petroleum, Beijing, China;kcgonglei@foxmail.com

Lei Gong received his B.A. degree from theHunan University of Science and Technologyand is now a doctoral student at China Uni-versity of Petroleum. His recent interests in-clude natural fracture systems and tight gassandstone reservoir characterization.

ACKNOWLEDGEMENTS

We thank Shao Wenbins, Zhang Min, ZhangDaowei, Zhang Yongshu, and Si Dan, seniorengineers at the Qinghai Oil Field Branch, Petro-China Company Limited, for their constructiveand many do not coincide with the present-day direction ofthe maximum horizontal compressive stress.

INTRODUCTION

Since 1950, 17 commercial oil and gas reservoirs have beendiscovered in Paleogene saline lacustrine carbonate rocks in

Copyright 2012. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received July 9, 2011; provisional acceptance December 7, 2011; revised manuscript receivedJanuary 21, 2012; final acceptance April 18, 2012.DOI:10.1306/04181211090voirs. The open fractures are parallel to and occur near

mine the potential production rates of tight carbonate reser-northwest ChinaLianbo Zeng, Xiaomei Tang, Tiecheng Wang,and Lei Gong

ABSTRACT

Paleogene saline lacustrine carbonate rocks are important frac-tured reservoirs in the western Qaidam Basin. Core data showthat most fractures are small, steeply dipping faults; bedding-plane slip faults; and subvertical opening-mode fractures. Otherfractures are diagenetic in origin. Fracture occurrence and abun-dance patterns are controlled by lithology, bed thickness, andproximity to larger faults. Fractures are generally filled withcalcite, gypsum, or glauberite (Na2Ca[SO4]2); the degree offracture filling determines the effectiveness of fractures as fluidconduits and the distribution of high-quality reservoirs. Openfractures not only provide the main pathways for fluid flow,in tight Paleogene salinelacustrine carbonate reservoirs,AAPG Bulletin, v. 96, no. 11 (November 2012), pp. 20032017 2003

help. We also thank the reviewers of this text,Colin P. North, Stephen E. Laubach, Julia F. Gale,Darryl Green, Stephen A. Sonnenberg, andanonymous reviewers, who provided excellentadvice on the clarity of the text and figures. Thisstudy is financially supported by the Founda-tion of the State Key Laboratory of PetroleumResource and Prospecting, China University ofPetroleum, Beijing (PRPJC2008-03).The AAPG Editor thanks the following reviewersfor their work on this paper: Colin P. North andStephen A. Sonnenberg.

EDITOR S NOTE

Color versions of Figures 410, 1317, and 1920can be seen on the online version.

2004 Geologic Notesthe western Qaidam Basin, northwestern China (Xu et al.,2006). In the northwestern part of the basin, host rockmatrixporosity and permeability are uniformly low, and all reservoirsrequire natural fractures to produce (Fu, 2010). In the south-western part of the basin, although some host rocks have highermatrix porosity and permeability, more than half are fracturedreservoirs. Therefore, the occurrence and abundance of openfractures determines the distribution of good reservoirs (Fu,2010).Where no open fractures exist, little productive reservoiris observed. The distribution of open fractures is therefore apotential guide to exploring and exploiting these tight carbon-ate reservoirs. The function of open fractures and cement de-posits is increasingly appreciated as key to the evaluation ofreservoirs (Nelson, 1985; Hood et al., 2003; Laubach et al.,2004b; Laubach and Ward, 2006; Gale et al., 2010; Ortegaet al., 2010).

Liu et al. (1998),Wei et al. (1999), and Li andWang (2001)reported the reservoir characteristics of lithology, pore type andconfiguration, and porosity and permeability of fractured car-bonate reservoirs in the Xianshuiquan oil field, Nanyishan gasfield, and Shizigou deep oil field in the western Qaidam Basin.They thought that the major fractures were tectonic, whichassociatedwith folds and faults from data of outcrops, cores, andthin sections, and emphasized the significance of fractures onstorage and fluid flow. Peng et al. (2003) predicted the fracturedistribution in carbonate rocks of the northern Gasikule oil fieldby the finite-element numerical simulation of the paleotectonicstress field based on assumptions derived from the fault con-figuration and regional plate tectonics. Tong and Cao (2004)reported that fractures were mainly fold-related fractures par-allel to and perpendicular to the strike of the axes of anticlines,and the intensity of these fractures was developed with the in-creased compressive folding in theXianshuiquan and Shizigouoil fields. Cao et al. (2007) predicted that fractures were betterdeveloped near faults and along the axes of anticlines based ondominant control of structures in the Nanyishan gas field.

In this study, we depict the types and distribution of thefractures, interpret the controlling factors of fracture develop-ment and preservation, and then evaluate the open fracturesand their contribution to the productivity of the Paleogenecarbonate reservoirs in thewesternQaidamBasin. The reservoirrocks described here are good examples of tight, fine-grainedcarbonate reservoirs. The fractures in these rocks are commonlycemented, which reduces fracture porosity and permeability.This article provides an example of the important functionthat cement deposits have in damaging natural fracture con-duits. It also shows how the free fluid index (FFI) calculated

inantly composed of red sandstone, conglomerate,

and mudstone in the lower part, and lacustrine graymudstone, carbonate rocks, and interbedded gyp-sum and salt layers in the upper part (Fu et al., 2010;Chen et al., 2011; Hui et al., 2011). The Oligocenefrom nuclear magnetic resonance (NMR) providesevidence that can be used to identify zones havingeffective natural fractures.

GEOLOGIC SETTING

Stratigraphy

TheQaidamBasin has a rhombic shape. It is 850 km(528 mi) long from east to west, 150 to 300 km(93186 mi) wide from north to south, and hasan area of approximately 1.21 105 km2 (4.67 104 mi2). It is an intermontane basin surroundedby the Altyn Tagh (also spelled Altan) Shan tothe northwest, the eastern Kunlun Shan to thesouthwest, and the Qilian Shan to the northeast(Figure 1A) (Shan is Chinese for mountains).

At the front of the Altyn Tagh Shan, the west-ern Qaidam Basin contains mainly Cenozoic stratadeposited in alluvial-fan, fluvial, and lacustrine set-tings (Figure 2), which overlies Paleozoic and locallyMesozoic granitic rocks along an angular unconfor-mity. Paleogene and Neogene strata are complete,whereas Quaternary rocks have been eroded byneotectonic uplift movements (Fu et al., 2010; Chenet al., 2011; Hui et al., 2011).

The Paleogene saline lacustrine carbonate res-ervoirs are above the Eocene Xiaganchaigou For-mation and the Oligocene Shangganchaigou For-mation at depths of more than 3500m (11,482 ft).Rock types of reservoirs include lacustrine dolo-mite, limestone, and muddy limestone (Fu et al.,2010). The individual muddy limestone beds arelaminated and have high clay-mineral contents,including hydromica and kaolinite (Ye et al., 1993;Hui et al., 2011). Based on compositional analysesof 400 samples, the average composition consists of34.4% calcite, 27.4% dolomite, 20% clay mineral,5.6% gypsum, 8.8% terrigenous debris, and 3.8%pyrite.

The Eocene Xiaganchaigou Formation is dom-

faults. Deformation atmiddle and shallow depths inthe Neogene rocks shows as fold thrusts (Figure 3).These thrusts are steep angle on the top and lowangle on the bottom, with folds on the hangingwalls. The fold thrusts gradually develop in timeand spatially in magnitude from west to east andfrom north to south (Zheng et al., 2004).Shangganchaigou Formation is composed of inter-bedded carbonate, sandstone, gypsum, and salt lay-ers (Chen et al., 2011; Hui et al., 2011). Thecombination of lithologies and evaporite-rich rockassemblages are reflected in the types of cementdeposits in fractures in the western Qaidam Basin.

Structure

The Qaidam Basin is a Mesozoic and Cenozoic in-tracontinental sedimentary basin superposed on apre-Jurassic block (Xia et al., 2001; Zhu et al.,2006). It was a rifted basin in the Early and MiddleJurassic, a foreland basin in the Late Jurassic andCretaceous, a weakly extensional basin in the Pa-leocene and Eocene, and a foreland basin in theOligocene, andwas in a fold-thrust setting from theMiocene to the Pleistocene. The main structuresformed when the Altyn Tagh faults (Figure 1A)had left-lateral strike slip, exhibiting a strong in-fluence on the western Qaidam Basin (Zhou et al.,2006; Yin et al., 2008). Uplift resulting from strongcompression is the main movement from the Ho-locene to the present and resulted in a denudation ofmore than 1000m (3280 ft) in the westernQaidamBasin (Zheng et al., 2004; Zhou et al., 2006; Zhuet al., 2006).

Multiple styles of deformation in the westernQaidamBasin exist. At depths ofmore than 3500m(11482 ft), high-angle thrust faults dominate inPaleogene rocks (Figure 3). Most thrust faults cut tothe upper Shangganchaigou Formation (23.3 Ma)(Figure 2) where they end in open folds. Somefaults have a large difference in bed thicknesses be-tween the hanging walls and footwalls; these wereearly synsedimentary normal faults and were re-versed to high-angle reverse faults during latercompression (Zheng et al., 2004). Some thrustfaults cut to the Pliocene or even to the surface ofEarth, probably marking late reactivation of theseZeng et al. 2005

Figure 1. (A) Location andtectonic setting of the QaidamBasin in northwestern China.NATF = northern Altyn Taghfault; SATF = southern AltynTagh fault (northwesternboundary fault of the QaidamBasin); NQLF = northern QilianShan fault; MQLF = middle

Qilian Shan fault; SQLF =

2006 Geologic NotesReservoir Characteristics

For Paleogene saline lacustrine carbonate reservoirs,core porosity from mercury injection is principallybetween 3 and 8%, and permeability is from 0.01to 1.0 md (Fu, 2010). When samples have micro-fractures, their permeabilities can reach 10.0 md.Porosity includes intercrystalline pores and intra-

granular and intergranular dissolved pores and frac-tures; almost no primary pores exist. Scanning elec-tron microscopy and mercury porosimetry revealthat the matrix has micropores (

pores are mainly in minerals like mirabilite and an-hydrite (Figure 4B) and, secondarily, in the locallydissolved brongniardit, anhydrite, halite, and calcitefill in the fractures (Figure 4C). The diameters ofdissolution pores are from 1 to 20 mm (0.03947.88 in.) (Figure 4D).

Hydrocarbon Production

The distribution of oil and gas is complex in thePaleogene saline lacustrine carbonate reservoirs.Adjacent wells may have markedly different pro-duction patterns. Wells with high outputs are

Figure 2. Schematic stratigraphy, source rock, and reservoirs in the western Qaidam Basin. The reservoirs discussed in this article aremarked by the gray box in the column on the right. The composite figure data are taken from two boreholes of cores and logs in theShizigou oil field.

Figure 3. Structural cross section based on surface geology and seismic data. The line location is shown in Figure 1B. , PaleoceneLulehe Formation; , Eocene Xiaganchaigou Formation; , Oligocene Shangganchaigou Formation; , Miocene XiayoushashanFormation; , Miocene Shangyoushashan Formation; , Pliocene Shizigou Formation and Pleistocene Qigequan Formation.Zeng et al. 2007

region B. In region A, wells A1, A2, and A3 are all region B, the oil rates in most vertical wells andFigure 5. Map of reverse faults fromseismic and well data on the Paleogenetop of the Shizigou oil field and the welllocation in regions A and B. The main

faults are northwest-southeast and the

2008 Geologic Notessecondary ones are north-south. Thevertical wells of A1, A2, B1, and B2 andthe inclined well of B3 and B4, located inthe hanging walls of northwest-southeastreverse faults, are good producers versusthe vertical wells of A3, B4, B5, and C1,which are poor producers. See Figure 1Bfor the location.locally located in regions A and B in the Shizigoustructure (Figure 5). Reservoirs are mainly in theOligocene Shangganchaigou Formation in region A

vertical wells in the same fault block. The initial oilproduction per day is more than 200 t (1460 bbl) inA1 and A2 but less than 10 t (73 bbl) in A3, which

Figure 4. Photographs of poresin saline lacustrine carbonate res-ervoirs of the Eocene Xiagan-chaigou Formation, Shizigou oilfield. (A) Micropores from scan-ning electron microscopy (SEM);depth, 4064.8 m (13,335.0 ft).(B) Dissolved pores in anhydritefrom SEM; depth, 4139.7 m(13,581.7 ft). (C) Dissolved pores infillings of fracture; depth, 4145.6 m(13,601.0 ft). P (pink) = dissolvedpore; G = gypsum filled in fractureearly. (D) Dissolved pores incore; depth, 4142.5 m (13,590.9 ft).The top of the core is at the leftside.and in the Eocene Xiaganchaigou Formation in is just tens of meters away from A1 and A2. In

(NMRI) were obtained from core-plug samplesinclined well B4 are more than 150 t/day (1095 bbl/day) but only 0.9 t (7 bbl) in the vertical well B4and 13.7 t (100 bbl) in vertical well B5 (Table 1).These abrupt differences in initial production can-not be accounted for by observed variations in hostrockmatrix porosity and permeability, which areuniformly low. Production rates from the best wellsare anomalous compared to the production thatwould be expected from the matrix porosity and

Table 1. Initial Oil Production Per Day in the Shizigou Structure

WellNumber Well Type Formation

Initial OilProduction

Per Day, t/day(bbl/day)

A1 Vertical well ShangganchaigouFormation

290 (2117)

A2 Vertical well 328 (2394)A3 Vertical well 6.9 (50)B1 Vertical well Xiaganchaigou

Formation180 (1314)

B2 Vertical well 955 (6971)B3 Inclined well 168 (1226)B4 Vertical well 0.9 (7)B4 Inclined well 168 (1226)B5 Vertical well 13.7 (100)C1 Vertical well 19 (138)permeability of cores. Together, these productioncharacteristics are typical for reservoirs where natural

s o e

I M

e t tun c ass is uel B) ft)in o d

lo lsac tie pM m dterpretations of FMI logs in 6

measure fracture attributes in cores alonto axes then revise and calculatfrom 8 wells. Samples were processed to 2.5 cm(1 in.) in diameter and were washed in alcohol andbenzene to less than three-level x-ray fluorescence.After being roasted to an invariable weight in a vac-uum drying box at a temperature of 65C, sampleswere saturated with simulant reservoir water andwere measured in NMRI. When samples were cen-trifugal by 6.8 104 kgf/m2, they were measuredin NMRI again. The T2 cutoff value can be deter-mined by comparing T2 relaxation time spectrumsbefore with those after being centrifugal; here, T2is the spectrum of the transverse relaxation timeof precessional protons relative to static magnetic-field axis during the fluid flow (Kenyon, 1992). Theclay boundwater porosity (fCBW) and the irreduc-ible porosity of the capillary bulk volume (fCBVI)were obtained from T2 distribution (Kenyon, 1992;Wang et al., 1998).

FRACTURE CHARACTERIZATION

Based on data from cores, thin sections, and imagelogs, fractures in the Paleogene carbonate reser-voirs can be divided into small faults, opening-mode (or extension) fractures, and bedding planesthat have slipped or extended. The small faultsare in en echelon patterns with downdip striations(Figure 6) and strike northeast-southwest. Theopening-mode fractures have steep dips and arealigned with the northwest-southeast strike of thefold-thrust belt. These fractures are generally short(

have large fracture apertures (range, 0.55 mm[0.01970.197 in.]), and show wedge shapes withwide tops and narrow lower tips (Figure 7). Bed-ding surfaces that show striations that mark slipare found where bed dips are high near thrusts andprobably mark flexural slip during folding or thrust-ing during post-Miocene shortening (Figure 8).Bedding planes have also been locally dilated, form-ing bed-parallel fractures or veins along laminae(Figure 9); these lack striations and we interpretthem to be of diagenetic origin. A similar assemblageof fractures can be found in outcrops of the pro-ducing units at the Xianshuiquan and Nanyishanfields (Figure 1B).

Formation MicroImager logs show four sets offracture orientations: northwest-southeast, north-south, northeast-southwest, and east-west strikes2010 Geologic Notesin the Paleogene carbonate reservoirs (Figure 10).Fracture strikes mimic the orientations of faultsand fold hinge lines. The development degree ofevery fracture set orientation is relevant to faults aswell as fold thrusts. Calculations with the MonteCarlo method (Howard, 1990) and logging inter-pretations indicate that the porosities of fracturesin 251 samples are distributed generally between0.1 and 0.8%,with a peak value of 0.2 to 0.3% anda maximum value of 2.08%. Fractures are the im-portant storage spaces of the tight saline lacustrinecarbonate reservoirs.

If cement is deposited while fractures are open-ing, the age of cement can give the age of fracturesFigure 7. Vertical opening-mode (extension) fractures of thenorthwest-southeast strike in the vertical cores of the EoceneXiaganchaigou Formation from the B1 well, Shizigou oil field,limestone; depth, 4169.5 m (13,679.5 ft). Fractures filled withcalcite are short and wide. See Figure 5 for the well location.Figure 6. The surface of the high-angle small fault (shear frac-ture) in the core of the Oligocene Shangganchaigou Formationfrom the vertical well, Nanyishan gas field, limestone; depth,3031.5 m (9945.9 ft). Calcite and striations mark the fracturesurface (arrow in slip direction). The top of the core is at the leftside. See Figure 1B for the Nanyishan gas field.Figure 9. Bed-parallel fractures along laminae in the core of theEocene Xiaganchaigou Formation from the B5 well, Shizigou oilfield, limestone; depth, 4063.2 m (13,330.7 ft). Dark areas (A) areopen-fracture pore space along bed-parallel fractures. Lighterareas (B) within fractures are isolated calcite deposits. See Figure 5for the well location.Figure 8. Bedding-plane slip fractures with striations in thecores of the Eocene Xiaganchaigou Formation from the inclinedB3 well. The arrow indicates slip direction. No cement fill on thefracture surfaces exists. Shizigou oil field, calcareous mudstone;depth, 4146.5 m (13,604.0 ft). The top of the core is at the leftside. See Figure 5 for the well location.

Figure 11. Average intensity of all fracture types in differentlithologies in the Shizigou oil field.analysis (Wei et al., 1999; Fu et al., 2010). Accord-ing to the statistics of average intensity of all frac-tures, lithology type is the most important factorgoverning fracture development in the QaidamBasin Paleogene saline lacustrine carbonate rocks(Figure 11). Fracture intensities are expected toincrease with increased content of brittle miner-als such as dolomite and calcite (Ortega et al.,2010). We found fracture abundances to be high-est in limy dolomite and dolomitic limestone and,secondarily, in the muddy dolomite and muddylimestone.

The opening-mode fracture abundance also re-flects mechanical bed thickness (Bai and Pollard,2000; Underwood et al., 2003). The opening-modefractures are arranged within the bed perpendic-ular to the bedding surface. For thin beds, the av-erage spacing of fractures varies linearly with bedthickness, that is, fracture spacing increases as bed

thickness increases (Figure 12).(Laubach, 2003). Carbon and oxygen isotope anal-ysis of calcite in all sets of filled opening-mode frac-tures from nine samples in the Eocene Xiagan-chaigou Formation in the Xianshuiquan structuresuggests that the time of fracturing is mainly fromthe Late Pliocene to the early Pleistocene (Liuet al., 1998), concurrent with the time of tectonicdeformation.

OBSERVATIONS OF FRACTURE ABUNDANCE

Based on data of outcrops and cores, we can mea-sure fracture attributes. Fracture abundance is in-fluenced by rock type (Nelson, 1985). The Paleo-gene lithology categories are based on composition

Figure 10. Fracture traces of the Oligocene ShangganchaigouFormation on Formation MicroImaging log, A1 well, Shizigouoil field. Dark linear features on the unwrapped image of theborehole wall mark conductive fracture traces of different setorientations in bedded carbonates. See Figure 5 for the welllocation.Figure 12. Relationship between the spacing of the opening-mode fractures of all sets and the bed thickness in the Nanyishangas field.Zeng et al. 2011

zone formed at the tip of F2.Fractures are filled with calcite inboth regions. See Figure 5 for theFaults control the location of fractures. Forexample, in Figure 13, a small-scale reverse faultformed in two phases of movement, and each phaseresulted in a fracture zone at the end of the fault.The early reverse fault (F1) has a higher angle; thelater one (F2) has a lower angle. Both have frac-ture zones filledwith calcite at the end in regions Aand B, respectively. Usually, fractures are better de-veloped along faults and in the regions of the hang-ing wall of large faults. Wells with high hydrocar-bon outputs are distributed at the hanging wall of

well location.Figure 13. (A) The raw image ofcore in the Eocene XiaganchaigouFormation from the vertical well B1,Shizigou oil field, limestone; depth,4175.6 m (13,699.5 ft). (B) Theimage with superimposed anno-tation showing the relationshipbetween fractures and faults. Theearly and later reverse faults aremarked by F1 (solid line) and F2(dashed line), respectively. Thedashed rings mark regions withfractures. Letter a indicates anearly fracture zone formed at thetip of F1; letter B, later fracturethe reverse faults of the northwest-southeast strike

2012 Geologic Notes40% of fractures are filled in the Nanyishan struc-ture distant from thedepositional center of gypsumand salt, where the gypsum and salt layers are lessthan 100 m (328 ft) thick.

Observation of partially filled fractures showsthat the degree of filling varies with fracture size.Cements preferentially seal smaller aperture frac-tures (Figure 14). From fracture strikes from FMIlogs in the Shizigou field (Figure 15), most of theopen fractures strike northwest-southeast, coin-cident with the main thrust faults in the basin. In

contrast, most of the filled fractures strike south-and along the reverse faults of the north-southstrike in the Shizigou field structure (Figure 5).

OBSERVATIONS OF CEMENT FILLIN FRACTURES

Observations of cement-filled fractures from coresand thin sections show that more than 50% of thefractures are filled with calcite, gypsum, or glau-berite (sodium calcium sulfate) in the carbonaterocks. The proportion of cement-filled fractures isrelative to the location of evaporite layers. For ex-ample, more than 90% of the fractures are ce-mented in the Shizigou structure, where the de-positional center of gypsum and salt is locally morethan 300m (984 ft) thick. In contrast, approximately

north, approximately parallel to the present-daymaximumhorizontal compressive-stress orientationobtained from borehole breakouts and earthquake

Figure 14. Core photograph of open fracture caused by the dis-solution of calcite fill in the fracture in the Eocene XiaganchaigouFormation from the inclined B3 well, Shizigou oil field, limestone;depth, 4123.8 m (13,529.5 ft). P = fracture pore space (black); N =narrow fractures being preferentially filled with calcite. The top ofthe core is at the left side. See Figure 5 for the well location.

source mechanisms (Wang et al., 2006). How-ever, in theC1well in the Shizigou field structure,the orientations of open and filled fractures strikenortheast-southwest, coincident with the strikeof themain fault nearby thewell (Figure 16). Theseshow that fractures occur in the fault damage zones,and fractures would tend to dilate in the stress statethat formed the faults (Tamagawa and Pollard,2008). Open fractures do not necessarily coincidewith the direction of the maximum horizontal com-pressive stress; precipitated cements can seal anyorientation fracture (Laubach et al., 2004a). Laterfault activity is very important to create productivefractures.

The filled fractures are also controlled by fac-tors such as fracture timing and proximity to gyp-sum and salt layers. The earlier the fractures de-veloped, the more likely they are to be filled withminerals. So, fractures formed later are probablymore likely to be effective and of benefit to thereservoir (Figure 17). The filling degree is also re-lated to mineral content, either gypsum or halite.Fractures closest to the gypsum and salt layers aremore commonly filled. Figure 18 shows the dis-tribution of gypsum in fractures in a well in theNanyishan field structure. Observation of cement-filled fractures shows that 67% of the fractures arefilled in section A (from 2950 to 2977 m [96789767 ft]), 25% of the fractures are filled in section B(from 2977 to 2999 m [97679839 ft]), and lessthan 10% of the fractures are filled in section C(from 2999 to 3040 m [98399974 ft]). With de-creased gypsum content, the proportion of filledfractures is also lower.

Dissolution and neotectonic uplift can makefilled fractures effective. Acidic water formed byFigure 16. Rose diagram of all fracturestrikes from Formation MicroImager inPaleogene carbonates in well C1. (A) Ori-entation of open fractures. (B) Orientationof sealed fractures. Open and sealed frac-tures are parallel to the main fault nearbythe well.Figure 15. Rose diagram of all fracturestrikes from Formation MicroImager inPaleogene carbonates in the Shizigou oilfield. (A) Orientation of open fractures.(B) Orientation of sealed fractures. Openfractures are northwest-southeast orien-tations parallel to the main faults and aresouth-north orientations parallel to thesecondary faults and the sealed fractures.The main orientations of sealed fracturesstrike south-north approximately parallelto the present-day maximum horizontalstress orientation obtained from boreholebreakouts and the earthquake source

mechanism (Wang et al., 2006).Zeng et al. 2013

from the Pliocene could have dissolved cementsandmade filled fractures effective (Figure 19). The

stronger the later dissolution, the more effective2014 Geologic Notesthe filled fractures. The Holocene uplift and ab-normally high fluid pressure can also make filledfractures crack again and improve their propensityto be open (Figures 17, 20).Figure 18. The relationship between the gypsum content andthe proportion of all filled fractures in the Oligocene Shang-ganchaigou Formation from one borehole of cores, Nanyishanfield structure. The gypsum beds are above layer A. In section A,67% of the fractures are filled; in section B, 25%; in section C,less than 10%. n = 150.organic maturation and clay-mineral transformation

Figure 17. Microfractures of the Oligocene ShangganchaigouFormation in a horizontal thin section from the A1 well, Shizigouoil field. The host rock is argillaceous limestone; depth, 4004 m(13,136 ft). Letter A indicates earlier fracture filled with gypsum;letter B, later open fracture filled with crude oil; letter C, openfracture that opened along an earlier fracture filled with gypsumand subsequently filled with crude oil. See Figure 5 for the welllocation.Figure 20. Microfractures of the Eocene Xiaganchaigou For-mation in a horizontal thin section from the B2 well, Shizigou oilfield. The host rock is lacustrine limestone; depth, 4122.8 m(13,526.2 ft). Early fractures filled with calcite and gypsum havebeen broken by neotectonic uplift or abnormally high fluidpressure and became open fractures filled with crude oil. Thehost rock is lacustrine limestone. See Figure 5 for the well lo-cation. Fa indicates early fracture set 1; Fb, later fracture set. C =fracture-filling calcite; G = fracture-filling gypsum; P = porosity.Figure 19. Microfractures of the Eocene Xiaganchaigou For-mation in a horizontal thin section from the B2 well, Shizigouoil field. The host rock is lacustrine limestone; depth, 4102 m(13,458 ft). F = earlier fracture filled with gypsum that has beendissolved as fracture filled with crude oil. See Figure 5 for thewell location.

ern Qaidam Basin.

tion coefficient (R) is 0.92. N = 25.COMPARISON OF CORE-FRACTUREOBSERVATIONS TO FREE FLUID

Effective (open) fractures are the main storagespaces and pathways for fluid flow in the Paleo-gene saline lacustrine carbonate reservoirs in thewestern Qaidam Basin. The fractures that are com-pletely filled are likely to be ineffective as fluidconduits (Laubach, 2003). Only those not filledwith minerals or those showing later dissolutionare effective (Figures 13, 14, 17, 19). Here, weestimate the location of open fractures that areeffective fluid conduits using the FFI and the freefluid saturation (SFF) derived from NMR. The FFIrefers to the bulk volume percentage of free fluid inrocks, and the free fluid saturation (SFF) is a ratio ofthe FFI and the total porosity (Coates et al., 2000):

FFI fT fCBW fCBVISFF FFIfT

1 fCBW + fCBVIfT

where FFI is the free fluid index, SFF is the free fluidsaturation, fT is the total porosity of rock, fCBW isthe clay boundwater porosity, and fCBVI is the ir-reducible porosity of the capillary bulk volume.

Open fractures improve the FFI and the SFF ofthe Paleogene saline lacustrine carbonate reservoirsand determine the potential throughput. The Pa-leogene carbonates have many micropores withslim throats and have high contents of clay min-erals. The strong capillary-bond forces and sorp-tion of clay minerals in the micropores result inlow oil saturation and FFI (Zeng and Li, 2009). Forexample, the total He porosities of 650 samplesfrom core-plug measurement mainly range from2.2 to 8.5% in the Shizigou structure. Based on theanalysis of 14 samples using the scanning electronmicroscope (SEM), the main clay minerals in thecarbonate reservoirs are montmorillonite, chlorite,and illite. Component analysis from x-ray diffrac-tion shows that the average clay-mineral abundanceis 20.5%. The NMR analyses show that the FFI isbetween 0.25 and 2.8% and that the SFF rangesfrom 0.97 to 43.9%. Open fractures are the sig-nificant factor on improving the FFI and the SFFbecause they connect the reservoir pores for fluidto flow. The FFI and the SFF increase with fractureporosity (Figure 21). Hence, the distribution ofthe open fractures is the key factor on the crea-tion of high-quality reservoirs in the Paleogenesaline lacustrine carbonate reservoirs in the west-Figure 21. Relationship between the free fluid saturation, ameasure of free fluid in rocks, and the porosity of all fracturetypes in the Paleogene saline lacustrine carbonate reservoirs inthe Shizigou oil field. Free fluid saturation is from nuclear mag-netic resonance data; fracture porosity is calculated from coreobservations of fracture abundance and openness. The correla-CONCLUSIONS

1. In thewesternQaidamBasin, themain fracturesin the Paleogene carbonate reservoirs are small,steeply dipping faults, near vertical opening-mode fractures and bedding slip surfaces. Alsopresent are partly cemented opening-mode frac-tures parallel to bedding planes, which we inter-pret to be of diagenetic origin.

2. The main factors governing fracture develop-ment are lithology, bed thickness and structure,and, especially, proximity to large faults. Frac-tures of all types are more abundant at fault tips,along the reverse faults of the south-north strikeand in the hanging wall of the reverse faults ofthe northwest-southeast strike.

3. Most fractures are filled with calcite, gypsum,or glauberite in the carbonate rocks. CementsZeng et al. 2015

Chen, G. J., G. C. Du, C. F. Lu, L. H. Xue, J. Chen, and X. B.Zhang, 2011, Sedimentary filling history and analysis

of its controlling factors in the Paleogene of the north-western Qaidam Basin, China (in Chinese with Englishabstract): Acta Sedimentologica Sinica, v. 29, p. 866875.

Coates, G. R., L. Z. Xiao, and M. G. Prammer, 2000, NMRlogging principles and application: Houston, Gulf Pub-lishing Company, 234 p.

Fu, S. T., 2010, Key controlling factors of oil and gas accumu-lation in the western Qaidam Basin and its implicationsfor favorable exploration direction (in Chinese withEnglish abstract): Acta Sedimentologica Sinica, v. 28,p. 373379.

Fu, S. T., Y. Li, X. Zhang, and H. Mei, 2010, Technology ofhydrocarbon exploration and development in the QaidamBasin I (in Chinese): Beijing, Petroleum Industry Press,385 p.

Gale, J. F. W., R. H. Lander, R. M. Reed, and S. E. Laubach,2010, Modeling fracture-porosity evolution in dolostone:Journal of Structural Geology, v. 32, no. 9, p. 12011211, doi:10.1016/j.jsg.2009.04.018.

Hood, S. D., C. S. Nelson, and P. J. J. Kamp, 2003, Modifica-tion of fracture porosity by multiphase vein mineraliza-tion in an Oligocene nontropical carbonate reservoir:preferentially seal smaller aperture fractures;the amount of fill in a fracture is controlled bythe time of fracture initiation and the distancefrom gypsum and salt layers in the succession,with older fractures and those closest to evap-orite layers being more completely filled. Theabundance of open fractures mainly coincideswith proximity to the regional main faults, notwith the direction of the maximum horizontalcompressive stress.

4. Open fractures are the main storage spaces andpathways for fluid flow and improve the FFI andthe SFF and determine the potential through-put. The FFI and the SFF increase with fractureporosity. Uneven distribution of open fracturesresulted in differences between the productionrates of neighboring boreholes.

REFERENCES CITED

Bai, T., and D. D. Pollard, 2000, Fracture spacing in layeredrocks: A new explanation based on the stress transition:Journal of Structural Geology, v. 22, no. 1, p. 4357,doi:10.1016/S0191-8141(99)00137-6.

Cao, H. F., B. Xia, L. Y. Fan, T. Zhang, and Y. Hu, 2007,Formation mechanism and distribution rule of Na-nyishan fractured reservoirs (in Chinese with English ab-stract): Natural Gas Geoscience, v. 18, no. 1, p. 7177.2016 Geologic NotesTaranaki Basin, New Zealand: AAPG Bulletin, v. 87,p. 15751597, doi:10.1306/06040301103.

Howard, J. H., 1990, Description of natural fracture systemsfor quantitative use in petroleum geology: AAPG Bulle-tin, v. 74, p. 151162.

Hui, B., H. S. Yi, G. Q. Xia, and X.Ma, 2011, Characteristicsof Cenozoic sedimentary evolution in western QaidamBasin (in Chinese with English abstract): Geology inChina, v. 38, p. 12741281.

Kenyon, W. E., 1992, Nuclear magnetic resonance as a pet-rophysical measurement: Nuclear Geophysics, v. 6, no. 2,p. 153171.

Laubach, S. E., 2003, Practical approaches to identifyingsealed and open fractures: AAPG Bulletin, v. 87, p. 561579, doi:10.1306/11060201106.

Laubach, S. E., and M. E. Ward, 2006, Diagenesis in porosityevolution of opening-mode fractures, Middle Triassic toLower Jurassic La Boca Formation: NE Mexico: Tecto-nophysics, v. 419, p. 7597, doi:10.1016/j.tecto.2006.03.020.

Laubach, S. E., J. E.Olson, and J. F.W.Gale, 2004a, Are openfractures necessarily aligned with maximum horizontalstress? Earth and Planetary Science Letters, v. 222,p. 191195.

Laubach, S. E., R. M. Reed, and J. E. Olson, 2004b, Coevo-lution of crack-seal texture and fracture porosity in sedi-mentary rocks: Cathodoluminescence observations ofregional fractures: Journal of Structural Geology, v. 26,p. 967982.

Li, Y. K., and T. C. Wang, 2001, Middle-deep fractured oilreservoir of Shizigou area in Qaidam Basin (in Chinesewith English abstract): Petroleum Exploration and De-velopment, v. 28, no. 6, p. 1217.

Liu, R. H., W. Zhou, and W. B. Liu, 1998, Evaluation ondistribution of natural fracture from tertiary reservoir,Xiansuiquan oil field in Chaidamu Basin (in Chinesewith English abstract): Journal of Mineralogy and Petrol-ogy, v. 72, no. 2, p. 5256.

Nelson, R. A., 1985, Geologic analysis of naturally frac-tured reservoirs: Houston, Gulf Publishing Company,352 p.

Ortega, O. J., R. A. Marrett, and S. E. Laubach, 2006, Ascale-independent approach to fracture intensity andaverage spacing measurement: AAPG Bulletin, v. 90,p. 193208, doi:10.1306/08250505059.

Ortega, O. J., J. F. W. Gale, and R. Marrett, 2010, Quantify-ing diagenetic and stratigraphic controls on fracture in-tensity in platform carbonates: An example from theSierra Madre Oriental, northeast Mexico: Journal ofStructural Geology, v. 32, p. 19431959, doi:10.1016/j.jsg.2010.07.004.

Peng, L. C., W. B. Shao, and L. Zhang, 2003, Fracture pre-diction of E23 reservoir in Yuehui 1 well block, Gasikuleoil field (in Chinese with English abstract): Oil & GasGeology, v. 24, p. 391395.

Tamagawa, T., and D. D. Pollard, 2008, Fracture permeabil-ity created by perturbed stress fields around active faultsin a fractured basement reservoir: AAPG Bulletin, v. 92,p. 743764, doi:10.1306/02050807013.

Tong, H. M., and D. Y. Cao, 2004, Genesis and distribution

pattern of fractures in western Qaidam Basin (in Chinesewith English abstract): Oil &Gas Geology, v. 25, p. 639649.

Underwood, C. A., M. L. Cooke, J. A. Simo, and M. A.Muldoon, 2003, Stratigraphic controls on vertical frac-ture patterns in Silurian dolomite, northeastern Wiscon-sin: AAPG Bulletin, v. 87, p. 121142.

Wang, W., S. Miao, and W. Liu, 1998, A study to determinethe moveable fluid porosity using NMR technology inthe rock matrix of Xiaoguai oil field: Society of Petro-leum Engineers Paper 50903, 9 p.

Wang, X. F., H. L. Wu, Y. S. Ma, C. J. Cao, L. Q. Wang, andX. H. Chen, 2006, Controls of the tectonic stress fieldand fluid potential field on hydrocarbon migration andaccumulation in the western Qaidam Basin, China (inChinese with English abstract): Geological Bulletin ofChina, v. 25, p. 10361044.

Wei, C. Z., Z. C. Li, and C. J. Wu, 1999, Characteristics ofthe fractured reservoir of condensate gas pool of Na-nyishan oil field in Qaidam Basin (in Chinese with Eng-lish abstract): Natural Gas Industry, v. 19, no. 4, p. 57.

Xia, W. C., N. Zhang, X. P. Yuan, L. S. Fan, and B. S. Zhang,2001, Cenozoic Qaidam Basin, China: A stronger tec-tonic inversed, extensional rifted basin: AAPG Bulletin,v. 85, p. 715736.

Xu, F. Y., C. M. Yin, Q. L. Gong, and Y. Shen, 2006, Meso-zoicCenozoic structural evolution in Qaidam Basin and

inces I: The general (in Chinese): Beijing, Petroleum In-dustry Press, 257 p.

Yin, A., Y. Q. Dang, M. Zhang, X. H. Chen, and M. W.McRivette, 2008, Cenozoic tectonic evolution of theQaidam Basin and its surrounding regions (Part 3):Structural geology, sedimentation, and regional tectonicreconstruction: Geological Society of America Bulletin,v. 120, no. 78, p. 847876, doi:10.1130/B26232.1.

Zeng, L. B., 2008, Formation and distribution of fractures inlow-permeability sandstone reservoirs (in Chinese):Beijing, Science Press, 169 p.

Zeng, L. B., and X. Y. Li, 2009, Fractures in sandstone reser-voirs of ultra-low permeability: The Upper Triassic Yan-chang Formation in the Ordos Basin, China: AAPG Bul-letin, v. 93, p. 461477.

Zheng, M. L., M. J. Li, C. C. Cao, and J. Y. Zhang, 2004,Characteristics of structures of various levels in the Qai-dam Cenozoic Basin (in Chinese with English abstract):Acta Geologica Sinica, v. 78, no. 1, p. 2635.

Zhou, J. X., F. Y. Xu, T. C. Wang, A. F. Cao, and C. M. Yin,2006, Cenozoic deformation history of the Qaidam Ba-sin, NW China: Results from cross-section restorationand implications for Qinghai-Tibet Plateau tectonics:Earth and Planetary Science Letters, v. 243, p. 195210, doi:10.1016/j.epsl.2005.11.033.

Zhu, L. D., C. S. Wang, H. B. Zheng, F. Xiang, H. S. Yi, andD. Z. Liu, 2006, Tectonic and sedimentary evolution ofbasins in the northeast of Qinghai-Tibet Plateau andstract): China PetroleumExploration, v. 11, no. 6, p. 917.Ye, D., X. Zhong, Y. Yao, F. Yang, S. Zhang, Z. Jiang, and Y.

Wang, 1993, Tertiary strata in Chinese petroliferous prov-their implication for the northward growth of the Pla-teau: Paleogeography, Paleoclimatology, Paleoecology,v. 241, p. 4960, doi:10.1016/j.palaeo.2006.06.019.its control over oil and gas (in Chinese with English ab-Zeng et al. 2017