Enhanced Tight Oil Recovery by Volume Fracturing in Chang 7 Reservoir: Experimental Study and Field Practice

energies

Article Enhanced Tight Oil Recovery by Volume Fracturing in Chang 7 Reservoir: Experimental Study and Field Practice

Long Yu 1,2, Jinjie Wang 1,* , Chong Wang 3 and Daixin Chen 4 1 Key Laboratory of Tectonics and Petroleum Resources (China University of Geosciences), Ministry of Education, Wuhan 430074, China; [email protected] 2 Department of Chemical Engineering, University of Calgary, Calgary, AB T2N1N4, Canada 3 Research Institute of Exploration & Development, Changqing Oilﬁeld Company, PetroChina, Xi’an 710018, China; wch_cq@petrochina.com.cn 4 No. 12 Oil Production Plant, Changqing Oilﬁeld Company, PetroChina, Xi’an 710018, China; [email protected] * Correspondence: [email protected]

Received: 13 May 2019; Accepted: 19 June 2019; Published: 24 June 2019

Abstract: The Chang 7 reservoir in Changqing oilfield is rich in tight oil. However, due to the low formation permeability, it is very difficult to obtain economical oil production without stimulation treatments. Volume fracturing seems to be a more efficient tight oil recovery enhancement (EOR) method in Chang 7 pilot tests compared with conventional hydraulic fracturing. In this study, Chang 7 tight oil reservoir was first characterized by its geological property, hydrocarbon source rock distribution, and formation physiochemical property. Tight core flooding tests were then conducted to experimentally investigate the EOR ability of the volume fracturing technique. The field-scale practice was also demonstrated and analyzed. The results show that Chang 7 reservoir is favorable for the generation of a large amount of tight oil. Fractures created in tight cores can significantly improve the fluid flow conductivity and enhance the imbibition of displacing water, resulting in a greater tight oil recovery increment. Volume fracturing is an effective way to generate a larger number of fractures. Field application indicates that volume fracturing treatment can form a much greater reservoir stimulation volume. Daily oil production in the volume-fracturing-treated wells can be more than twice as high as that in the conventional-fracturing-treated wells.

Keywords: volume fracturing; Chang 7 reservoir; tight oil recovery; imbibition; oil production

1. Introduction With the world’s increasing need for energy and the gradual decline of conventional oil and gas production, attention has been turned toward unconventional reservoirs such as shale oil and shale gas [1]. Resources in tight reservoirs are substantial worldwide. Global gas reserves in shale reservoirs are estimated to be 716 trillion m3 [2]. America has turned unconventional resource production into a commercial process. Tight sand production and shale gas account for about 30% of total gas production in America [3]. China has the largest natural gas resources in tight reservoirs or tight sand reservoirs [4,5]. However, although there is large resource potential in tight reservoirs, it is much more diﬃcult to extract oil and gas from a tight formation than from conventional reservoirs, mainly due to the small pore size and the ultra-low permeability of the matrix [6,7]. Hydraulic fracturing combined with horizontal drilling has been widely used to enhance the production of oil and gas from tight sands or shale reservoirs [8,9]. Hydraulic fracturing improves hydrocarbon transport by increasing the formation’s permeability and enhancing extraction. The main

Energies 2019, 12, 2419; doi:10.3390/en12122419 www.mdpi.com/journal/energies Energies 2019, 12, 2419 2 of 22 approach is to cut the low-permeability matrix into small pieces to increase the rock surfaces and connectivity. The fine induced fractures maximize the area of contact with the rocks, allowing hydrocarbon extraction from thousands of meters of rocks, rather than tens or hundreds of meters available with merely vertical wells [10,11]. Fracture networks connect each small piece of the matrix to the hydrocarbon flow path to the production well [12,13]. Many successful cases worldwide demonstrate that hydraulic fracturing enhances oil recovery in unconventional reservoirs [14,15]. Hydraulic fractures connecting with natural fracture systems ensure a more effective stimulation in fractured reservoirs, but the occurrence of arrest, diversion, and offset may inhibit the fracture growth and proppant placement. Blanton’s [16] conducted laboratory hydraulic fracturing experiments using pre-fractured material to investigate the interactions between hydraulic fractures and natural fractures, aiming to provide information that helps to examine the conditions under which such inhabitations happen so that detrimental effects can be prevented. His results show that the morphology of hydraulic fracture is significantly affected by the pre-existing fractures, and hydraulic fractures are more likely to cross natural fractures only in high stresses and under high pre-existing fracture angles. Maity and Ciezobka [17] developed a novel image-processing workflow method to detect and analyze the proppant distribution in more than 200 through-fracture Permian Basin core samples to investigate proppant transport behavior in stimulated formation volumes during hydraulic fracturing treatment. The observations show that the presence of hydraulic fracture and of natural fracture and their interactions do not necessarily result in high proppant concentration in the cores, and stress contrast and lithology changes can govern the local in-depth proppant distribution. Their study provides a new method to systematically analyze core samples for the distributions of proppant and similar particles. Cipolla et al. [18] identified the benefits of tortuosity, multiple fractures, and the apparent activation of natural fractures and verified their potential using both fracture modeling and G-function analyses. Luo et al. [19] conducted a reservoir simulation using a geo-model to simulate the unique flow regime in multi-stage fractured horizontal wells compound formation linear flow. Results showed good agreement with field data of the Bakken formation. In recent years, due to the rapid development of the tight oil/gas industry, the oil/gas recovery technique has made great progress. The appearance of volume fracturing has resulted in a great increase in tight oil and gas production [20]. The conventional hydraulic fracturing treatment aims to create a bi-wing open fracture in tight reservoir formations [21]. The fluid flowability is mainly affected by one fracture, but the fracture cannot improve the flowability of the total reservoir formation because, in the vertical direction of the fracture, the oil/gas still experiences a long-distance matrix flow in the low permeability porous media, as shown in Figure1a. The single fracture limits the final oil/gas recovery efficiency, as the fluid flowability in the vertical direction is not increased [22,23]. To improve reservoir productivity, the fracture should be designed with a high fracture length and a high fracture conductivity [24]. The volume fracturing technique can generate single open fractures and can create and extend complex fracture networks [23,25]. In volume fracturing treatment, the reservoir formation was reconstructed and broken up through the fracturing method, forming several main fractures. By using the high flux, a large volume, and low viscosity fluids, together with the “staged and multi-cluster” perforation, secondary fractures can be generated in the main fractures. In the same way, second-order secondary fractures, and third-order secondary fractures, can also be created to form a complex fracture network in the formation [25,26], as shown in Figure1b. The volume of the formation with fracture networks is called the stimulated reservoir volume (SRV) [27,28]. Fractures generated by volume fracturing are not only conventional open fractures, they also experience a shear/sliding dilation process [29], which leads to larger contact areas between the fracture faces and formation matrix. Due to the great number of created fractures, the complex fracture network and the large fracture-contact area, the oil/gas in the stimulated reservoir formations can flow along the shortest distance in any direction from the matrix to the fractures, significantly increasing the overall formation permeability [25,26,30]. Therefore, the reservoir formation can be effectively reconstructed, and reservoir productivity can be greatly improved. Energies 2019, 12, 2419 3 of 22 Energies 2019, 12, x FOR PEER REVIEW 3 of 23

(a) (b)

Figure 1. Schematic of conventional hydr hydraulicaulic fracture and fracture ne networktwork by volume fracturing: (a) Conventional fracture,fracture, ((b)) fracturesfractures byby volumevolume fracturingfracturing treatment.treatment.

BothFractures conventional generated fracturing by volume and fracturing volume fracturing are not only are sand conventional fracturing open techniques. fractures, According they also to someexperience criteria, a shear/sliding sand fracturing dilation treatment process with [29], a fracturing which fluidleads volumeto larger smaller contact than areas 1500 between m3 is called the conventionalfracture faces fracturing, and formation and that matrix. with aDue fracturing to the fluidgreat volumenumber larger of created than 1500 fractures, m3 is called the complex volume fracturingfracture network [31]. However,and the large volume fracture-contact fracturing area, still hasthe oil/gas other characteristics in the stimulated in reservoir terms of operations.formations Incan volume flow alongfracturing, the shortest the fluid distance injection in any rate direction is relatively from high, the usuallymatrix to larger the fractures, than 10 m significantly3/min, but it canincreasing be slightly the overall smaller formation in some specificpermeability reservoirs. [25,26,30]. Volume Therefore, fracturing the isreservoir usually formation operated withcan be a smallereffectively proppant reconstructed, (70/100 and mesh~40 reservoir/70 mesh) productivity and a lower can be sand greatly ratio, improved. with an average range of 3–5%. In someBoth cases, conventional the sand ratiofracturing can be and around volume 10%, fractu dependingring are on sand the formation fracturing properties. techniques. Slickwater According is mostlyto some used criteria, as the sand fracturing fracturing fluid treatment [32,33]. In with some a conventionalfracturing fluid fracturing volume theories, smaller thethan injection 1500 m of3 is a significantcalled conventional volume of fracturing, fracturing and fluids that with with high a fracturing pressures wouldfluid volume cause a larger serious than filter 1500 loss m problem3 is called of thevolume fluid fracturing in the matrix [31]. and However, forming shortervolume hydraulic fracturing fractures, still has resulting other characteristics in formation damagein terms and of non-eoperations.ffective In fracturing volume fracturing, treatment. the However, fluid injection volume rate fracturing is relatively treatment high, always usually accompanies larger than by10 injectionm3/min, ofbut large it can volume be slightly fracturing smaller fluids. in First, some this specific is because reservoirs. the segmented Volume multi-cluster fracturing is fracturing usually techniqueoperated with is usually a smaller employed proppant in the(70/100 volume mesh~40/70 fracturing mesh) treatment and a tolower form sand fracture ratio, networks with an average [34–36]. Inrange conventional of 3–5%. stagedIn some fracturing cases, the treatment sand ratio in horizontal can be around wells, the 10%, single depending cluster perforation on the formation method isproperties. usually used, Slickwater which is can mostly only used support as the the fractu lowring volume fluid and [32,33]. low rateIn some of fracturing conventional fluid fracturing injection, nottheories, the large the injection fluid injection of a significant required byvolume the multi-cluster of fracturing fracturing. fluids with Second, high pressures the volume would fracturing cause a isserious more filter suitable loss forproblem and usually of the fluid being in applied the matrix in brittleand forming formations, shorter which hydraulic are more fractures, easily resulting to form ain great formation number damage of complex and non-effect fracturesive during fracturing the large treatment. volume However, injection fracturingvolume fracturing treatments. treatment Third, becausealways accompanies of the low permeability by injection of tightof large oil rocks, volume the filtrationfracturing loss fluids. of fracturing First, this fluids is tobecause the matrix the issegmented very small, multi-cluster most of the fracturing large volume technique fluids is wouldusually flow employed into the in the numerous volume inducedfracturing fractures treatment or theto form natural fracture microfractures, networks which[34–36]. could In conventional increase the staged stimulated fracturing reservoir treatment volume. in Study horizontal results wells, from Lithe et single al. [37 cluster] show thatperforation volume method fracturing is canusually significantly used, which increase canthe only production support the of tight low oilvolume reservoirs. and Alow larger rate fracturedof fracturing volume fluid and injection, increased not fracture the large networks fluid injection could result required in greater by the oil multi-cluster production. Chenfracturing. et al. [Second,31] compared the volume the investment fracturing and is more benefit suitable between for conventional and usually hydraulic being applied fracturing in brittle and volumeformations, fracturing which inare the more Southern easily Sichuanto form Basina grea andt number found of that complex tested gasfractures production during yield the large from volume fracturinginjection fracturing is about 2.12 treatments. times that Third, of conventional because of fracturingthe low permeability technology. of The tight wide oil application rocks, the offiltration volume loss fracturing of fracturing in the fluids field could to the reduce matrix the is very circle small, returns most and of decrease the large total volume costs. fluids would flow Theinto Changqingthe numerous oilfield induced is a fractures regional or oilfield the natural affiliated microfractures, with PetroChina which Companycould increase Limited the (PetroChina).stimulated reservoir In 2012, volume. the oil-gas Study equivalent results from exceeded Li et 45al. million [37] show tons, that making volume it the fracturing biggest fieldcan insignificantly China. The increase work areathe production is located inof thetight Ordos oil reservoirs. Basin, with A larger an exploration fractured volume area of 3.7and increased105 km2. × Changfracture 7 networks is a block richcould in result tight oil in withgreater estimated oil production. resources Chen reaching et al. up [31] to twocompared billion tons.the investment Hydraulic fracturingand benefit has between been tried conventional for tight oil hydraulic recovery infracturing Chang 7. and However, volume pilot fracturing tests and in field the dataSouthern show thatSichuan conventional Basin and hydraulicfound that fracturing tested gas treatments production cannot yield from efficiently volume improve fracturing the oilis about production 2.12 times rate, whereasthat of conventional volume fracturing fracturing treatment technology. in the The Chang wide 7 application tight oil formations of volume can fracturing lead to a in significant the field increasecould reduce in the the tight circle oil returns production and anddecrease a great total decrease costs. in the water cut. The Changqing oilfield is a regional oilfield affiliated with PetroChina Company Limited (PetroChina). In 2012, the oil-gas equivalent exceeded 45 million tons, making it the biggest field in China. The work area is located in the Ordos Basin, with an exploration area of 3.7 × 105 km2. Chang

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7 is a block rich in tight oil with estimated resources reaching up to two billion tons. Hydraulic fracturing has been tried for tight oil recovery in Chang 7. However, pilot tests and field data show that conventional hydraulic fracturing treatments cannot efficiently improve the oil production rate, whereas volume fracturing treatment in the Chang 7 tight oil formations can lead to a significant Energies 2019, 12, 2419 4 of 22 increase in the tight oil production and a great decrease in the water cut. In this study, the geological and physical properties of Chang 7 tight oil reservoir were characterizedIn this study, first. the The geological tight oil and recovery physical ability properties of the ofvolume Chang frac 7 tightturing oil reservoirtreatment were was characterized investigated first.through The core tight flow oil recovery experiments ability and of field the volume scale practice. fracturing The treatment results of was this investigated work may provide through some core flowinstructions experiments with andthe applicability field scale practice. of the volume The results fracturing of this worktechnique may providein tight someoil reservoirs instructions for EOR. with the applicability of the volume fracturing technique in tight oil reservoirs for EOR. 2. Characterization of Chang 7 Tight Oil Reservoir 2. Characterization of Chang 7 Tight Oil Reservoir 2.1. Geological Characteristics 2.1. Geological Characteristics Figure 2 shows the location and typical sedimentary facies of the Chang 7 reservoir, the ChangqingFigure2 oilfield. shows theChang location 7 is the and main typical tight sedimentary oil reservoir facies in China of the Changand is located 7 reservoir, in the the Ordos Changqing Basin. oilfield.The Ordos Chang Basin 7 isis thea typical main tightinland oil sedimentary reservoir in Chinabasin with and isa locatedmultiphase in the craton Ordos in Basin. the southwest The Ordos of BasinNorth is China. a typical Delta inland facies sedimentary and lacustrine basin facies with we a multiphasere widely developed craton inthe in the southwest Ordos Basin. of North The China. delta Deltafront faciessand bodies, and lacustrine the gravity facies current were widely settled developed sediments in in the semi-deep–deep Ordos Basin. Thelake delta faces, front and sand the bodies,turbidity the sand gravity bodies current are the settled most sedimentsimportant inreserv semi-deep–deepoir sand bodies lake for faces, Chang and 7. The the turbidityreservoir sandsand bodiesbodies areare the close most to important the hydrocarbon reservoir sand source bodies rocks, for Chang possessing 7. The reservoirfavorable sandconditions bodies arefor close the toaccumulation the hydrocarbon of tight source oil. rocks, possessing favorable conditions for the accumulation of tight oil.

FigureFigure 2.2. LocationLocation of of the Ordos Basin together with typical sedimentary facies and sand bodybody distributionsdistributions ofof thethe ChangChang 77 tighttight oiloil reservoir,reservoir, thetheChangqing Changqingoilﬁeld. oilfield.

2.2.2.2. Characteristics of Hydrocarbon Source RocksRocks TheThe hydrocarbonhydrocarbon sourcesource rocksrocks ofof ChangChang 7 are mainly composed of oil shale and dark mudstone. FigureFigure3 3shows shows the the isoline isoline graphs graphs of theof the thickness thickness of the of sourcethe source rock distributionsrock distributions in Chang in Chang 7, the Ordos 7, the Basin.Ordos TheBasin. oil The shale, oil foundshale, largelyfound largely at the bottomat the bo ofttom the Changof the Chang 7 oil reservoir 7 oil reservoir group, group, distributes distributes in the NW–SEin the NW–SE direction, direction, reaching reaching ZhiDan atZhiDan the northeast, at the northeast, Majiatan at Majiatan the northwest, at the Zhenyuan-Jingchuannorthwest, Zhenyuan- at theJingchuan southwest, at the and southwest, Yijun-Huangling and Yijun-Huangling at the southeast, at andthe southeast, it is estimated and that it is 37%estimated of the totalthat 37% volume of the of source rocks in this area are oil shale, with an average thickness of 16 m and a total area of 3.25 104 km2, total volume of source rocks in this area are oil shale, with an average thickness of 16 m and× a total asarea shown of 3.25 in Figure× 104 km3a.2 The, as hydrocarbonshown in Figure generation 3a. The center hydrocarbon for oil shale generation is at Jiyuan-Huachi-Zhengning. center for oil shale is at ComparedJiyuan-Huachi-Zhengning. with oil shale, the Compared dark mudstone with possessesoil shale, a widerthe dark distribution. mudstone It reachespossesses Ansai a atwider the northeast,distribution. Majiatan It reaches at theAnsai northwest, at the northeast, Pingliang Maji atatan the southwest,at the northwest, and Huanglong Pingliang at at the the southwest, southeast, and the distribution of mudstone covers an area of 5.11 104 km2 in the direction of NW–SE, with an × average thickness of 17 m, as shown in Figure3b. The mudstone occupies 63% of the total volume of source rocks. Energies 2019, 12, x FOR PEER REVIEW 5 of 23

and Huanglong at the southeast, and the distribution of mudstone covers an area of 5.11 × 104 km2 Energiesin the direction2019, 12, 2419 of NW–SE, with an average thickness of 17 m, as shown in Figure 3b. The mudstone5 of 22 occupies 63% of the total volume of source rocks.

(a) (b)

FigureFigure 3.3. IsolineIsoline graph graph of of the the thickness thickness of hydrocarbonof hydrocarbon source source rock rock distributions distributions in Chang in Chang 7, the Ordos7, the Basin:Ordos (Basin:a) Oil shale,(a) Oil (shale,b) dark (b mudstone.) dark mudstone.

TheThe totaltotal organicorganic carboncarbon (TOC)(TOC) isis an important characterization parameterparameter ofof the organic matter abundanceabundance in hydrocarbonhydrocarbon source rocks.rocks. In In this this study, 123 core samples from Chang 7 werewere ﬁrstfirst collected,collected, andand aa carboncarbon andand sulfursulfur analyzeranalyzer (CS(CS analyzer,analyzer, model:model: CSCS 230,230, LECO,LECO, St.St. Joseph, MO, USA) waswas usedused toto measuremeasure thethe TOCTOC inin the hydrocarbon sourcesource rocks.rocks. The CS 230 an analyzeralyzer can conveniently measuremeasure thethe TOCTOC datadata withwith highhigh accuracyaccuracy and high stability, withwith aa 11 ppmppm oror 5%5% relativerelative standardstandard deviationdeviation (RSD)(RSD) measurementmeasurement accuracy. Hydrocarbon source rocks of Chang 7 are rich inin organicorganic matter.matter. OrganicOrganic geochemical geochemical data data indicate indicate that thethat residual the residual organic carbonorganic content carbon in thecontent hydrocarbon in the sourceshydrocarbon rocks sources mainly distributesrocks mainly in thedistributes range of in 2–22%. the range In some of 2–22%. source rocks,In some the source residual rocks, organic the carbonresidual content organic can carbon be as content high as can 30–40%. be as high Figure as4 30–40%. shows the Figure distributions 4 shows the of thedistributions total organic of the carbon total (TOC)organic for carbon dark (TOC) mudstone for dark and oilmudstone shale in and the oil Chang shale 7 in reservoir. the Chang It can7 reservoir. be seen thatIt can TOC be seen for dark that mudstoneTOC for dark is smaller mudstone than is 10, smaller it mainly than concentrates 10, it mainly inconcentrates the range of in two the torange ﬁve. of While two to for five. oil While shale, thefor TOCoil shale,has athe wider TOC range has a from wider 2 to range 25. The from average 2 to 25. TOC The for average dark mudstone TOC for and dark oil mudstone shale is 5.8% and and oil 13.8%,shale is respectively. 5.8% and 13.8%, respectively.

Figure 4. TOC distribution for source rocks in Chang 77 inin thethe OrdosOrdos Basin.Basin.

The corresponding vitrinite reflectance (Ro) for the source rocks of the Chang 7 reservoir is between 0.85% and 1.15%, indicating a high intensity of hydrocarbon generation. It is estimated that Energies 2019, 12, x FOR PEER REVIEW 6 of 23 Energies 2019, 12, 2419 6 of 22 The corresponding vitrinite reflectance (Ro) for the source rocks of the Chang 7 reservoir is between 0.85% and 1.15%, indicating a high intensity of hydrocarbon generation. It is estimated that 4 2 the averageaverage intensityintensity ofof hydrocarbonhydrocarbon generationgeneration inin ChangChang 77 isis 495495 × 10104 kmkm2. The total amount of × 8 generated hydrocarbons hydrocarbons in in the the source source rocks rocks can can be be as as high high as as2473.08 2473.08 × 10810 ton.ton. The Thesource source rocks rocks also × alsoexperienced experienced a strong a strong hydrocarbon hydrocarbon expulsion expulsion process, process, with a with hydrocarbon a hydrocarbon expulsion expulsion intensity intensity of 290 4 2 8 of× 102904 km210, andkm a ,hydrocarbon and a hydrocarbon expulsion expulsion amount amount of 1447.71 of 1447.71× 108 ton. It10 canton. be Itseen can that be seen the Chang that the 7 × × Changreservoir 7reservoir in the Changqing in the Changqing oilfield possesses oilfield possesses a significant a significant amount amountof favorable of favorable hydrocarbon hydrocarbon source sourcerocks, which rocks, ensures which ensures a high capacity a high capacity for generating for generating and producing and producing oil. oil.

2.3. Physical Properties of Reservoir Formations Testing datadata collectedcollected from fourfour pilot areas, Maling,Maling, Heshui, Jiyuan, and Ansai, in Chang 7 were used to characterize the physical properties of thethe tight oil reservoirreservoir formations.formations. Figure 55 shows shows thethe location distribution ofof thethe four pilot areas. As ca cann be seen, the pilot areas covered most of the typical formations inin thethe Chang Chang 7 7 tight tight oil oil reservoir, reservoir, so theso the physical physical properties properties results results measured measured in these in these areas canareas be can used be toused characterize to characterize the overall the ov physicalerall physical properties properties for Chang for Chang 7. 7.

Figure 5. Locations of the four pilot areas in Chang 7 reservoir.

Table1 1 givesgives the detrital detrital components components of of the the tight tight reservoir reservoir rocks rocks of the of four the pilot four areas pilot in areas Chang in Chang7. It can 7. Itbe can seen be that seen the that tight the tight sandstones sandstones are aremainly mainly composed composed of ofquartz, quartz, feldspar, feldspar, and and lithic fragments, which occupy 77.3% of the total total composit compositionion analyzed analyzed through through a a number number of of rock rock samples. samples. Therefore, the formation rocks possess a high brittlenessbrittleness and tend to form complex fractures during fracturing treatments.

Table 1. Detrital components for the four pilot areas in Chang 7.7.

DetritalDetrital Composition Composition [%] [%] Pilot AreaPilotNumber Number of Sample of Quartz Feldspar LithicLithic Fragment Others Area Sample Quartz Feldspar Others Maling 68 40 18.4Fragment 18.4 23.2 HeshuiMaling 6668 40 41.2 18.4 20.8 18.4 16.923.2 21.1 JiyuananHeshui 12366 41.2 25 20.8 38.9 16.9 12.321.1 23.8 AnsaiJiyuanan 31123 25 26.8 38.9 40.6 12.3 11.4 23.8 21.2 Sum 288 32.5 30.1 14.7 22.7 Ansai 31 26.8 40.6 11.4 21.2 Sum 288 32.5 30.1 14.7 22.7 To obtain the porosity and permeability distributions in Chang 7 reservoir, a number of core samples from the formation layers of four blocks of Maling, Heshui, Jiyuan, Ansai were collected and

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To obtain the porosity and permeability distributions in Chang 7 reservoir, a number of core samplesEnergies 2019 from, 12, the 2419 formation layers of four blocks of Maling, Heshui, Jiyuan, Ansai were collected7 and of 22 the porosity and permeability of the cores were measured. The core data, together with the reservoir well logging results, were used to draw the porosity and permeability maps. Table 2 shows the coring details,the porosity Figure and 6 shows permeability the porosity of the distributions cores were measured. for the blocks The of core Maling, data, togetherHeshui, Jiyuan with the and reservoir Ansai, Figurewell logging 7 shows results, the permeability were used to results. draw theThe porosity dots and and lines permeability in the figures maps. are Tablethe existing2 shows wells. the coring details, Figure6 shows the porosity distributions for the blocks of Maling, Heshui, Jiyuan and Ansai, Figure7 Tableshows 2. theThe permeability coring details results.for the analysis The dots of poro andsity lines and in permeability the ﬁgures arein Chang the existing 7 reservoir. wells.

Number of Average Average BlocksTable 2.FormationThe coring detailsLayer for the analysis of porosity and permeability in Chang 7 reservoir. Core Samples Porosity [%] Permeability [mD] Blocks Formation Layer Number of Core Samples Average Porosity [%] Average Permeability [mD] Maling Chang 72 2234 9.1 0.13 Maling Chang 7 2234 9.1 0.13 Heshui Chang2 71 2575 8.9 0.14 Heshui Chang 71 2575 8.9 0.14 JiyuanJiyuan ChangChang 72 72 34553455 8.9 8.9 0.12 0.12 Ansai Chang 7 4067 8.1 0.11 Ansai Chang3 73 4067 8.1 0.11

(a) (b)

FigureFigure 6. Porosity (%)(%) distributionsdistributions of of the the four four pilot pilot areas areas in Chang in Chang 7: (a )7: Maling, (a) Maling, (b) Heshui, (b) Heshui, (c) Jiyuan, (c) Jiyuan,(d) Ansai. (d) Ansai.

PorositiesPorosities of of the the reservoir reservoir formations formations in in Maling, Maling, Heshui, Heshui, Jiyuan, Jiyuan, and and Ansai Ansai mainly mainly distributes distributes in thein therange range of of6–11%, 6–11%, 7–11%, 7–11%, 6–10%, 6–10%, and and 6–9%, 6–9%, resp respectively.ectively. Most Most of of the the reservoir reservoir formation formation permeabilitiespermeabilities are are smaller smaller than than 0.2 0.2 mD (Figure 77a–c).a–c). In Ansai,Ansai, thethe formationformation permeabilitypermeability can bebe muchmuch smaller, smaller, as as shown shown in in Figure 77d.d. The average porosity of Chang 7, as calculatedcalculated based on thethe overalloverall core core analysis, analysis, is is around around 8–9%, 8–9%, and and the the average average permeability permeability is about is about 0.11–0.14 0.11–0.14 mD. mD. As Ascan canbe seen,be seen the, theChang Chang 7 reservoir 7 reservoir possesses possesses very very low lowporo porositysity and andpermeability, permeability, which which are unfavorable are unfavorable for oilfor production. oil production. The micropore structure of the tight sandstones in the Chang 7 tight oil reservoir was measured using X-ray computed tomography (X-CT). X-CT is a widely used and reliable technology that can rapidly measure the pore structures of tight cores with high accuracy, and the measurement scale of CT ranges from nm to µm level. Figure8 shows the variation in pore volume at di ﬀerent pore radii. The results were obtained based on an X-CT analysis of 52 cores from the Chang 7 reservoir. The pore radius of the Chang 7 tight oil reservoir mainly distributes in the range of 2–10 µm. Pores with a radius Energies 2019, 12, x FOR PEER REVIEW 8 of 23

Energies 2019, 12, 2419 8 of 22 of 2–10 µm occupy 76.8% of the total pore volume in the reservoir and thus are the main storage space forEnergies the 2019 tight, 12 oil., x FOR PEER REVIEW 8 of 23

(a) (b)

Figure 7. Permeability (mD) distributions of the four pilot areas in Chang 7: (a) Maling, (b) Heshui, (c) Jiyuan, (d) Ansai.

The micropore structure of the tight sandstones in the Chang 7 tight oil reservoir was measured using X-ray computed tomography (X-CT). X-CT is a widely used and reliable technology that can rapidly measure the pore structures of tight cores with high accuracy, and the measurement scale of CT ranges from nm to μm level. Figure 8 shows the variation in pore volume at different pore radii. The results were obtained based on an X-CT analysis of 52 cores from the Chang 7 reservoir. The pore radius of the Chang 7 tight oil (reservoirc) mainly distributes in the(d) range of 2–10 μm. Pores with a radiusFigure of 2–10 7.7. Permeability μm occupy (mD) 76.8% distributions of the total of the pore four volume pilot areas in inthe Chang reservoir 7: ( a) and Maling, thus (b )are Heshui, the main storage((cc)) Jiyuan,Jiyuan,space for ((dd)) Ansai.theAnsai. tight oil.

The micropore structure of the tight sandstones in the Chang 7 tight oil reservoir was measured using X-ray computed tomography (X-CT). X-CT is a widely used and reliable technology that can rapidly measure the pore structures of tight cores with high accuracy, and the measurement scale of CT ranges from nm to μm level. Figure 8 shows the variation in pore volume at different pore radii. The results were obtained based on an X-CT analysis of 52 cores from the Chang 7 reservoir. The pore radius of the Chang 7 tight oil reservoir mainly distributes in the range of 2–10 μm. Pores with a radius of 2–10 μm occupy 76.8% of the total pore volume in the reservoir and thus are the main storage space for the tight oil.

Figure 8. VariationVariation of pore volumes at didifferentﬀerent porepore radiusradius forfor thethe tighttight rocksrocks ofof ChangChang 7.7.

Figure9 9 showsshows the coordination coordination numbers numbers of of the the po poresres for forthe theChang Chang 7 tight 7 tightoil reservoir. oil reservoir. It can Itbe can seenbe that seen the that overall the overall coordination coordination number number for the for pores the pores is small, is small, mainly mainly concentrating concentrating in 1–3. in 1–3. Coordination number characterizes the number of pore throats that connect to one pore body.

The smaller coordination number means poorer pore connectivity because, in such case, the pores were connected with fewer throats, which would limit the ﬂuid ﬂowability in the tight porous media. Although most of the pore body radius of Chang 7 reservoir are between 2 µm and 10 µm, and the pore

Figure 8. Variation of pore volumes at different pore radius for the tight rocks of Chang 7.

Figure 9 shows the coordination numbers of the pores for the Chang 7 tight oil reservoir. It can be seen that the overall coordination number for the pores is small, mainly concentrating in 1–3.

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Coordination number characterizes the number of pore throats that connect to one pore body. The smaller coordination number means poorer pore connectivity because, in such case, the pores were Energies 2019, 12, 2419 9 of 22 connected with fewer throats, which would limit the fluid flowability in the tight porous media. Although most of the pore body radius of Chang 7 reservoir are between 2 μm and 10 μm, and the throatpore throat radius radius could could be much be much smaller. smaller. Results Results in Figure in Figure8 indicates 8 indicates that itthat is di it ﬃis cultdifficult for the for tightthe tight oils ﬂowingoils flowing in the in porous the porous media, media, and thus and uneconomicthus unecon toomic recover to recover them fromthem the from reservoir the reservoir without without further stimulationfurther stimulation treatment. treatment. To acquire To economicallyacquire economically feasible tight feasible oils, hydraulictight oils, fracturinghydraulic techniquesfracturing shouldtechniques be utilized. should be utilized.

Figure 9. CoordinationCoordination number for the pores of Chang 7 tight oil reservoir. 3. Experimental Section for Tight Oil Recovery in Pore-Fracture Dual Media 3. Experimental Section for Tight Oil Recovery in Pore-Fracture Dual Media 3.1. Flow Conductivity of Pore-Fracture Media and Its Effects on Tight Oil Recovery 3.1. Flow Conductivity of Pore-Fracture Media and Its Effects on Tight Oil Recovery The flow conductivity in a pore-fracture dual medium can be much higher than that in single pore The flow conductivity in a pore-fracture dual medium can be much higher than that in single media due to high permeability fractures. In order to investigate the flow behaviors of oil and water pore media due to high permeability fractures. In order to investigate the flow behaviors of oil and in the dual medium, relative permeability measurements were conducted through core flow tests. water in the dual medium, relative permeability measurements were conducted through core flow Because cores with fractures are easily broken, it is difficult to obtain them from the reservoir formations tests. Because cores with fractures are easily broken, it is difficult to obtain them from the reservoir directly. In this study, the unbroken cores from Chang 7 formations, 2.5 cm in diameter and 6 cm in formations directly. In this study, the unbroken cores from Chang 7 formations, 2.5 cm in diameter length, were compressed using the tri-axial compression method to create different microfractures. and 6 cm in length, were compressed using the tri-axial compression method to create different During the fracture creating process, we used the trial and error method to make fractured cores microfractures. During the fracture creating process, we used the trial and error method to make which possess appropriate initial permeabilities until the required cores were successfully achieved. fractured cores which possess appropriate initial permeabilities until the required cores were The successfully made cores would be then used for the relative permeability tests. The relative successfully achieved. The successfully made cores would be then used for the relative permeability permeability of oil and water were measured using the un-steady state method. The change of tests. The relative permeability of oil and water were measured using the un-steady state method. cumulative production of oil and water with time was recorded carefully to accurately calculate the The change of cumulative production of oil and water with time was recorded carefully to accurately relative permeability data. Figure 10 shows four typical results for the relative permeability variations calculate the relative permeability data. Figure 10 shows four typical results for the relative of oil and water in the cores with different fractures. Before fracturing, the cores possess similar initial permeability variations of oil and water in the cores with different fractures. Before fracturing, the permeability (ki). The core permeabilities after fracturing (kf) are mainly determined by the developed cores possess similar initial permeability (ki). The core permeabilities after fracturing (kf) are mainly fractures. The after-fracturing permeabilities of the core sample (Figure 10a,b) do not increase very determined by the developed fractures. The after-fracturing permeabilities of the core sample (Figure much compared to the initial permeabilities. For core sample (Figure 10a), the permeability increases 10a,b) do not increase very much compared to the initial permeabilities. For core sample (Figure 10a), from 0.08 mD to 0.19 mD, and for core sample (Figure 10b), it increases from 0.14 mD to 0.36 mD. the permeability increases from 0.08 mD to 0.19 mD, and for core sample (Figure 10b), it increases In such cases, the fractures created by the tri-axial compression method in the cores are more likely from 0.14 mD to 0.36 mD. In such cases, the fractures created by the tri-axial compression method in the pre-existing microfractures in formations. The fractures possess a small size, small number and the cores are more likely the pre-existing microfractures in formations. The fractures possess a small have limited effects on the fluid flow conductivity increase in the cores. The permeabilities of the core size, small number and have limited effects on the fluid flow conductivity increase in the cores. The sample (Figure 10c,d) have a significant increase after fracturing, the measured kf can be as high as permeabilities of the core sample (Figure 10c,d) have a significant increase after fracturing, the 5.48 mD and 12.14 mD, respectively. In such cases, the created fractures in the cores are more likely measured kf can be as high as 5.48 mD and 12.14 mD, respectively. In such cases, the created fractures the produced fractures by fracturing treatment in formations. Such fractures were more complex and in the cores are more likely the produced fractures by fracturing treatment in formations. Such with a larger number and larger size than the fractures in core sample (Figure 10a) and core sample fractures were more complex and with a larger number and larger size than the fractures in core (Figure 10b). sample (Figure 10a) and core sample (Figure 10b). As can be seen in Figure 10, before fracturing, the flow of oil and water occurs in the matrix of the cores. The relative permeability of oil first decreases rapidly with water saturation and then declines slowly. The relative permeability of water increases gradually. The cores possess a wide two-phase Energies 2019, 12, 2419 10 of 22

flow region. After fracturing, due to the developed microfractures, the flow conductivity in all of the cores has a great increment for both oil and water. For cores with slightly increased permeability, sometimes two to three times higher than that before fracturing (Figure 10a,b), the variations of relatively permeabilities for oil and water are similar to that in the un-fractured cores. The relative permeability of oil declines, and the relative permeability of water inclines gradually. The intersection of the two-phase relative permeability curves is higher in the fractured cores, indicating a greater increase in fluid flowability after fracturing. In addition, the fractured cores still have a wide two-phase flow region. If the permeabilities of the cores after fracturing are much higher than that before fracturing, as shown in Figure 10c,d, there is no doubt that flow conductivity in the cores can be improved greatly. However, the relative permeabilities for the oil phase and the water phase change drastically with water saturation in these fractured cores. The two-phase flow region becomes much smaller than the un-fractured cores and the slightly fractured cores. In such cases, a more rapid water breakthrough will occur through these fractures in the cores when flooded with water. Therefore, in order to efficiently increase oil recovery in tight oil formations through fracturing treatments, such fractures with an appropriate flow conductivity should be created. The developed fractures in formations could enhance theEnergies fluid 2019 flowability., 12, x FOR PEER REVIEW 10 of 23

1 1 Kro before fracturing Kro before fracturing Krw before fracturing 0.8 0.8 Krw before fracturing Kro after fracturing Kro after fracturing Krw after fracturing Krw after fracturing 0.6 0.6 Kr Kr 0.4 0.4

0.2 0.2

0 0 0 20406080100 0 20406080100 Sw (%) Sw (%) (a) (b) 1 1 Kro before fracturing Kro before fracturing Krw before fracturing Krw before fracturing 0.8 0.8 Kro after facturing Kro after fracturing Krw after fracturing Krw after fracturing 0.6 0.6 Kr Kr 0.4 0.4

0.2 0.2

0 0 0 20406080100 0 20406080100 Sw (%) Sw (%) (c) (d)

FigureFigure 10. 10. RelativeRelative permeabilities permeabilities of oil of and oil water and waterin the cores in the before cores and before after fracturing: and after fracturing:(a) ki = 0.08 (mD,a) ki k=f =0.08 0.19 mD mD,, k (fb=) k0.19i = 0.14 mD, mD, (b k)f =k i0.36= 0.14 mD, mD,(c) ki k=f 0.07= 0.36 mD, mD, kf = 5.48 (c) kmD,i = (0.07d) ki mD,= 0.07k mD,f = 5.48 kf = 12.14 mD, (mD.d) ki = 0.07 mD, kf = 12.14 mD.

FigureAs can 11 be shows seen in the Figure variations 10, before of tight fracturing, oil recoveries the inflow the of fractured oil and coreswater at occurs diﬀerent in the permeability matrix of ratiosthe cores. of the The after-fracturing relative permeabilit core permeabilityy of oil first to thedecreases before-fracturing rapidly with core water permeability saturation (kf /kandi). then declines slowly. The relative permeability of water increases gradually. The cores possess a wide two- phase flow region. After fracturing, due to the developed microfractures, the flow conductivity in all of the cores has a great increment for both oil and water. For cores with slightly increased permeability, sometimes two to three times higher than that before fracturing (Figure 10a,b), the variations of relatively permeabilities for oil and water are similar to that in the un-fractured cores. The relative permeability of oil declines, and the relative permeability of water inclines gradually. The intersection of the two-phase relative permeability curves is higher in the fractured cores, indicating a greater increase in fluid flowability after fracturing. In addition, the fractured cores still have a wide two-phase flow region. If the permeabilities of the cores after fracturing are much higher than that before fracturing, as shown in Figure 10c,d, there is no doubt that flow conductivity in the cores can be improved greatly. However, the relative permeabilities for the oil phase and the water phase change drastically with water saturation in these fractured cores. The two-phase flow region becomes much smaller than the un-fractured cores and the slightly fractured cores. In such cases, a more rapid water breakthrough will occur through these fractures in the cores when flooded with water. Therefore, in order to efficiently increase oil recovery in tight oil formations through fracturing treatments, such fractures with an appropriate flow conductivity should be created. The developed fractures in formations could enhance the fluid flowability.

Energies 2019, 12, x FOR PEER REVIEW 11 of 23

Figure 11 shows the variations of tight oil recoveries in the fractured cores at different permeabilityEnergies 2019, 12 ratios, 2419 of the after-fracturing core permeability to the before-fracturing core permeability11 of 22 (kf/ki).

60.0 无水期驱油效率Water cut = 0 50.0 含水98%驱油效率Water cut = 98%

40.0

30.0 Oil recovery /%

驱油效率(%) 20.0

10.0

0.0 0 30 60 90 120 150 180 裂缝与基质的渗透率级差（倍） kf / ki

FigureFigure 11. 11. OilOil recovery recovery variations variations with with different diﬀerent permeability permeability ratios ratios at at different diﬀerent water cuts.

ItIt can can be be seen seen that that both both of of the the tight tight oil oil recoveri recoverieses of ofthe the cores cores decrease decrease with with an increase an increase of the of the permeability ratio kf/ki. Before water breakthrough (water cut = 0), the decrease of oil recovery permeability ratio kf/ki. Before water breakthrough (water cut = 0), the decrease of oil recovery with permeabilitywith permeability ratio ratiois small. is small. However, However, when when wate waterr cut cut= 98%,= 98%, the the tight tight oil oil recovery recovery decreases decreases significantlysignificantly as as the the permeability permeability ratio ratio increases. increases. This This is is because because the the created created fractures fractures in in the the cores cores possesspossess a a higher higher permeability permeability than than the the matrix, matrix, and and du duee to to the the small small size size of of the the cores, cores, some some of of the the fracturesfractures may formform throughthrough thethe whole whole cores cores from from the the inlet inlet to to the the outlet. outlet. These These fractures fractures could could help help the theoil inoil the in matrixthe matrix to flow to flow out moreout more easily easily and thusand canthus improve can improve the oil the production oil production rate. However, rate. However,due to duethe highto the conductivity, high conductivity, once the once water the breaks water through breaks through from these from very these high very permeability high permeability fractures, fractures,especially especially from those from that those connect that the connect core inlet the to core the inlet core outlet,to the core thefollowing outlet, the displacing following fluid displacing would fluidbe more would likely be tomore flow likely through to flow these through highly permeablethese highly water permeable channels, water rather channels, than flow rather into thethan matrix flow intoto displace the matrix oil. This to waterdisplace channeling oil. This problem water couldchanneling be more problem severe as could the permeability be more ofsevere the fractures as the permeabilitybecomes greater, of the leaving fractures more becomes residual greater, oil in the leaving tight coresmore [ 38residual]. In the oil field in the scale, tight because cores [38]. of the In long the fielddistance scale, between because the of injection the long well distance and the between production the injection well and well the appropriate and the production operations, well most and of the the appropriatefractures are operations, unlikely to most break of through the fractures the wells are toun leadlikely to to the break water through channeling the problem.wells to lead Therefore, to the waterfracturing channeling treatment problem. in field Therefore, can usually fracturing result in hightreatment oil production in field can rate usually like the result core flooding in high butoil productionmay rarely causerate like the the water core channeling flooding but problem may ra asrely in thecause core the experiments. water channeling problem as in the core experiments. 3.2. Effect of Imbibition on Oil Recovery in Fractured Tight Oil Reservoir

3.2. EffectIn conventional of Imbibition oil on reservoirs,Oil Recovery the in oil Fractured is flooded Tight out Oil from Reservoir the pore spaces by the displacing fluids. The oil recovery is improved mainly by the displacement effect. However, in tight oil reservoirs, because In conventional oil reservoirs, the oil is flooded out from the pore spaces by the displacing fluids. of the ultra-low permeability, it is much more difficult for the tight oil to be displaced out by the injected The oil recovery is improved mainly by the displacement effect. However, in tight oil reservoirs, water than the conventional oil. In such reservoirs, apart from the displacement effect, the imbibition because of the ultra-low permeability, it is much more difficult for the tight oil to be displaced out by of water in the pore spaces plays an important role in tight oil recovery improvement. Fracturing the injected water than the conventional oil. In such reservoirs, apart from the displacement effect, treatment can improve the oil production rate in tight reservoirs. The matrix of reservoir formations the imbibition of water in the pore spaces plays an important role in tight oil recovery improvement. provides spaces for tight oil storage, and the created fractures mainly provide highly conductive flow Fracturing treatment can improve the oil production rate in tight reservoirs. The matrix of reservoir channels for the oil. In the early recovery stage, most of the produced oil comes from the fractures. formations provides spaces for tight oil storage, and the created fractures mainly provide highly As the oil in the fractures flows out, the following oil would be mainly from the matrix. In this stage, conductive flow channels for the oil. In the early recovery stage, most of the produced oil comes from water in the fractures imbibes into the low permeability matrix to displace tight oil out from the pore the fractures. As the oil in the fractures flows out, the following oil would be mainly from the matrix. spaces. Such an imbibition effect is important for the oil recovery in the fracturing-treatment tight In this stage, water in the fractures imbibes into the low permeability matrix to displace tight oil out reservoirs, especially when the reservoir is in the mid or late development stages. from the pore spaces. Such an imbibition effect is important for the oil recovery in the fracturing- Figure 12 shows a detailed schematic of the imbibition effect on oil recovery in a tight porous treatment tight reservoirs, especially when the reservoir is in the mid or late development stages. medium with fractures. Imbibition in pore-fracture dual media can be described as the wetting phase Figure 12 shows a detailed schematic of the imbibition effect on oil recovery in a tight porous (water) in fractures spontaneously imbibed into the matrix of the tight porous media under the capillary medium with fractures. Imbibition in pore-fracture dual media can be described as the wetting phase force, replacing the non-wetting phase (oil) in the tight pore spaces. The replaced oil will then enter the fracture systems and finally flow into the wellbore. The complex fractures in tight porous media divide the total matrix into a number of smaller pieces, which provides more interaction areas for the EnergiesEnergies 2019 2019, ,12 12, ,x x FOR FOR PEER PEER REVIEW REVIEW 1212 of of 23 23

(water)(water) inin fracturesfractures spontaneouslyspontaneously imbibedimbibed intointo thethe matrixmatrix ofof thethe tighttight porousporous mediamedia underunder thethe capillarycapillary force, force, replacing replacing the the non-wetting non-wetting phase phase (oil) (oil) in in the the tight tight pore pore spaces. spaces. The The replaced replaced oil oil will will Energiesthenthen enterenter2019, 12 thethe, 2419 fracturefracture systemssystems andand finallyfinally flowflow intointo thethe wellbore.wellbore. TheThe complexcomplex fracturesfractures in in12 tight oftight 22 porousporous mediamedia dividedivide thethe totaltotal matrixmatrix intointo aa nunumbermber ofof smallersmaller pieces,pieces, whichwhich providesprovides moremore waterinteractioninteraction and theareas areas oil. for for Therefore, the the water watermore and and the displacingthe oil. oil. Therefore, Therefore, water more canmore invade displacing displacing the matrix water water canto can replace invade invadethe the the oilmatrix matrix inside. to to Thereplacereplace imbibition the the oil oil einside. inside.ffect would The The imbibition thusimbibition be enhanced. effect effect would would As the thus thus oilflows be be enhanced. enhanced. out from theAsAs th matrix,thee oil oil flows theflows dense out out from fracturesfrom the the canmatrix,matrix, also the the provide dense dense morefractures fractures flow can can channels also also provide provide for the more more replaced flow flow oil,channels channels which for for increases the the replaced replaced the possibility oil, oil, which which of increases increases further movementthethe possibility possibility of the of of furtheroil. further movement movement of of the the oil. oil.

MatrixMatrix FractureFracture

WaterWater OilOil

InvadedInvaded area area MatrixMatrix

WaterWater FractureFracture

OilOil

FigureFigure 12. 12. Schematic Schematic of of the the imbibition imbibition effect e effectﬀect on on oil oil recoveryreco recoveryvery in in tight tight porous porous mediamedia media withwith with fractures.fractures. fractures.

FigureFigure 13 13 shows shows a a comparisoncomparison comparison test test of of thethe the waterwater water imbibitionimbibition imbibition raterate rate inin in tighttight tight corescores cores withwith with andand and withoutwithout without fractures.fractures.fractures. The The permeability permeability of of the the matrix matrix of of the the two two tight tight cores cores is is 0.08 0.08 mD. mD. Fractures Fractures in in the the cores cores were were createdcreated usingusing using aa a tri-axialtri-axial tri-axial compressioncompression compression apparatus.apparatus. apparatus.

(a(a) )

(b(b) )

FigureFigure 13. 13. Images Images of of of imbibition imbibition imbibition rate rate rate of of ofwater water water in in intight tight tight cores: cores: cores: ( a(a) )Core (Corea) Core without without without fractures, fractures, fractures, ( b(b) )core core (b) with corewith withfractures.fractures. fractures.

AsAs can can be bebe seen seen in in in Figure Figure Figure 13, 13, 13 the ,the the imbibition imbibition imbibition proces proces processss in in the the in tight the tight tight core core corewith with withfractures fractures fractures is is much much is muchfaster faster fasterthanthan that that than in in that the the core in core the without without core without fractures. fractures. fractures. In In the the co Incorere the without without core without fractures, fractures, fractures, the the water water the was was water imbibed imbibed was imbibed into into the the intomatrixmatrix the slowly slowly matrix from from slowly the the from bottom. bottom. the bottom.In In the the core core In thewithwith core fr fractures,actures, with fractures, the the water water the tended tended water to to tended first first enter enter to first into into enter the the intofracturesfractures the fractures rapidly, rapidly, rapidly,and and the the water andwater the then then water begins begins then to to begins be be imbibed imbibed to be into imbibed into the the nearby nearby into the matrix matrix nearby along along matrix the the alongfractures. fractures. the fractures.AfterAfter about about After 240 240 min, aboutmin, the the 240 core core min, with with the fractures fractures core with can can fractures be be completely completely can be occupied completely occupied by by occupied the the imbibed imbibed by thewater, water, imbibed more more water,thanthan five fivemore times times than faster fasterfive thantimes than the the faster core core than without without the core fracture fracture withouts.s. The The fractures. fractures fractures The in in the fracturesthe ti tightght cores cores in the can can tight significantly significantly cores can significantly increase the contact areas for the water and the core matrix and thus can improve the imbibition rate in the cores remarkably. Provided that the cores were saturated with oil in advance, a higher oil producing rate enhanced by the imbibition effect can be expected in the fractured cores. Energies 2019, 12, x FOR PEER REVIEW 13 of 23

increase the contact areas for the water and the core matrix and thus can improve the imbibition rate Energies 2019, 12, 2419 13 of 22 in the cores remarkably. Provided that the cores were saturated with oil in advance, a higher oil producing rate enhanced by the imbibition effect can be expected in the fractured cores. CapillaryCapillary pressure pressure is the is the main main driving driving force force of the of the imbibition imbibition effect effect in tightin tight porous porous media media [39 ,[39,40].40]. As theAs capillarythe capillary pressure pressure is inversely is inversely proportional proportion to the capillaryal to the radius,capillary the smallerradius, capillarythe smaller possesses capillary greaterpossesses capillary greater pressure capillary in it andpressure thus has in it a and stronger thus imbibitionhas a stronger effect. imbibition The average effect. pore The diameter average for pore tightdiameter porous mediafor tight can porous be several media to can tens be of several nanometers, to tens which of nanometers, ensures a highwhich capillary ensures force a high in capillary those pores.force To in have those an pores. effective To have oil recovery an effective in the oil fracturing recovery in treatment the fracturing of tight treatment oil reservoirs, of tight the oil capillary reservoirs, pressurethe capillary or the imbibition pressure shouldor the imbibition be high enough should to be overcome high enough the end to e ffovercomeect between the the end fractures effect between and thethe matrix. fractures Another and the thing matrix. one should Another be thing concerned one should with be is thatconcerned a smaller with pore is that radius a smaller is not pore always radius helpfulis not for always the imbibition-enhanced helpful for the imbibition-enhanced oil recovery. In order oil recovery. to effectively In order replace to effectively oil with water replace in tightoil with porouswater media, in tight the poreporous radius media, should the be pore larger radius than theshould thickness be larger of the than water the adsorption thickness layer of the on thewater poreadsorption walls. layer on the pore walls. DuringDuring the the water water flooding flooding process process in in tight tight oil oil reservoirs, reservoirs, apart apart fromfrom thethe displacementdisplacement effect, effect, oil oil recoveryrecovery cancan alsoalso be be enhanced enhanced by by the the imbibition imbibition eff effect,ect, as as discussed discussed above. above. To To determine determine the the oil oil recoveryrecovery factors factors of the of the displacement displacement effect effect and and the th imbibitione imbibition effect, effect, flooding flooding tests tests for for Chang Chang 7 tight 7 tight corescores with with different different permeabilities permeabilities were performed, were performed, and nuclear and magnetic nuclear resonance magnetic (NMR) resonance technology (NMR) wastechnology used to analyze was used thedi toff analyzeerent oil the recoveries. different oil recoveries. FigureFigure 14 shows 14 shows a typical a typical frequency frequency spectrum spectrum of the of the transversal transversal relation relation time time (T2 )(T measured2) measured by by NMRNMR for afor tight a tight oil coreoil core at di atff erentdifferent oil saturations.oil saturations.

FigureFigure 14. Frequency14. Frequency spectrum spectrum of relation of relation time time for tightfor tight oil coreoil core at di atﬀ erentdifferent oil saturations. oil saturations.

In Figure 14, the area between the T frequency at 100% water saturation (blue curve) and the In Figure 14, the area between the2 T2 frequency at 100% water saturation (blue curve) and the T2 T2 frequencyfrequency atat 100%100% oiloil saturation (red curve) characte characterizesrizes the the total total oil oil saturation saturation in in the the tight tight core. core. The The area between the T frequency after water flooding (green curve) and the T frequency at 100% oil area between the T2 frequency after water flooding (green curve) and the2 T2 frequency at 100% oil saturationsaturation characterizes characterizes the the total total movable movable oil inoil thein the tight tight core. core. As As can can be seen,be seen, in tightin tight oil reservoirs,oil reservoirs, duedue to the to the low low permeability permeability and and poor poor pore pore connectivity, connectivity, a large a large amount amount of oil of cannotoil cannot be movedbe moved and and producedproduced and and will will remain remain in thein the reservoir reservoir as residualas residual oil. oil. The The water water flooding flooding process process in tightin tight oil oil reservoirsreservoirs is designed is designed to recoverto recover the the movable movable oil asoil muchas much as possible.as possible. During During the the water water flooding flooding process,process, the the movable movable oil isoil produced is produced both both by theby the water wa imbibitionter imbibition effect effect and and the the water water displacement displacement effect.effect. The The relaxation relaxation time cut-otimeff cut-offvalue wasvalue used was to characterizeused to characterize the limitation theof limitation movable oilof recoveredmovable oil by therecovered two diff byerent the e fftwoects different [41–43]. Aseffects shown [41–43]. in Figure As 14shown, for oilin recoveredFigure 14, by for the oil imbibition recovered eff byect the (yellow area), the corresponding T is smaller than the cut-off value, and the corresponding T is larger imbibition effect (yellow area),2 the corresponding T2 is smaller than the cut-off value,2 and the than cut-off value. corresponding T2 is larger than cut-off value. BasedBased on theon the NMR NMR analysis analysis of the of the water water flooding flooding tests te insts the in the tight tight cores, cores, oil recoveriesoil recoveries improved improved by theby imbibitionthe imbibition effect effect and the and displacement the displacement effect were effect obtained. were obtained. Table3 shows Table the 3 detailedshows movablethe detailed oil recoverymovable resultsoil recovery for the results imbibition for the e ffimbibitionect and the effect displacement and the displacement effect in 17 tight effect oil in cores 17 tight from oil the cores Changfrom 7 reservoir.the Chang 7 reservoir.

Energies 2019, 12, 2419 14 of 22

Table 3. Movable oil recoveries aﬀected by imbibition and displacement in Chang 7 tight cores.

Recovered Movable Oil Saturation [%] Recovery of Movable Oil [%] Core Number Permeability [mD] Porosity [%] Total Movable Oil Saturation [%] Imbibition Effect Displacement Effect Imbibition Effect Displacement Effect 1 0.014 7.5 24.42 9.81 14.61 40.17 59.83 2 0.014 6.7 25.45 13.06 12.39 51.32 48.68 3 0.015 7.1 28.42 12.77 15.65 44.93 55.07 4 0.034 10.1 34.21 13.21 21 38.61 61.39 5 0.038 10.7 34.16 10.77 23.39 31.53 68.47 6 0.044 9.9 35.31 13.23 22.08 37.47 62.53 7 0.045 10.2 37.06 13.48 23.58 36.37 63.63 8 0.058 10.5 35.31 11.01 24.3 31.18 68.82 9 0.065 10.3 32.7 10.12 22.58 26.00 58.02 10 0.066 10 38.92 10.8 28.12 28.18 73.38 11 0.067 11.9 38.32 9.46 28.86 24.69 75.31 12 0.096 11.3 36.87 6.67 30.2 18.09 81.91 13 0.102 11.1 37.72 5.29 32.43 14.02 85.98 14 0.104 10.7 34.81 3.23 31.58 9.28 90.72 15 0.108 11.7 39.04 5.22 33.82 13.37 86.63 16 0.135 10.9 39.79 2.12 37.67 5.33 94.67 17 0.143 8.6 36.01 4.59 31.42 12.75 87.25 Energies 2019, 12, 2419 15 of 22

As we can see in Table3, because of the low permeability, the tight cores obtained from the Chang 7 reservoir possess a low movable oil saturation (<40%). During the water flooding process, the imbibition effect could have a significant contribution to the movable oil recovery in the tight cores, as about 5.33–51.32% of the movable oil recovery was improved by the water imbibition. It can also be seen in Table3 that the imbibition e ffect in tight cores decreases with the increase in core permeability. In the cores with lower permeabilities, e.g., where k < 0.06 mD, a large portion of movable oil (around 30–50%) could be recovered by the imbibition effect. In cores with higher permeabilities, the water displacement takes a much more predominant effect. The measurements and experimental tests in this study can provide instructive data to further reservoir simulation and optimization operations. The permeability, porosity and pore structure distribution data obtained from thousands of core sample analysis could help to enhance the reliability of the accurate description for the physical properties of reservoir formations. The relative permeability tests provided useful data for the analysis of flow behavior of tight oil and water in pore-fracture dual media. The EOR results from core flooding experiments could give instructions to the pilot operations during the fracturing treatments, i.e., when enhancing oil recovery in tight oil reservoirs using fracturing treatment, on one hand, the developed high permeability fractures could increase the oil production rate, on the other hand, such existing high permeability channels could lead to a higher water cut and a smaller final oil recovery factor. Thus, creating proper fractures considering both the production rate and final oil recovery is of great significance to the application of fracturing in tight oil reservoirs.

4. Field Practice of Volume Fracturing Treatment

4.1. Field Development Stages in the Chang 7 Reservoir The field development in the Chang 7 tight oil reservoir has experienced four stages. The first is the directional well development stage. Directional well tests were conducted from 2010 to 2011. During this stage, water injection accompanied by multistage sand fracturing in directional wells was performed. The average amount of ceramic proppant injected into each well was 32.1 m3. The sand ratio in the fracturing fluid was 29.8%, and the fluid injection rate was 2.0 m3/min. The production rate in the treated directional wells was low, about 1.5 ton/day in every well, indicating little improvement to the tight oil recovery. To solve the problem of the low production rate in the directional wells, in 2011, conventional fracturing treatment in horizontal wells was tried in the Chang 7 reservoir. The fluid injection rate of the conventional fracturing was smaller than 6 m3/min. The production results in six treated horizontal wells showed that a significant oil production rate improvement can be obtained in the early well production stage, reaching about 5.3 ton/day in every well. However, the wells were soon watered out and oil production rate dropped rapidly. In 2012, the volume fracturing pilot test in the Chang 7 reservoir was carried out. Twenty-four horizontal wells were treated by volume fracturing during this stage. Compared with conventional fracturing, the fluid injection rate of volume fracturing was higher than 6 m3/min, with a larger injected fracturing fluid volume. After volume fracturing treatment, the oil production rate in horizontal wells can be markedly increased to as high as 10 ton/day, almost twice as high compared with the conventional fracturing treatment. In Chang 7 reservoir, a segmented multi-cluster fracturing with fast-drilling bridge plugs technique was applied during the volume fracturing treatment [38], as shown in Figure 15. The long horizontal well was divided into several intervals by bridge plugs, and three to five clusters perforations were performed in every interval. The multi-cluster perforations can support the large volume fluid injection which is required to form a great number of complex fractures. In addition, due to the shorter inter-fracture distance in the multi-cluster fracturing, the interference between them can generate more complex fracture networks [25]. In Chang 7 reservoir, the formation rocks possess a high brittleness as the quartz, feldspar and lithic fragment composed over 70% of the Energies 2019, 12, 2419 16 of 22 rocks, which are more easily to form a great number of complex fractures during the large volume injection fracturing treatments. Energies 2019, 12, x FOR PEER REVIEW 16 of 23

Figure 15. Schematic of the segmented multi-cluster fracturing technique with bridge plugs.

Considering thethe significant significant promotion promotion of oil of production oil production with the with pilot the volume pilot fracturingvolume fracturing treatment, atreatment, large-scale a large-scale field application field application of hydraulic ofvolume hydraulic fracturing volume infracturing four blocks in four in the blocks Chang in 7the reservoir Chang was7 reservoir launched was from launched 2013 from to 2016. 2013 By to 2016. the end By ofthe 2016, end of 414 2016, wells 414 in wells Chang in Chang 7 had 7 been had treatedbeen treated with volumewith volume fracturing. fracturing. The average The average oil production oil production rate of rate the of treated the treated wells waswells 9.6 was ton /9.6day ton/day per well per for well the firstfor the three first months. three months. So far, theSo far, total the tight total oil tight production oil production in these in wells these has wells been has 3.203 been 3.203106 ton. × 106 ton. × 4.2. Tight Oil Production in Volume-Fracturing-Treated WellsWells Table4 4 shows shows aa setset ofof wellwell stimulationstimulation resultsresults byby thethe volumevolume fracturingfracturing treatmentstreatments inin thethe ChangChang 7 tight oil reservoir.reservoir. Fractures parameters were obtained through the application of microseismicmicroseismic monitoring technology. SRVSRVf f representsrepresents stimulated stimulated reservoir reservoir vo volumelume by conventional fracturingfracturing treatment, andand SRVvSRVvf f representsrepresents stimulated stimulated reservoir reservoir volume volume by by volume volume fracturing fracturing treatment. treatment. It canIt can be seenbe seen that that the the volume volume fracturing fracturing treatments treatments in the in wells the wells possessed possessed a higher a higher fluid injectionfluid injection rate, a rate, lower a sandlower ratio, sandand ratio, a largerand a reservoirlarger reservoir stimulation stimulation volume volume than the than conventional the conventional fracturing. fracturing. The average The injectionaverage injection rate of volume rate of fracturing volume fracturing in 12 treated in wells12 treated was aboutwells 8.8was m 3about/min, almost8.8 m3/min, four timesalmost that four of thetimes conventional that of the conventional fracturing. The fracturing. sand ratios, The which sand rangedratios, which from 8.5 ranged to 14.3%, from were 8.5 to less 14.3%, than halfwere those less inthan conventional half those in fracturing. conventional The fracturing. volume fracturing The volu treatmentme fracturing in wells treatment formed in favorable wells formed fractures favorable in the formation.fractures in The the averageformation. half-length, The average width, half-length, and height width, of the and fractures height created of the by fractures volume created fracturing by treatmentsvolume fracturing were all largertreatments than those were in all conventional larger than fracturing those in treatments, conventional indicating fracturing an improvement treatments, inindicating the fluid an flow improvement in the fractures. in the Due fluid to flow the proper in the parameterfractures. Due design, to the such proper as large parameter sand and design, fluid injectionsuch as large volume, sand low and sand fluid ratio, injection high volume, injection low rate, sand and ratio, so on, high and injection the appropriate rate, and well so on, operations, and the volumeappropriate fracturing well operations, could lead volume to a larger fracturing fracture could distribution lead to around a larger the fracture treated distribution wells. The volumearound fracturingthe treated treatment wells. The design volume overall fracturing resulted treatment in the greater design SRV overall in the resulted reservoir, in i.e.,the thegreater largest SRV SRV invf thein thereservoir, treated i.e., wells the was largest 4.9 timesSRVvf greaterin the treated than the wells SRV fwas, which 4.9 times also benefits greater the than fluid the flow SRV andf, which the finalalso oilbenefits production. the fluid flow and the final oil production.

Energies 2019, 12, 2419 17 of 22

Table 4. Reservoir stimulation results of volume fracturing treatments in Chang 7.

Field Operation Parameters Fracture Parameters Fracturing Number of Well Injection Fracture 4 3 SRV /SRV Well No. Sand Volume Sand Ratio Total Injected Fracture Fracture SRV [10 m ] vf f Treatment Intervals/Number of Rate Half-Length [m3] [%] Volume [m3] Width [m] Height [m] Perforation Clusters [m3/min] [m] 1 13/26 514.8 9.5 6.2 7475 257 110 69 387.1 2.7 2 13/26 520 9.3 6.3 7800 272 96 78 402.8 2.8 3 11/22 496.1 10.6 6.0 6556 401 38 58 176.8 1.2 4 11/22 438.9 8.5 6.0 7656 326 69 51 229.4 1.6 5 11/22 482.9 10.7 6.0 5896 371 62 52 240.4 1.7 Volume 6 9/44 1146.6 13.8 15.0 9135 386 162 41 515.3 3.6 fracturing 7 8/39 1016 14.3 15.0 10248 336 128 37 314.0 2.2 8 4/11 259.2 11.0 10.0 2148 302 71 68 289.1 2.0 9 4/12 312.4 11.0 9.4 3352 291 68 69 270.3 1.9 10 8/32 475.2 12.9 7.7 4152 337 110 96 711.7 4.9 11 6/24 520.8 12.4 8.0 4680 244 136 38 252 1.8 12 5/21 377.5 13.0 8.0 3910 160 120 48 183.4 1.3 Conventional 13 8/16 184 29.0 2.2 1223 160 90 50 144 1.0 fracturing

SRV—stimulated reservoir volume, SRVvf—stimulated reservoir volume by volume fracturing treatment, SRVf—stimulated reservoir volume by conventional fracturing treatment. Energies 2019, 12, 2419 18 of 22 Energies 2019, 12, x FOR PEER REVIEW 18 of 23

Volume fracturingfracturing is alwaysis always accompanied accompanied by large by fluidlarge injection fluid injection volume, itvolume, also has ait characteristic also has a ofcharacteristic low backflow of low rate. backflow During therate. fracturing During the treatment, fracturing most treatment, of the fracturingmost of the fluid fracturing was retained fluid was in theretained formations, in the formations, which could which increase could the increase formation the formation pressures. pressures. In Chang In 7 Chang reservoir, 7 reservoir, the average the formationaverage formation pressure, pressure,Pi, is 15.8 MPa.Pi, is 15.8 Bai et MPa. al. [35 Bai] investigated et al. [35] investigated the variation the of fracturevariation net of pressure fracture with net thepressure change with of injection the change rate inof formationinjection rate layers in with formation different layers thickness with duringdifferent hydraulic thickness fracturing during treatmenthydraulic infracturing Chang 7 treatment reservoir. in Figure Chang 16 7 summarized reservoir. Figure characteristics 16 summarized of the netcharacteristics pressure variation of the net in formationpressure variation fractures in at diformationfferent injection fractures rates. at different As we can injection see, increasing rates. As the we injection can see, rate increasing can improve the theinjection net pressure rate can in improve the formed the net fractures. pressure in the formed fractures.

Figure 16. VariationVariation of net pressures in formed fractures withwith the change of injection rate in formation layers with didifferentﬀerent thicknessthickness duringduring fracturingfracturing treatments.treatments.

After injecting large volume fracturing fluid, ﬂuid, the average formation pressures, P, in didifferentﬀerent blocks increased.increased. TableTable5 5gives gives the the formation formation pressure pressure data data during during the the volume volume fracturing fracturing treatments treatments in somein some of the of pilotthe areas.pilot Theareas. pressures The pressures were obtained were basedobtained on bothbased the on direct both pressure the direct measurements pressure andmeasurements simulation and results. simulation results.

Table 5. Formation pressures during volume fracturing treatments in Chang 7. Table 5. Formation pressures during volume fracturing treatments in Chang 7. Average Length Fluid Injection Fluid Backflow Fluid Volume Pilot Number Backflow Rate of Horizontal Volume per Well Volume per RetainedFluid in VolumeP/Pi [%] Areas of Wells Average Length Fluid Injection Fluid Backflow [%] Pilot Number Well [m] [m3] Well [m3] BackflowFormation Retained [m3] in P/Pi of Horizontal Volume per Volume per Areas of Wells Rate [%] Formation [%] Jiyuan 173Well 789 [m] Well 5463 [m3] 1672Well [m3] 30.6 3791 119 Heshui 56 976 5805 1623 28.0 4182[m3] 119 JiyuanMaling 173 39 789 1264 9294 5463 3263 1672 35.1 30.6 6031 3791 127 119 Heshui 56 976 5805 1623 28.0 4182 119 MalingIn 2011, six39 horizontal 1264 wells in Jiyuan 9294 pilot areas were 3263 treated by conventional 35.1 6031 fracturing 127with low fluid injection volume and low injection rate. The average oil production rate in the wells was In 2011, six horizontal wells in Jiyuan pilot areas were treated by conventional fracturing with 5.3 ton/day, and the production wells were quickly flooded after a few months. In 2012, 24 horizontal low fluid injection volume and low injection rate. The average oil production rate in the wells was wells in Jiyuan pilot areas were treated by volume fracturing. After the treatment, the average oil 5.3 ton/day, and the production wells were quickly flooded after a few months. In 2012, 24 horizontal production rate in the wells reached to 12 ton/day, twice larger than that of the conventional fracturing wells in Jiyuan pilot areas were treated by volume fracturing. After the treatment, the average oil treatment. After 2012, a number of horizontal wells in Jiyuan, Heshui, and Maling were treated with production rate in the wells reached to 12 ton/day, twice larger than that of the conventional volume fracturing. The average daily oil rate after one-year production in the treated wells were still fracturing treatment. After 2012, a number of horizontal wells in Jiyuan, Heshui, and Maling were higher than eight tons, which indicating a slowly decrease in oil productivity. Table6 shows a summary treated with volume fracturing. The average daily oil rate after one-year production in the treated of the decline rate of oil production in conventional fracturing and volume fracturing horizontal wells. wells were still higher than eight tons, which indicating a slowly decrease in oil productivity. Table As we can see, after one-year production, the average oil decline rate in volume fracturing wells is 6 shows a summary of the decline rate of oil production in conventional fracturing and volume lower than that in conventional fracturing wells. Figure 17 shows a typical comparison of the one-year fracturing horizontal wells. As we can see, after one-year production, the average oil decline rate in tight oil production results in two horizontal wells treated by volume fracturing and conventional volume fracturing wells is lower than that in conventional fracturing wells. Figure 17 shows a typical fracturing in the Chang 7 reservoir. As can be seen, the volume fracturing treatment in horizontal wells comparison of the one-year tight oil production results in two horizontal wells treated by volume can significantly increase tight oil production. In the first month, the average daily oil production of the fracturing and conventional fracturing in the Chang 7 reservoir. As can be seen, the volume fracturing treatment in horizontal wells can significantly increase tight oil production. In the first month, the average daily oil production of the volume-fracturing-treated wells was more than twice that of the

Energies 2019, 12, 2419 19 of 22 volume-fracturing-treated wells was more than twice that of the conventional-fracturing-treated wells. The daily oil production decreased with the production time in both types of treated wells. Compared with conventional fracturing, the tight oil production in the wells treated by volume fracturing had a slower decreasing rate. By the end of one year, the daily oil production of the volume-fracturing-treated wells had declined from 12.3 to 7.6 ton/day, about a 38% decrease. The daily oil production of the conventional-fracturing-treated wells had a more remarkable decrease of 55%, from 5.15 to 2.3 ton/day. The one-year-accumulated tight oil production of the volume-fracturing-treated wells was as high as 3500 t, about 2.3 times larger than that of the conventional-fracturing-treated wells, as shown in FigureEnergies 201917b., 12, x FOR PEER REVIEW 19 of 23

conventional-fracturing-treatedTable 6. Decline of oil production wells. in conventional The daily o fracturingil production and volumedecreased fracturing with the horizontal production wells. time in both types of treated wells. Compared with conventional fracturing, the tight oil production in the Injection Fluid Injection One-year oil Fracturing Number Well Length Sand Volume Pilot Areas Rate Volume per Well Production wellsTreatment treated byof volume Wells fracturing had a [m]slower decreasingper Well [m3] rate. By the end of one year, the daily oil [m3/min] [m3] Decline Rate [%] production of the volume-fracturing-treated wells had declined from 12.3 to 7.6 ton/day, about a 38% Conventional 5 Jiyuan <1000 174.2 2.1 974.2 57.3 decrease.fracturing The daily oil production of the conventional-fracturing-treated wells had a more Maling, Heshui, remarkable decrease37 of 55%, from 5.15 to1500 2.3 ton/day. 763The one-year-accumulated 7.1 12511 tight oil production 34.1 Volume Jiyuan of thefracturing volume-fracturing-treated13 Heshui, Jiyuan wells 1000–1400was as high as 715 3500 t, about 6.8 2.3 times 8791 larger than that 40.5 of the conventional-fracturing-treated2 Jiyuan wells, as< 1000shown in Figure 494.8 17b. 6.0 5241 37.8

15 4000 Conventional fracturing Conventional fracturing 3500 12 Volume fracturing Volume fracturing 3000

9 2500 2000

6 1500

1000 Oil productionOil /ton/day 3

Accumulated oil productionoilAccumulated /ton 500

0 0 012345678910111213 0 1 2 3 4 5 6 7 8 9 10 11 12 13 Time /M Time /M

(a) (b)

Figure 17.17. One-year tight oil production results in wellswells after volume fracturing treatment and in wellswells after conventional fracturing fracturing treatment: treatment: (a ()a Daily) Daily tight tight oil oil production, production, (b) ( baccumulated) accumulated tight tight oil oilproduction. production.

5. ConclusionsTable 6. Decline of oil production in conventional fracturing and volume fracturing horizontal wells.

In this work, the performance of the volume fracturingSand treatment to enhanceFluid tight oilOne-year recovery oil in Well Injection Fracturing Number Volume Injection Production the Chang 7 tight oil reservoir,Pilot the Areas Changqing Length oilfield, was studiedRate through experimental investigation Treatment of Wells per Well Volume per Decline Rate and field-scale practice. Conclusions drawn[m] from this study are[m as3/min] follows: [m3] Well [m3] [%] Conventional(1) The Chang 7 tight oil reservoir in the Changqing oilfield possesses a wide distribution of 5 Jiyuan <1000 174.2 2.1 974.2 57.3 hydrocarbonfracturing source rocks that are rich in organic matter. The tight oil generation intensity of the Chang 7 reservoir is estimatedMaling, to be 495 104 km2, and the total amount of generated hydrocarbons 37 × 1500 763 7.1 12511 34.1 can beVolume as high as 2473.08 Heshui,108 ton. Jiyuan The favorable hydrocarbon source rocks in the Chang 7 reservoir fracturing 13 ×Heshui, Jiyuan 1000–1400 715 6.8 8791 40.5 ensures a high capacity2 of tightJiyuan oil generation<1000 and accumulation.494.8 6.0 5241 37.8 (2) Core analysis from the pilot areas of the Chang 7 tight oil reservoir indicates poor physical properties5. Conclusions of the reservoir formations. The average porosity of the formations is around 8–9%, and average permeability is about 0.11–0.14 mD. Due to the low porosity, low permeability, and poor poreIn connectivity, this work, itthe is diperformancefficult to recover of the the volume tight oilfrac fromturing formations treatment without to enhance fracturing tight oil treatment. recovery in the Chang 7 tight oil reservoir, the Changqing oilfield, was studied through experimental investigation and field-scale practice. Conclusions drawn from this study are as follows: (1) The Chang 7 tight oil reservoir in the Changqing oilfield possesses a wide distribution of hydrocarbon source rocks that are rich in organic matter. The tight oil generation intensity of the Chang 7 reservoir is estimated to be 495 × 104 km2, and the total amount of generated hydrocarbons can be as high as 2473.08 × 108 ton. The favorable hydrocarbon source rocks in the Chang 7 reservoir ensures a high capacity of tight oil generation and accumulation. (2) Core analysis from the pilot areas of the Chang 7 tight oil reservoir indicates poor physical properties of the reservoir formations. The average porosity of the formations is around 8–9%, and average permeability is about 0.11–0.14 mD. Due to the low porosity, low permeability, and poor pore connectivity, it is difficult to recover the tight oil from formations without fracturing treatment. (3) Fractures developed in tight cores can significantly improve fluid flow conductivity. The increased flowability is crucial to oil recovery improvement in tight oil reservoirs. However, fractures

Energies 2019, 12, 2419 20 of 22

(3) Fractures developed in tight cores can significantly improve fluid flow conductivity. The increased flowability is crucial to oil recovery improvement in tight oil reservoirs. However, fractures with permeabilities too high above those of the matrix may lead to a severe water channeling problem in the formation. The injected displacing water mainly flows through the fractures with overly high permeability, leaving the tight oil in the matrix almost un-swept. Therefore, when applying fracturing treatment to improve the oil recovery in tight oil reservoirs, developing fractures with appropriate permeabilities, which increases the flowability and decreases the water channeling possibility, is important for field operators. (4) The imbibition effect plays an important role in tight oil recovery enhancement in low-permeability porous media. Core experiments show that developed fractures can remarkably increase the imbibition rate in tight cores, as the contact area between the fracture and the matrix is significantly increased by the formed fractures. In some fractured Chang 7 tight cores, the movable oil recovery improved by the water imbibition effect can be as high as 51.32%. The imbibition effect in tight cores increases with the decrease in core permeability. (5) A field-scale application of the volume fracturing treatment exhibits a prominent increase in tight oil production in the Chang 7 reservoir. Compared with the conventional fracturing treatment, volume fracturing can produce a larger number of fractures with more favorable properties to improve the flow conductivity. Moreover, volume fracturing treatment in horizontal wells resulted in a much larger stimulated reservoir volume around the treated wells, which can be 4.9 times greater than that of conventional volume fracturing.

Author Contributions: Conceptualization, J.W. and L.Y.; methodology, C.W.; validation, J.W., L.Y. and C.W.; formal analysis, L.Y.; investigation, L.Y.; resources, C.W. and D.C.; data curation, C.W. and D.C.; writing—original draft preparation, L.Y.; writing—review and editing, J.W.; supervision, J.W.; project administration, J.W. and C.W.; funding acquisition, J.W. Funding: This research was funded by National Natural Science Foundation of China (51804283), the Fundamental Research Funds for the Central Universities (CUG170652) and the National Natural Science Foundation of Hubei Province (2017CFB345). Acknowledgments: The authors would like to acknowledge the China University of Geosciences for supporting this research. We also acknowledge the National Natural Science Foundation of China (51804283), the Fundamental Research Funds for the Central Universities (CUG170652) and the National Natural Science Foundation of Hubei Province (2017CFB345) for providing research funding. Conﬂicts of Interest: The authors declare no conﬂict of interest.

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