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Characterization and prevention of formation damage for fractured carbonate reservoir formations with low permeability

Characterization and prevention of formation damage for fractured carbonate reservoir formations... permeability were determined as the main potential damage mechanisms during drilling and completion operations in the ancient buried hill Ordovician reservoirs in the Tarim Basin. Geological structure, lithology, porosity, permeability and mineral components all affect the potential for formation damage. The experimental results showed that the permeability loss was 83.8%-98.6% caused by stress sensitivity, and was 27.9%-48.1% caused by water blocking. Based on the experimental results, several main conclusions concerning stress sensitivity can be drawn as follows: the lower the core permeability and the smaller the core fracture width, the higher the stress sensitivity. Also, stress sensitivity results in lag effect for both permeability recovery and fracture closure. Aimed at the mechanisms of formation damage, a modified low-damage mixed metal hydroxide (MMH) drilling fluid system was developed, which was mainly composed of low-fluorescence shale control agent, filtration control agent, low- fl uorescence lubricant and surfactant. The results of experimental evaluation and fi eld test showed that the newly-developed drilling fluid and engineering techniques provided could dramatically increase the return permeability (over 85%) of core samples. This drilling fluid had such advantages as good rheological and lubricating properties, high temperature stability, and low fi ltration rate (API fi ltration less than 5 ml after aging at 120 for 4 hours). Therefore, fractured carbonate formations with low permeability could be protected effectively when drilling with the newly-developed drilling fluid. Meanwhile, fi eld test showed that both penetration rate and bore stability were improved and the soaking time of the drilling fl uid with formation was sharply shortened, indicating that the modifi ed MMH drilling fl uid could meet the requirements of drilling engineering and geology. Fractured carbonate formations with low permeability, stress sensitivity, water blocking, Key words: MMH drilling fl uids, formation damage control from 25% to 60% (Zhang et al, 2006), and the loss caused 1 Introduction by water-blocking ranges from 70% to 90% (Bennion et al, Micro-fractured carbonate reservoirs with low 1999). Much higher permeability loss can result from stress permeability are commonly characterized by high clay sensitivity and can be observed from experimental results for content, high water saturation, complicated pore structures, targeted low-permeability fractured formations. This paper high sensitivity to fresh water, high capillary pressure, severe introduces the damage characteristics of tight carbonate water blocking, severe anisotropy and high flow resistance, reservoir formations with low permeability in the Tarim and have abundant natural micro-fractures. During drilling Basin, and presents an approach to preventing formation and production operations, stress sensitivity damage can damage from stress sensitivity and water blocking during be easily induced by a change in effective stress. Water drilling and completion operations. sensitivity and water-blocking can also be easily caused by various invading fluids (Bennion et al, 2000; Erwom et al, 2 Geological characteristics of target 2003; Lin, et al, 2003; Ren et al, 2004). Furthermore, the formations damage to permeability of formations is largely irreversible. Experimental results show that permeability loss caused by The Ordovician reservoirs in the Tarim Basin are the type stress sensitivity can never be ignored. It commonly ranges of carbonate fracture-porosity dual-permeability reservoirs, and are mainly controlled by geological conditions, development of fractures and dissolution cavities. The *Corresponding author. email: yanjienian@sina.com target formation mainly consists of grayish-brown silt-sized Received April 7, 2008 Pet.Sci.(2008)5:326-333 327 327 crystalline limestone and micrite, with a few calcarenites, until irreducible water saturation, S , was established. The wi and dolostones. The permeability of the target formation is value of S is generally related to rock property, formation wi -3 2 (0.01-36.38)×10 μm . The effective porosity ranges from temperature and pressure. Afterwards, the correlation between 0.11% to 6.76%. The permeability and porosity of the target the permeability to oil and displacement pressure could be formation are extremely low, and secondary corrosion holes, determined. For all the tests, the displacement rate was 1 ml/ cavities and fractures form the main storage space rather min and the confi ning pressure was controlled at 1-25 MPa. 3.1.2 Impact of stress on core permeability and fracture width than the carboncete matrix. The average width of formation fractures is generally less than 10 μm. Clay minerals are Based on above-mentioned test procedure, correlation mainly augenetic, distributed in holes and cavities and between effective stress and permeability or fracture width the total content is commonly less than 5%. Among clay of cores taken from five wells in the target formation was minerals, illite accounts for 33%-70%, with an average value measured and shown in Fig. 1. of 58.5%; illite/smectite (I/S) accounts for 14%-33%, with an It can be seen from Fig.1 that both permeability and average value of 25.6%; kaolinite accounts for 0-27%, with fracture width initially declined quickly with increasing an average value of 11.3%; and chlorite accounts for 0-34%, effective stress. When the effective stress increased to over with an average value of 10.1%. 10 MPa, the decline rate tended to slow down. When the effective stress was over 14 MPa, the permeability loss ranged 3 Main mechanisms of formation damage from 83.8% to 98.6%, with an average value of 93.38%; the fracture width decreased by 71.1% -88.5%, with an average Sensitivity tests for core samples taken from the target value of 76.5%. formation show that the formations are characterized by The low-permeability cores taken from the fractured weak sensitivity to fl ow rate, weak to medium sensitivity to formation usually have relatively stronger sensitivity to stress, water and weak sensitivity to salt, and strong sensitivity to which results in the alteration of the original relations of load- acid. More attention has been paid to sensitivity to stress and bearing frame particles, fractures and pore-throat structures. water-blocking, which is discussed in detail below. The fractures and pore throats tend to close down with increasing effective stress. Consequently, the reduction in 3.1 Experimental evaluation of sensitivity to stress the width of fl uid fl ow channels will lead to a decrease in the Sensitivity to stress can be defined as the impact of permeability of the cores. However, when stress increases to effective stress (the differential between overburden a specifi c value, because relatively low values of permeability pressure and pore pressure) on the permeability of the and fracture width are reached, core permeability and fracture target formation, which is mainly caused by compression width change only slightly with further increasing stress, and closure of capillaries and pores. Unlike mid- and high- therefore stress sensitivity tends to weaken. permeability formations, fluid flow in low-permeability 3.1.3 Impact of effective stress on core porosity formations is affected by the slippage effect, therefore various Double cycles of stress loading/unloading experiments forms of fl ow exist. The strong sensitivity to stress is mainly were performed. The first cycle of stress loading/unloading caused by non-linear gas flow in porous media. The lower experiment referred to the values of porosity that were the formation permeability, especially in fracture-porosity measured at the confining pressure of 3, 5, 7, 10, 20 and channels, the more remarkable the effect on stress sensitivity 30 MPa, respectively. Then stress was gradually unloaded (Luo et al, 2005). Sensitivity to stress is usually related to afterwards a second cycle of stress experiment was performed formation permeability, water saturation, confi ning pressure in the same way. The correlation of core porosity and and displacement pressure. effective stress was measured, and it was shown that cores 3.1.1 Preparation of core samples and test procedure porosity reduced slightly with increasing effective stress. Natural outcrop core samples taken from the Ordovician The reduction in the core porosity was less than 5% during fractured formation were drilled to the desired size and the first stress loading experiment, and the reduction was served as core groundmass of man-made fractured cores. The less than 2% during the second stress loading experiment. cores were then split into two parts along the axial direction It is considered that core porosity mainly depends on what by applying pressure, and fine particles on the fracture the core volume is. Particles in the core deformed slightly surface was blown off with N . Finally, the two sections were after being compacted during the rock-forming process. cemented by resin. The reason why the alteration of core porosity in the first The experiments were performed by using JHMF-II cycle of loading/unloading experiment is higher than that fl owing apparatus designed for cores to simulate in situ stress in the second cycle is as below: There mainly exist double state of formations. The experimental procedure adopted was actions, which are compaction and compression, chiefly as follows: 1) Firstly, the core size was measured, the dry core compaction during the fi rst cycle of stress loading/unloading sample was weighted and N permeability was measured. experiment, therefore alteration of core porosity is relatively 2) The green core was weighed after evacuation saturated high. However, alteration of core porosity becomes less in the with simulated formation brine, and then the porosity of second cycle of loading/unloading experiment due to the end cores could be calculated. 3) The permeability to brine could of compaction and chiefl y compression. All in all, it can be be obtained after the core was set in the test-apparatus and considered that alteration of effective stress can do little harm displaced with brine until the displacing pressure was kept to core porosity. constant. 4) The core was then displaced with kerosene 328 Pet.Sci.(2008)5:326-333 6 12 50 35 50 Permeability Permeability P ermeabilit y 5 10 Fracture width Fracture width 40 40 Fract ure widt h 4 8 30 30 3 6 2 4 10 10 1 2 0 0 0 0 0 0 2 4 6 8 1012141618 0 2 4 6 8 101214 1618 0 2 4 6 8 1012 141618 Effect ive st ress, MP a Effect ive st ress, MP a Effective stress, MPa (a) Core No. A35 (b) Core No. B17 (c) Core No. B36 45 30 10 16 Permeability Permeability Fracture width Fracture width 30 20 15 10 10 4 0 0 0 0 02 46 8 10 12 14 16 18 02 4 6 8 10 12 14 16 18 Effective stress, MPa Effective stress, MPa (d) Core No. C21 (e) Core No. C37 Fig. 1 Impact of effective stress on core permeability and fracture width 3.1.4 Lag effect of sensitivity to effective stress During practical oil field production, every alteration of production parameters, such as intermittent well operating, adjustment of production pressure differential, etc. can inevitably result in alteration of formation pore structure, furthermore, formation permeability and fracture width are seriously damaged. The impact of stress sensitivity on core 30 permeability during stress loading/unloading was evaluated, 0246 8 10 12 14 16 18 20 22 24 26 as shown in Fig. 2. Effect ive st ress, MP a The following phenomenon can be seen from Fig. 2: (a) Core No. B18 1) During effective stress loading, the higher the stress was applied, the more seriously the core permeability was damaged, and hence the higher the stress sensitivity was. However, there exists a stress sensitivity point. When effective stress is higher than such a value, effective stress 18 has relatively less damage to core permeability, hence, stress sensitivity becomes obviously weaker. 2) The stress sensitivity point in the process of stress unloading is lower than that in the process of stress loading, namely, there exists an obvious lag effect of stress sensitivity, and with the increase of cycles of stress loading/unloading, the lag effect 0 2 4 6 8 10 1214 1618 2022 2426 becomes weaker, but once being damaged, permeability can Effective stress, MPa not recover to its original value. This can be caused by the (b) Core No. C36 deformation of the fracture surface of the dual-permeability formation, which results from the continuous effective stress. Impact of stress sensitivity on core permeability during several Fig. 2 This is the so-called lag effect of fracture closure. cycles of loading and unloading -3 2 Permeability, 10 μm -3 2 Permeability, 10 μm Fracture width, μm -3 2 Permeability, 10 μm Fracture width, μm -3 2 -3 2 Permeability, 10 μm Permeability, 10 μm -3 2 Permeability, 10 μm Fracture width, μm -3 2 Permeability, 10 μm Fracture width, μm Fracture width, μm Pet.Sci.(2008)5:326-333 329 more severe water blocking effect. As can be known from the 3.2 Evaluation of water-blocking damage capillary pressure equation and Bennion’s equation (Bennion As pore throats in the low-permeability formations are et al, 1995) of predicting water blocking effect that water extremely small, water blocking is commonly considered blocking damage is mainly related to such parameters as K , one of the main damaging factors. Hence, evaluation of S , and (oil/water interfacial tension) and other factors wi water-blocking damage was also undertaken. The testing such as lithology, type and content of cementing substance, procedure was as follows: Core samples were from taken the pore structure and properties of invasion fl uids, etc. Hence, it target formation, confi ning pressure during entire experiment can never be ignored. Theoretically, 1) In order to minimize remained above stress sensitivity point to reduce the stress capillary force, various types of treating agents and measures sensitivity effect. Firstly, N permeability was measured can be used to reduce surface tension and alter original by using dry core, and the cores were vacuum saturated by formation water wettability to nearly intermediate wettability, standard brine, then the core was displaced with kerosene to namely is approximately 90° (basing on equation 1). 2) leaving irreducible water remaining in the core, and then core Meanwhile, to improve permeability in the near wellbore permeability K was measured by displacing with kerosene op zone by adopting some operations such as acidizing and in the forward direction after it was contaminated by brine in fracturing, etc, water-blocking damage can also be effectively the reverse direction. Finally the rate of permeability damage minimized or eliminated. R was calculated. All displacing tests were performed by using the JHMD-II intelligent core fl ooding apparatus. (1) Table 1 shows that the damage rate R induced by water blocking is relatively higher, ranging from 27.9% to where p is capillary force, is contact angle, r is radius of 48.1%. The lower the original water saturation S and N wi 2 pore throat or contracted capillary. permeability K , the higher the damage rate R , indicating a s Evaluation results of water-blocking damage for cores from fractured carbonate formation Table 1 -3 2 Core permeability, 10 μm Core Porosity Original water saturation N permeability Core damage rate -3 2 , % number S , % K , 10 μm R wi a s Before fl uid blocking After fl uid blocking 1 3.2 14.2 18.0 10.6 5.5 48.1 2 4.5 15.2 7.3 3.4 1.8 47.0 3 4.7 23.6 25.3 14.7 10.6 27.9 fully recovered after the stress is unloaded. This is the so- 4 Protective techniques during drilling and called lag effect of stress, or lag effect of fracture closure. 2) production operations The pore structure of the target formation complicates the stress action. Pore space is extremely small, but the change 4.1 Mechanism of sensitivity to stress in pore space resulting from stress change is relatively Some characteristics concerning sensitivity to stress can greater. Hence, when the stress applied is lower than stress be summarized as below from above mentioned experimental sensitivity point, stress sensitivity is generally very high. 3) results. 1) Tested cores have obvious sensitivity to stress, the Pore throats and pore channels in the core are compressed by permeability of cores are drastically reduced with the increase stress. Especially, when effective stress is lower than stress in effective stress. 2) There exists a stress sensitivity point, sensitivity point, fluid flow capacity declines because pore above which stress sensitivity becomes weaker. 3) During the throats and pore channels are compressed by stress. Namely, decrease in stress, there exists an obvious lag effect of stress the measured core permeability declines. However, when sensitivity or fracture closure, and the more times the stress pore throats and pore channels are compressed to a specifi c was applied, the weaker the lag effect of stress sensitivity extent, namely reaching the stress sensitivity point, the extent or fracture closure. 4) Cores with low permeability or small or tendency of being compressed becomes relatively smaller, fracture width can not fully recover their permeability values and correspondingly the decline of core permeability becomes after stress was applied. All tested cores failed to recover smaller. 4) Various formations have different extents of stress their original permeabilities. The following reasons can sensitivity, which mainly depends on compaction effect, type probably explain the stress sensitivity of low-permeability and content of rock mineral composition, packing substances fractured formation. 1) There are abundant micro-fractures in fractures and their types and contents (Ostensen, 1986; in the rock. Micro-fractures can easily be closed after stress Ruan and Wang, 2002). is applied. Furthermore, these closed fractures can not be 330 Pet.Sci.(2008)5:326-333 4.2 Prevention of damage induced by sensitivity to In the MMH drilling fluid system, bentonite can react stress during drilling and production operations with the MMH particles and water to form a special spatial network structure (Zhang et al, 2000). The size of this For a given formation, the value of effective stress mainly network structure formed is usually bigger than that of depends on pore pressure. The higher the pore pressure, pore throat and micro-fracture width. Consequently, clay the smaller the effective stress. Therefore, some necessary particles invasive depth is restricted. The flexible plugging preventive measures should be taken into account. For at pore throats formed by compound network structure can example, a reasonable range of negative pressure for under- be deformed and later effectively drained out of formation. balanced drilling and tripping operation should be kept so as Unlike solid particle plugging, which needs high drainage to maintain a higher pore pressure, and effectively prevent pressure and in which possibly the blocks at the pore throats formation damage caused by overly negative pressure, partial can hardly be drained out, organic MMH particles can be excessive lower pore flow pressure or overly big surge easily dissolved by oil and acid, which can further improve pressure resulting from tripping operation. The sensitivity to oil/gas phase permeability by means of the flowback of stress can lead to even more serious damage in the process oil and acidizing treatments, etc. At the same time, MMH of production. Hence, it is necessary to keep a reasonable drilling fl uid can effectively inhibit clay hydration, swelling, production pressure differential and possibly avoide and has strong resistance to salt sensitivity, so it has unique unnecessary well shut-in to effectively prevent damage performance for fractured carbonate reservoir protection. caused by sensitivity to stress. 5.3 Formulations and properties of drilling fl uids 5 Formulations and properties of low- Considering that all kinds of treating agents should meet damage drilling fluids used in fractured the requirements of formation lithology, physical properties, carbonate formations sensitivity characteristics and well logging, it is necessary to select shale-controlling agents with low-fluorescence, Low-damage drilling fluids are generally composed of fi ltration control agents, lubricants and surfactants properly, fracture-packing agents (such as asbestos fiber and sized so as to improve the performance of the MMH drilling fl uids. calcium carbonate), soft particles of oil-soluble resin and On the basis of experiments, a typical formulation of the some strongly inhibitive agents. In addition, a special film- MMH drilling fluid is listed as below: 4% bentonite + 7% forming agent can be used to plug up the fractures with MMH + 2% SMP-1 + 2% WFT-666 + 3% CHSP-1 + 3% various widths very quickly and effectively. This drilling fl uid DFD-140 + 0.2% SP-2 + 2% MHR86D (lubricant) + 0.2% system is characterized by a high stress bearing capacity, low ABSN + 4% CaCO . drainage pressure and high permeability recovery, etc (Li, 3 For some formations, an alternative drilling fl uid system 2001; Lu et al, 2004; Zhang and Yan, 2004; Zhao et al, 2007). can also be used to enhance the plugging effectiveness 5.1 Requirements of low-damage drilling fl uids further. Its formulation is as below: 4% bentonite + 7% MMH + 2% SMP-1 + 2% WFT-666 + 3% CHSP-1 + 3% DFD-140 Under-balanced or near-balanced drilling technology has + 0.2% SP-2 + 2% MHR-86D + 0.2% ABSN + 2% QCX-1 + been widely applied to penetrating targeted formations in 1.5% DYY-1 (an oil-soluble resin) + 4% CaCO . the Tarim Basin. According to the main damage mechanisms 5.3.1 Evaluation of rheological properties for the Ordovician fractured carbonate formations, the basic Experimental results in Table 2 show that all the technical approaches to designing a low-damage drilling rheological parameters are rational. Meanwhile, the API fluid are as follows: 1) All kinds of treating agents used in fi ltration rate is less than 5 ml. drilling fl uids should be compatible with formation rock and 5.3.2 Compatibility between drilling fl uids and formation rocks brine so as to minimize formation damage during drilling The test sample was prepared by mixing 350 ml of low- operations; 2) Efficient filtration control agents should be damage drilling fluid with 40 grams of dry drilled cuttings. optimized to form quickly high-quality mud cake so as The drilled cuttings were dried at 100 ºC for 4 hours and then to reduce invasion depth of drilling fluids under a given screened to 10 mesh. According to the differential weights positive pressure differential; 3) Effi cient surfactants should of cores before and after aging, compatibility between the be optimized so as to reduce oil/water interfacial tension, drilling fluid and formation rock can be evaluated. The and minimize formation damage induced by water-blocking; experimental results are shown in Table 3. It can be found that 4) Maintaining a reasonable density of drilling fluids and the drilling cuttings recovery was over 99%, and no obvious controlling an appropriate range of surge pressure, so as to change happened in color and shape after aging, illustrating prevent formation damage induced by sensitivity to stress. an excellent compatibility. 5.2 Characteristics of low-damage MMH drilling 5.3.3 Compatibility between drilling fl uids and formation brine fl uid The low-damage drilling fl uids were mixed with formation brine in a proportion of 1:2 using an 8000 r/min high-speed The MMH electropositive colloid drilling fluid has mixer. After aging for 1 hour, no deposition and cloudiness formation protective functions such as reducing clay particle were observed, illustrating that drilling fl uids are compatible invasion, inhibiting hydration and swelling, high drainage with formation brine. rate and high permeability recovery, etc. Pet.Sci.(2008)5:326-333 331 5.3.4 Measurements of returned permeability for cores kerosene at a confi ning pressure of 4 MPa and a displacement contaminated with drilling fl uids rate of 1.0 ml/min; 3) Under the same conditions, the The JHMD-II core flooding test apparatus was used to permeability, K ', was measured after being contaminated measure the return permeability. The test procedures are as with low-damage drilling fl uids in the opposite direction, the follows: 1) The man-made fractured core, by mixing cores return permeability, which is herein defined as the percent taken from Ordovician fractured carbonate formations with permeability that is recovered, was calculated. : : : filling substances (in a proportion of smectite illite CaCO The test results are listed in Table 4. It can be seen that the : : : formation brine = 1 10 30 90) was 2.54 cm in-diameter return permeability of two core samples contaminated with and 2.75 cm in length. The man-made core was saturated the MMH drilling fluid are all over 87%, indicating good with simulated formation brine after being vacuum dried; protective effect. 2) The permeability, K was measured by displacment with S, Table 2 Rheological properties of low-damage drilling fl uids Density Apparent viscosity Plastic viscosity Yield point Gel strength API fi ltration loss Experimental conditions pH value , g/cm AV, mPa·s PV, mPa·s YP, Pa 10"/10', Pa ml Before aging 1.14 48.5 43.0 5.5 2/15 4 8.5 1) After aging 1.14 30.0 25.0 5.0 1/5 5 9.0 Notes: 1) Aging at 120 ºC for 16 hours Compatibility between low-damage drilling fl uid and formation cores Table 3 Weight of core, g Core Recovery percent number % Before being contaminated After being contaminated 1 39.76 39.56 99.5 2 40.15 39.86 99.3 Average 99.4 Table 4 Return permeability of cores contaminated with low-damage drilling fl uids Core Initial permeability Permeability after being exposed to Return permeability -3 2 -3 2 number K , 10 μm drilling fl uid K ', 10 μm % 1 5.36 4.68 87.3 2 7.12 6.29 88.3 Average 87.8 measured and shown in Table 5. The return permeability of 5.4 Field application cores contaminated with the mud were over 85% (Table 6), The modified low-damage MMH drilling fluid was used indicating only a slight extent of damage measured. for drilling the target formation in Well LG-6. This was a The results of fi eld tests show that this low-damage MMH high-slope directional wildcat well located in the Tarim Basin. drilling fl uid had good rheological and lubricating properties, The hole inclination angle was 62.4°-69.7°. The penetration as well as low filtration rates during drilling the target depth was 5,471-5,890 m. The coefficient of formation formation. The friction resistance during tripping operation pressure was 1.12 and formation temperature was 120 ºC. was only 2-3 tons. The borehole was regular and no collapse The rheological parameters of the field mud were happened. The main measures adopted during drilling 332 Pet.Sci.(2008)5:326-333 operations included controlling concentration of ABSN not controlling reasonable density of drilling fluid to minimize less than 0.2%; reinforcing solids control, cleaning out useless stress sensitivity caused by great positive differential pressure solid particles as much as possible, keeping the proportion and reducing drilling duration as much as possible, etc. between drilling cuttings and bentonite less than 3:1, Table 5 Rheological properties of fi eld mud (120 ºC/16h) Sticking Flow Consistency Mud μ AV PV YP G10 /10' API fi ltrdtion loss HTHP fi ltrdtion loss coeffi cient behavior index pH value types s mPa·s mPa·s Pa Pa ml/mm ml/mm g/cm K index n K, Pa·s 1 1.15 51 31.5 24.0 7.5 3.5/8 4.5/0.5 9.8/1.0 0.02 0.69 0.27 8.5 2 1.15 50 32.0 24.5 7.5 3.0/8 4.5/0.5 9.5/1.0 0.02 0.68 0.26 9.0 Table 6 Return permeabilities of core samples from Well LG-1 Initial permeability Core Permeability after being exposed to drilling fl uid Return permeability -3 2 -3 2 number K , 10 μm K ', 10 μm % s s 3 9.38 8.14 86.8 4 8.41 7.20 85.6 Average 86.2 Notes: The core samples were taken at a depth of 5585 m 6 Conclusions due to its network structure formed by clay particles, water molecules and MMH colloid particles. Therefore, the 1) The main storage space in fractured carbonate modifi ed low-damage MMH drilling fl uid could be used for formation with low-permeability includes micro-pores and protecting fractured carbonate reservoirs during drilling. micro-fractures. The sensitivities to effective stress and water blocking are determined as the two major damage factors. Acknowledgements 2) Experimental results showed that the permeability loss caused by increasing effective stress ranged from 83.8% to The authors gratefully acknowledge Project of the 98.6%, indicating quite a strong sensitivity to stress, while National Natural Science Foundation of China (No. the permeability loss caused by water blocking ranged from 50574061) for the partial support of this work. 27.9% to 48.1%. References 3) The sensitivity to stress is mainly related to the characteristics of fractures and the structure of pores in Ben nion D B, Thomas F B, Bietz R F, et al. Water and hydrocarbon formations, as well as the value of the effective stress applied. phase trapping in porous media. CIM paper. 1995 The main factors affecting water blocking include rock Ben nion D B, Thomas F B, Bietz R F, et al. Remediation of water and permeability, initial water saturation and oil/water interfacial hydrocarbon phase trapping problems in low permeability gas tension, as well as other factors such as lithology of formation reservoirs. JCPT. 1999. 38(8): 39-48 and properties of invading fl uids. Ben nion D B, Thomas F B and Ma T. Formation damage processes reducing productivity of low permeability gas reservoirs. 2000. SPE 4) The modified low-damage MMH drilling/completion paper 60325 fluid not only had excellent compatibility with rock and Erw om M D, Riersom C R and Bennion D B. Brine imbibition damage brine of the target formations, but also had good rheological in the Colville River Field, Alaska. 2003. SPE paper 84320 properties, low filtration rate and high return permeability. Li D F. Damage evaluation of drilling/completion fluids system Field applications showed smaller friction coeffi cient during to carbonate rock fractured reservoir. Drilling & Production tripping operation, regular boreholes and absence of collapse. Technology. 2001. 24(5): 85-87 (in Chinese) 5) The low-damage MMH drilling fluid is multi- Lin G R, Shao C G, Xu Z F, et al. Fluid damage and solution method functional, minimizing invasion depth of solid particles, study of low permeability gas reservoir. Petroleum Exploration and effectively inhibiting clay hydration and swelling, reducing Development. 2003. 30(6): 117-118 (in Chinese) salt-sensitivity, high drainage rate and high permeability Lu H, Wu X H and Qu L M. Studies on using polyols in water base Pet.Sci.(2008)5:326-333 333 drilling fluids for fissured carbonatestone reservoirs. Oilfield Zha ng C G, Xu T T and Hou W G. Mixed metal layered hydroxide Chemistry. 2004. 21(3): 205-207 (in Chinese) compound drilling fluid. Beijing: Petroleum Industry Press. Luo R L, Cheng L S, Peng J C et al. The relationship between stress- 2000. 52-56 (in Chinese) sensitivity permeability and starting pressure gradient of reservoir. Zha ng J B and Yan J N. New theory and method for optimizing the Journal of Southwest Petroleum Institute. 2005. 27(3): 20-22 (in particle size distribution of bridging agents in drilling fluids. Chinese) Acta Petrolei Sinica. 2004. 25(4): 88-91 (in Chinese) Ost ensen R W. The effect of stress dependent permeability on gas Zha ng Q, Du J F, Cui L C, et al. Study on stress sensitivity of production and well testing. SPE Formation Evaluation. 1986. 1(3): the reservoir rock in Sulige gas oilfeld. Drilling Fluid and 227-235 (SPE paper 11220) Completion Fluid. 2006. 23(5): 29-30(in Chinese) Ren X J, Zhang N S, Zhang X F, et al. Damage of residual water on Zha o J Z, Xue Y Z and Li G R. Formation damage control for low- permeability of tight gas reservoir. Natural Gas Industry. 2004. permeability reservoir during drilling operation in Shengli 24(11): 106-108 (in Chinese) Oilfield. Journal of China University of Petroleum (Edition of Rua n M and Wang L G. Low permeability oilfield development Natural Science). 2007. 31(3): 148-151 (in Chinese) and pressure-sensitive effect. Acta Petrolei Sinica. 2002. (5): 73-76 (in Chinese) (Edited by Sun Yanhua) http://www.deepdyve.com/assets/images/DeepDyve-Logo-lg.png Petroleum Science Springer Journals

Characterization and prevention of formation damage for fractured carbonate reservoir formations with low permeability

Shu, Yong; Yan, Jienian
Petroleum Science , Volume 5 (4) – Nov 21, 2008
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Publisher
Springer Journals
Copyright
Copyright © 2008 by China University of Petroleum (Beijing) and Springer-Verlag GmbH
Subject
Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Economics
ISSN
1672-5107
eISSN
1995-8226
DOI
10.1007/s12182-008-0055-8
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Abstract

permeability were determined as the main potential damage mechanisms during drilling and completion operations in the ancient buried hill Ordovician reservoirs in the Tarim Basin. Geological structure, lithology, porosity, permeability and mineral components all affect the potential for formation damage. The experimental results showed that the permeability loss was 83.8%-98.6% caused by stress sensitivity, and was 27.9%-48.1% caused by water blocking. Based on the experimental results, several main conclusions concerning stress sensitivity can be drawn as follows: the lower the core permeability and the smaller the core fracture width, the higher the stress sensitivity. Also, stress sensitivity results in lag effect for both permeability recovery and fracture closure. Aimed at the mechanisms of formation damage, a modified low-damage mixed metal hydroxide (MMH) drilling fluid system was developed, which was mainly composed of low-fluorescence shale control agent, filtration control agent, low- fl uorescence lubricant and surfactant. The results of experimental evaluation and fi eld test showed that the newly-developed drilling fluid and engineering techniques provided could dramatically increase the return permeability (over 85%) of core samples. This drilling fluid had such advantages as good rheological and lubricating properties, high temperature stability, and low fi ltration rate (API fi ltration less than 5 ml after aging at 120 for 4 hours). Therefore, fractured carbonate formations with low permeability could be protected effectively when drilling with the newly-developed drilling fluid. Meanwhile, fi eld test showed that both penetration rate and bore stability were improved and the soaking time of the drilling fl uid with formation was sharply shortened, indicating that the modifi ed MMH drilling fl uid could meet the requirements of drilling engineering and geology. Fractured carbonate formations with low permeability, stress sensitivity, water blocking, Key words: MMH drilling fl uids, formation damage control from 25% to 60% (Zhang et al, 2006), and the loss caused 1 Introduction by water-blocking ranges from 70% to 90% (Bennion et al, Micro-fractured carbonate reservoirs with low 1999). Much higher permeability loss can result from stress permeability are commonly characterized by high clay sensitivity and can be observed from experimental results for content, high water saturation, complicated pore structures, targeted low-permeability fractured formations. This paper high sensitivity to fresh water, high capillary pressure, severe introduces the damage characteristics of tight carbonate water blocking, severe anisotropy and high flow resistance, reservoir formations with low permeability in the Tarim and have abundant natural micro-fractures. During drilling Basin, and presents an approach to preventing formation and production operations, stress sensitivity damage can damage from stress sensitivity and water blocking during be easily induced by a change in effective stress. Water drilling and completion operations. sensitivity and water-blocking can also be easily caused by various invading fluids (Bennion et al, 2000; Erwom et al, 2 Geological characteristics of target 2003; Lin, et al, 2003; Ren et al, 2004). Furthermore, the formations damage to permeability of formations is largely irreversible. Experimental results show that permeability loss caused by The Ordovician reservoirs in the Tarim Basin are the type stress sensitivity can never be ignored. It commonly ranges of carbonate fracture-porosity dual-permeability reservoirs, and are mainly controlled by geological conditions, development of fractures and dissolution cavities. The *Corresponding author. email: yanjienian@sina.com target formation mainly consists of grayish-brown silt-sized Received April 7, 2008 Pet.Sci.(2008)5:326-333 327 327 crystalline limestone and micrite, with a few calcarenites, until irreducible water saturation, S , was established. The wi and dolostones. The permeability of the target formation is value of S is generally related to rock property, formation wi -3 2 (0.01-36.38)×10 μm . The effective porosity ranges from temperature and pressure. Afterwards, the correlation between 0.11% to 6.76%. The permeability and porosity of the target the permeability to oil and displacement pressure could be formation are extremely low, and secondary corrosion holes, determined. For all the tests, the displacement rate was 1 ml/ cavities and fractures form the main storage space rather min and the confi ning pressure was controlled at 1-25 MPa. 3.1.2 Impact of stress on core permeability and fracture width than the carboncete matrix. The average width of formation fractures is generally less than 10 μm. Clay minerals are Based on above-mentioned test procedure, correlation mainly augenetic, distributed in holes and cavities and between effective stress and permeability or fracture width the total content is commonly less than 5%. Among clay of cores taken from five wells in the target formation was minerals, illite accounts for 33%-70%, with an average value measured and shown in Fig. 1. of 58.5%; illite/smectite (I/S) accounts for 14%-33%, with an It can be seen from Fig.1 that both permeability and average value of 25.6%; kaolinite accounts for 0-27%, with fracture width initially declined quickly with increasing an average value of 11.3%; and chlorite accounts for 0-34%, effective stress. When the effective stress increased to over with an average value of 10.1%. 10 MPa, the decline rate tended to slow down. When the effective stress was over 14 MPa, the permeability loss ranged 3 Main mechanisms of formation damage from 83.8% to 98.6%, with an average value of 93.38%; the fracture width decreased by 71.1% -88.5%, with an average Sensitivity tests for core samples taken from the target value of 76.5%. formation show that the formations are characterized by The low-permeability cores taken from the fractured weak sensitivity to fl ow rate, weak to medium sensitivity to formation usually have relatively stronger sensitivity to stress, water and weak sensitivity to salt, and strong sensitivity to which results in the alteration of the original relations of load- acid. More attention has been paid to sensitivity to stress and bearing frame particles, fractures and pore-throat structures. water-blocking, which is discussed in detail below. The fractures and pore throats tend to close down with increasing effective stress. Consequently, the reduction in 3.1 Experimental evaluation of sensitivity to stress the width of fl uid fl ow channels will lead to a decrease in the Sensitivity to stress can be defined as the impact of permeability of the cores. However, when stress increases to effective stress (the differential between overburden a specifi c value, because relatively low values of permeability pressure and pore pressure) on the permeability of the and fracture width are reached, core permeability and fracture target formation, which is mainly caused by compression width change only slightly with further increasing stress, and closure of capillaries and pores. Unlike mid- and high- therefore stress sensitivity tends to weaken. permeability formations, fluid flow in low-permeability 3.1.3 Impact of effective stress on core porosity formations is affected by the slippage effect, therefore various Double cycles of stress loading/unloading experiments forms of fl ow exist. The strong sensitivity to stress is mainly were performed. The first cycle of stress loading/unloading caused by non-linear gas flow in porous media. The lower experiment referred to the values of porosity that were the formation permeability, especially in fracture-porosity measured at the confining pressure of 3, 5, 7, 10, 20 and channels, the more remarkable the effect on stress sensitivity 30 MPa, respectively. Then stress was gradually unloaded (Luo et al, 2005). Sensitivity to stress is usually related to afterwards a second cycle of stress experiment was performed formation permeability, water saturation, confi ning pressure in the same way. The correlation of core porosity and and displacement pressure. effective stress was measured, and it was shown that cores 3.1.1 Preparation of core samples and test procedure porosity reduced slightly with increasing effective stress. Natural outcrop core samples taken from the Ordovician The reduction in the core porosity was less than 5% during fractured formation were drilled to the desired size and the first stress loading experiment, and the reduction was served as core groundmass of man-made fractured cores. The less than 2% during the second stress loading experiment. cores were then split into two parts along the axial direction It is considered that core porosity mainly depends on what by applying pressure, and fine particles on the fracture the core volume is. Particles in the core deformed slightly surface was blown off with N . Finally, the two sections were after being compacted during the rock-forming process. cemented by resin. The reason why the alteration of core porosity in the first The experiments were performed by using JHMF-II cycle of loading/unloading experiment is higher than that fl owing apparatus designed for cores to simulate in situ stress in the second cycle is as below: There mainly exist double state of formations. The experimental procedure adopted was actions, which are compaction and compression, chiefly as follows: 1) Firstly, the core size was measured, the dry core compaction during the fi rst cycle of stress loading/unloading sample was weighted and N permeability was measured. experiment, therefore alteration of core porosity is relatively 2) The green core was weighed after evacuation saturated high. However, alteration of core porosity becomes less in the with simulated formation brine, and then the porosity of second cycle of loading/unloading experiment due to the end cores could be calculated. 3) The permeability to brine could of compaction and chiefl y compression. All in all, it can be be obtained after the core was set in the test-apparatus and considered that alteration of effective stress can do little harm displaced with brine until the displacing pressure was kept to core porosity. constant. 4) The core was then displaced with kerosene 328 Pet.Sci.(2008)5:326-333 6 12 50 35 50 Permeability Permeability P ermeabilit y 5 10 Fracture width Fracture width 40 40 Fract ure widt h 4 8 30 30 3 6 2 4 10 10 1 2 0 0 0 0 0 0 2 4 6 8 1012141618 0 2 4 6 8 101214 1618 0 2 4 6 8 1012 141618 Effect ive st ress, MP a Effect ive st ress, MP a Effective stress, MPa (a) Core No. A35 (b) Core No. B17 (c) Core No. B36 45 30 10 16 Permeability Permeability Fracture width Fracture width 30 20 15 10 10 4 0 0 0 0 02 46 8 10 12 14 16 18 02 4 6 8 10 12 14 16 18 Effective stress, MPa Effective stress, MPa (d) Core No. C21 (e) Core No. C37 Fig. 1 Impact of effective stress on core permeability and fracture width 3.1.4 Lag effect of sensitivity to effective stress During practical oil field production, every alteration of production parameters, such as intermittent well operating, adjustment of production pressure differential, etc. can inevitably result in alteration of formation pore structure, furthermore, formation permeability and fracture width are seriously damaged. The impact of stress sensitivity on core 30 permeability during stress loading/unloading was evaluated, 0246 8 10 12 14 16 18 20 22 24 26 as shown in Fig. 2. Effect ive st ress, MP a The following phenomenon can be seen from Fig. 2: (a) Core No. B18 1) During effective stress loading, the higher the stress was applied, the more seriously the core permeability was damaged, and hence the higher the stress sensitivity was. However, there exists a stress sensitivity point. When effective stress is higher than such a value, effective stress 18 has relatively less damage to core permeability, hence, stress sensitivity becomes obviously weaker. 2) The stress sensitivity point in the process of stress unloading is lower than that in the process of stress loading, namely, there exists an obvious lag effect of stress sensitivity, and with the increase of cycles of stress loading/unloading, the lag effect 0 2 4 6 8 10 1214 1618 2022 2426 becomes weaker, but once being damaged, permeability can Effective stress, MPa not recover to its original value. This can be caused by the (b) Core No. C36 deformation of the fracture surface of the dual-permeability formation, which results from the continuous effective stress. Impact of stress sensitivity on core permeability during several Fig. 2 This is the so-called lag effect of fracture closure. cycles of loading and unloading -3 2 Permeability, 10 μm -3 2 Permeability, 10 μm Fracture width, μm -3 2 Permeability, 10 μm Fracture width, μm -3 2 -3 2 Permeability, 10 μm Permeability, 10 μm -3 2 Permeability, 10 μm Fracture width, μm -3 2 Permeability, 10 μm Fracture width, μm Fracture width, μm Pet.Sci.(2008)5:326-333 329 more severe water blocking effect. As can be known from the 3.2 Evaluation of water-blocking damage capillary pressure equation and Bennion’s equation (Bennion As pore throats in the low-permeability formations are et al, 1995) of predicting water blocking effect that water extremely small, water blocking is commonly considered blocking damage is mainly related to such parameters as K , one of the main damaging factors. Hence, evaluation of S , and (oil/water interfacial tension) and other factors wi water-blocking damage was also undertaken. The testing such as lithology, type and content of cementing substance, procedure was as follows: Core samples were from taken the pore structure and properties of invasion fl uids, etc. Hence, it target formation, confi ning pressure during entire experiment can never be ignored. Theoretically, 1) In order to minimize remained above stress sensitivity point to reduce the stress capillary force, various types of treating agents and measures sensitivity effect. Firstly, N permeability was measured can be used to reduce surface tension and alter original by using dry core, and the cores were vacuum saturated by formation water wettability to nearly intermediate wettability, standard brine, then the core was displaced with kerosene to namely is approximately 90° (basing on equation 1). 2) leaving irreducible water remaining in the core, and then core Meanwhile, to improve permeability in the near wellbore permeability K was measured by displacing with kerosene op zone by adopting some operations such as acidizing and in the forward direction after it was contaminated by brine in fracturing, etc, water-blocking damage can also be effectively the reverse direction. Finally the rate of permeability damage minimized or eliminated. R was calculated. All displacing tests were performed by using the JHMD-II intelligent core fl ooding apparatus. (1) Table 1 shows that the damage rate R induced by water blocking is relatively higher, ranging from 27.9% to where p is capillary force, is contact angle, r is radius of 48.1%. The lower the original water saturation S and N wi 2 pore throat or contracted capillary. permeability K , the higher the damage rate R , indicating a s Evaluation results of water-blocking damage for cores from fractured carbonate formation Table 1 -3 2 Core permeability, 10 μm Core Porosity Original water saturation N permeability Core damage rate -3 2 , % number S , % K , 10 μm R wi a s Before fl uid blocking After fl uid blocking 1 3.2 14.2 18.0 10.6 5.5 48.1 2 4.5 15.2 7.3 3.4 1.8 47.0 3 4.7 23.6 25.3 14.7 10.6 27.9 fully recovered after the stress is unloaded. This is the so- 4 Protective techniques during drilling and called lag effect of stress, or lag effect of fracture closure. 2) production operations The pore structure of the target formation complicates the stress action. Pore space is extremely small, but the change 4.1 Mechanism of sensitivity to stress in pore space resulting from stress change is relatively Some characteristics concerning sensitivity to stress can greater. Hence, when the stress applied is lower than stress be summarized as below from above mentioned experimental sensitivity point, stress sensitivity is generally very high. 3) results. 1) Tested cores have obvious sensitivity to stress, the Pore throats and pore channels in the core are compressed by permeability of cores are drastically reduced with the increase stress. Especially, when effective stress is lower than stress in effective stress. 2) There exists a stress sensitivity point, sensitivity point, fluid flow capacity declines because pore above which stress sensitivity becomes weaker. 3) During the throats and pore channels are compressed by stress. Namely, decrease in stress, there exists an obvious lag effect of stress the measured core permeability declines. However, when sensitivity or fracture closure, and the more times the stress pore throats and pore channels are compressed to a specifi c was applied, the weaker the lag effect of stress sensitivity extent, namely reaching the stress sensitivity point, the extent or fracture closure. 4) Cores with low permeability or small or tendency of being compressed becomes relatively smaller, fracture width can not fully recover their permeability values and correspondingly the decline of core permeability becomes after stress was applied. All tested cores failed to recover smaller. 4) Various formations have different extents of stress their original permeabilities. The following reasons can sensitivity, which mainly depends on compaction effect, type probably explain the stress sensitivity of low-permeability and content of rock mineral composition, packing substances fractured formation. 1) There are abundant micro-fractures in fractures and their types and contents (Ostensen, 1986; in the rock. Micro-fractures can easily be closed after stress Ruan and Wang, 2002). is applied. Furthermore, these closed fractures can not be 330 Pet.Sci.(2008)5:326-333 4.2 Prevention of damage induced by sensitivity to In the MMH drilling fluid system, bentonite can react stress during drilling and production operations with the MMH particles and water to form a special spatial network structure (Zhang et al, 2000). The size of this For a given formation, the value of effective stress mainly network structure formed is usually bigger than that of depends on pore pressure. The higher the pore pressure, pore throat and micro-fracture width. Consequently, clay the smaller the effective stress. Therefore, some necessary particles invasive depth is restricted. The flexible plugging preventive measures should be taken into account. For at pore throats formed by compound network structure can example, a reasonable range of negative pressure for under- be deformed and later effectively drained out of formation. balanced drilling and tripping operation should be kept so as Unlike solid particle plugging, which needs high drainage to maintain a higher pore pressure, and effectively prevent pressure and in which possibly the blocks at the pore throats formation damage caused by overly negative pressure, partial can hardly be drained out, organic MMH particles can be excessive lower pore flow pressure or overly big surge easily dissolved by oil and acid, which can further improve pressure resulting from tripping operation. The sensitivity to oil/gas phase permeability by means of the flowback of stress can lead to even more serious damage in the process oil and acidizing treatments, etc. At the same time, MMH of production. Hence, it is necessary to keep a reasonable drilling fl uid can effectively inhibit clay hydration, swelling, production pressure differential and possibly avoide and has strong resistance to salt sensitivity, so it has unique unnecessary well shut-in to effectively prevent damage performance for fractured carbonate reservoir protection. caused by sensitivity to stress. 5.3 Formulations and properties of drilling fl uids 5 Formulations and properties of low- Considering that all kinds of treating agents should meet damage drilling fluids used in fractured the requirements of formation lithology, physical properties, carbonate formations sensitivity characteristics and well logging, it is necessary to select shale-controlling agents with low-fluorescence, Low-damage drilling fluids are generally composed of fi ltration control agents, lubricants and surfactants properly, fracture-packing agents (such as asbestos fiber and sized so as to improve the performance of the MMH drilling fl uids. calcium carbonate), soft particles of oil-soluble resin and On the basis of experiments, a typical formulation of the some strongly inhibitive agents. In addition, a special film- MMH drilling fluid is listed as below: 4% bentonite + 7% forming agent can be used to plug up the fractures with MMH + 2% SMP-1 + 2% WFT-666 + 3% CHSP-1 + 3% various widths very quickly and effectively. This drilling fl uid DFD-140 + 0.2% SP-2 + 2% MHR86D (lubricant) + 0.2% system is characterized by a high stress bearing capacity, low ABSN + 4% CaCO . drainage pressure and high permeability recovery, etc (Li, 3 For some formations, an alternative drilling fl uid system 2001; Lu et al, 2004; Zhang and Yan, 2004; Zhao et al, 2007). can also be used to enhance the plugging effectiveness 5.1 Requirements of low-damage drilling fl uids further. Its formulation is as below: 4% bentonite + 7% MMH + 2% SMP-1 + 2% WFT-666 + 3% CHSP-1 + 3% DFD-140 Under-balanced or near-balanced drilling technology has + 0.2% SP-2 + 2% MHR-86D + 0.2% ABSN + 2% QCX-1 + been widely applied to penetrating targeted formations in 1.5% DYY-1 (an oil-soluble resin) + 4% CaCO . the Tarim Basin. According to the main damage mechanisms 5.3.1 Evaluation of rheological properties for the Ordovician fractured carbonate formations, the basic Experimental results in Table 2 show that all the technical approaches to designing a low-damage drilling rheological parameters are rational. Meanwhile, the API fluid are as follows: 1) All kinds of treating agents used in fi ltration rate is less than 5 ml. drilling fl uids should be compatible with formation rock and 5.3.2 Compatibility between drilling fl uids and formation rocks brine so as to minimize formation damage during drilling The test sample was prepared by mixing 350 ml of low- operations; 2) Efficient filtration control agents should be damage drilling fluid with 40 grams of dry drilled cuttings. optimized to form quickly high-quality mud cake so as The drilled cuttings were dried at 100 ºC for 4 hours and then to reduce invasion depth of drilling fluids under a given screened to 10 mesh. According to the differential weights positive pressure differential; 3) Effi cient surfactants should of cores before and after aging, compatibility between the be optimized so as to reduce oil/water interfacial tension, drilling fluid and formation rock can be evaluated. The and minimize formation damage induced by water-blocking; experimental results are shown in Table 3. It can be found that 4) Maintaining a reasonable density of drilling fluids and the drilling cuttings recovery was over 99%, and no obvious controlling an appropriate range of surge pressure, so as to change happened in color and shape after aging, illustrating prevent formation damage induced by sensitivity to stress. an excellent compatibility. 5.2 Characteristics of low-damage MMH drilling 5.3.3 Compatibility between drilling fl uids and formation brine fl uid The low-damage drilling fl uids were mixed with formation brine in a proportion of 1:2 using an 8000 r/min high-speed The MMH electropositive colloid drilling fluid has mixer. After aging for 1 hour, no deposition and cloudiness formation protective functions such as reducing clay particle were observed, illustrating that drilling fl uids are compatible invasion, inhibiting hydration and swelling, high drainage with formation brine. rate and high permeability recovery, etc. Pet.Sci.(2008)5:326-333 331 5.3.4 Measurements of returned permeability for cores kerosene at a confi ning pressure of 4 MPa and a displacement contaminated with drilling fl uids rate of 1.0 ml/min; 3) Under the same conditions, the The JHMD-II core flooding test apparatus was used to permeability, K ', was measured after being contaminated measure the return permeability. The test procedures are as with low-damage drilling fl uids in the opposite direction, the follows: 1) The man-made fractured core, by mixing cores return permeability, which is herein defined as the percent taken from Ordovician fractured carbonate formations with permeability that is recovered, was calculated. : : : filling substances (in a proportion of smectite illite CaCO The test results are listed in Table 4. It can be seen that the : : : formation brine = 1 10 30 90) was 2.54 cm in-diameter return permeability of two core samples contaminated with and 2.75 cm in length. The man-made core was saturated the MMH drilling fluid are all over 87%, indicating good with simulated formation brine after being vacuum dried; protective effect. 2) The permeability, K was measured by displacment with S, Table 2 Rheological properties of low-damage drilling fl uids Density Apparent viscosity Plastic viscosity Yield point Gel strength API fi ltration loss Experimental conditions pH value , g/cm AV, mPa·s PV, mPa·s YP, Pa 10"/10', Pa ml Before aging 1.14 48.5 43.0 5.5 2/15 4 8.5 1) After aging 1.14 30.0 25.0 5.0 1/5 5 9.0 Notes: 1) Aging at 120 ºC for 16 hours Compatibility between low-damage drilling fl uid and formation cores Table 3 Weight of core, g Core Recovery percent number % Before being contaminated After being contaminated 1 39.76 39.56 99.5 2 40.15 39.86 99.3 Average 99.4 Table 4 Return permeability of cores contaminated with low-damage drilling fl uids Core Initial permeability Permeability after being exposed to Return permeability -3 2 -3 2 number K , 10 μm drilling fl uid K ', 10 μm % 1 5.36 4.68 87.3 2 7.12 6.29 88.3 Average 87.8 measured and shown in Table 5. The return permeability of 5.4 Field application cores contaminated with the mud were over 85% (Table 6), The modified low-damage MMH drilling fluid was used indicating only a slight extent of damage measured. for drilling the target formation in Well LG-6. This was a The results of fi eld tests show that this low-damage MMH high-slope directional wildcat well located in the Tarim Basin. drilling fl uid had good rheological and lubricating properties, The hole inclination angle was 62.4°-69.7°. The penetration as well as low filtration rates during drilling the target depth was 5,471-5,890 m. The coefficient of formation formation. The friction resistance during tripping operation pressure was 1.12 and formation temperature was 120 ºC. was only 2-3 tons. The borehole was regular and no collapse The rheological parameters of the field mud were happened. The main measures adopted during drilling 332 Pet.Sci.(2008)5:326-333 operations included controlling concentration of ABSN not controlling reasonable density of drilling fluid to minimize less than 0.2%; reinforcing solids control, cleaning out useless stress sensitivity caused by great positive differential pressure solid particles as much as possible, keeping the proportion and reducing drilling duration as much as possible, etc. between drilling cuttings and bentonite less than 3:1, Table 5 Rheological properties of fi eld mud (120 ºC/16h) Sticking Flow Consistency Mud μ AV PV YP G10 /10' API fi ltrdtion loss HTHP fi ltrdtion loss coeffi cient behavior index pH value types s mPa·s mPa·s Pa Pa ml/mm ml/mm g/cm K index n K, Pa·s 1 1.15 51 31.5 24.0 7.5 3.5/8 4.5/0.5 9.8/1.0 0.02 0.69 0.27 8.5 2 1.15 50 32.0 24.5 7.5 3.0/8 4.5/0.5 9.5/1.0 0.02 0.68 0.26 9.0 Table 6 Return permeabilities of core samples from Well LG-1 Initial permeability Core Permeability after being exposed to drilling fl uid Return permeability -3 2 -3 2 number K , 10 μm K ', 10 μm % s s 3 9.38 8.14 86.8 4 8.41 7.20 85.6 Average 86.2 Notes: The core samples were taken at a depth of 5585 m 6 Conclusions due to its network structure formed by clay particles, water molecules and MMH colloid particles. Therefore, the 1) The main storage space in fractured carbonate modifi ed low-damage MMH drilling fl uid could be used for formation with low-permeability includes micro-pores and protecting fractured carbonate reservoirs during drilling. micro-fractures. The sensitivities to effective stress and water blocking are determined as the two major damage factors. Acknowledgements 2) Experimental results showed that the permeability loss caused by increasing effective stress ranged from 83.8% to The authors gratefully acknowledge Project of the 98.6%, indicating quite a strong sensitivity to stress, while National Natural Science Foundation of China (No. the permeability loss caused by water blocking ranged from 50574061) for the partial support of this work. 27.9% to 48.1%. References 3) The sensitivity to stress is mainly related to the characteristics of fractures and the structure of pores in Ben nion D B, Thomas F B, Bietz R F, et al. 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Petroleum Science – Springer Journals

Published: Nov 21, 2008

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