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The damage mechanism of oil-based drilling fluid for tight sandstone gas reservoir and its optimization
Journal of Petroleum Science and Engineering 158 (2017) 616–625
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The damage mechanism of oil-based drilling fluid for tight sandstone gas reservoir and its optimization Ming Lei a, b, Wei'an Huang a, *, Ning Li c, Jiang'hong Jia d, Jia'xue Li c, You'wei Wang a, Jing'ye Li a a
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong, 266580, China Tarim Oil Field Branch Company of PetroChina, Korla, Xinjiang, 841000, China Research Institute of Oil and Gas Engineering, Tarim Oilfield Division, Korla, Xinjiang, 841000, China d Research Institute of Drilling Technology, Sinopec Shengli Petroleum Engineering Co., Ltd., Dongying, Shandong, 257017, China b c
A R T I C L E I N F O
A B S T R A C T
Keywords: Tight gas reservoir Oil phase trapping Emulsion plugging Oil-based drilling fluid The B block in tarim basin
The B block is a typical tight sandstone gas reservoir in Tarim basin in the Xinjiang Uygur Autonomous Region, China. In this block, the skin factors of each well drilled by oil-based drilling fluids were high and the reservoir damage was serious. The permeability recovery rates of two kinds of oil-based drilling fluids used in site were both less than 60%. To investigate the damage mechanism, the particle size distribution was tested to analyze solids damage incorporating the pore throat radius and micro-fracture width in this block. The contact angles of deionized water on reservoir cores before and after polluted by oil-based filtrate were measured to analyze the wettability alteration. Core flow experiment was applied to evaluate oil phase trapping, and the emulsion droplets formed by mixing oil-based filtrate with formation water were observed to analyze emulsion plugging damage. Based on the test results, the factors causing damage to the tight sandstone gas reservoir included solid phase invasion to fractures, wettability alteration, oil phase trapping and emulsion plugging. Therefore, the oil-based drilling fluids were optimized from aspects of reduction of the filtration loss, improvement of the sealing ability of the micro-fractures and reduction of the oil-water interfacial tension. A temporary plugging agent was compounded by using the Ideal Packing Theory, which could effectively plug the microfractures. The surfactant was optimized, and it could destroy the oil-based filtrate cake effectively and break emulsion in a short time. The permeability recovery rate of optimized oil-based drilling fluids was evaluated and the results showed that permeability recovery rate was 87.40% and 86.74%. Furthermore, cores early contaminated by oil-based drilling fluid were treated by optimized surfactant, and the tested permeability recovery rate reached more than 100%.
1. Introduction Tight sandstone gas reservoirs are rich in resources and the world's tight gas 1 resources distributed in many basins around the world amounted to 114 trillion cubic meters. The tight gas recoverable resources in China amounted to 9–13 trillion cubic meters, accounting for about 22% of the national natural gas recoverable resources according to the data from Chinese Academy of Engineering. Tight sandstone gas reservoir is an important oil and gas exploration area in the future and has a good development prospect. However, tight sandstone gas reservoir is one type of unconventional gas reservoir where natural gas is enriched in sandstone with low porosity (less than 10%) and low permeability (less than 0.1 103 μm2), which usually characterized by high capillary force, high irreducible water saturation, a tiny size of pore throats, severe
heterogeneity and abundant micro-fractures (Reinicke et al., 2010; Geng et al., 2010; Zhang et al., 2008; Andrews et al., 2012). Thus, it is harder to develop by conventional technology and easier to be damaged during drilling and gas production. Liquid phase trapping is one of the most serious damage factors in this kind of gas reservoirs. On condition that the initial water saturation is generally lower than the irreducible water saturation in tight sandstone gas reservoirs, the serious liquid phase trapping can be formed by self-absorption and retention of the filtrate under the effect of relative permeability and potential capillary pressure. The damage degree of liquid phase trapping is influenced by the capillary pressure and the initial water saturation, and it is also related to the quality of the mud cake (Bennion et al., 1994, 2000; Rickman and Jaripatke, 2010; Bahrami et al., 2011; 2012a,b; Zhang et al., 2012). Meanwhile, tight sandstone gas reservoirs are formed accompany with
* Corresponding author. School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong, 266580, China. E-mail addresses: [email protected] (M. Lei), [email protected] (W. Huang). http://dx.doi.org/10.1016/j.petrol.2017.09.003 Received 10 May 2017; Received in revised form 27 August 2017; Accepted 6 September 2017 Available online 6 September 2017 0920-4105/© 2017 Elsevier B.V. All rights reserved.
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
sensitivity. Summarily, Wang et al. (2014) proposed the protection status of tight gas reservoir as follows: ①although the surface tension of oil is lower than that of water, oil-based drilling fluid filtrate could be also adsorbed and retained after entering the gas reservoir; ②the change in wettability would increase the flow resistance of natural gas in the percolation channel, adversely affecting gas well production; ③oil-based filtrate invasion resulted in the change of reservoir from the original gas and water flow to gas, water, oil three-phase flow, and oil is a non-wetting phase, gathering into a mass in the middle of the percolation channel, reducing gas effective permeability. The B block is located in the Kelasu tectonic belt of Kuche depression in Tarim basin where the reservoir porosity is distributed between 1% and 9.4% with an average of 6.8% and the permeability is distributed between 0.011 103 μm2 and 8.56 103 μm2 with an average of 0.19 103 μm2. The B block belongs to a typical low permeability tight gas reservoir with low porosity, low permeability and serious heterogeneity. The skin factors of each well drilled by oil-based drilling fluids were high generally distributed between 5 and 20 and the reservoir damage was serious according to well testing interpretation. Thus, the objective of this study is to investigate main damage mechanism of oilbased drilling fluid in a certain tight sandstone gas reservoir in the B block, through testing permeability recovery rates of reservoir cores and analyzing the effect of solid phase and liquid phase on reservoir. Eventually, the oil-based drilling fluids are optimized from the aspect of ideal packing technology, oil-based filtrate cake removal, and demulsification of oil-based filtrate.
fractures in general. Fractures are sensitive to stress and once the effective stress reaches a critical value, fractures tend to contact even close, leading to crushing of the rocks then solid plugging damage occurs with aggregation of particles in the gas flow (Oluyemi, 2011). In addition, if particles in the drilling fluids could not form bridging or shielding at the fractures entrance, solid and liquid phase would invade into reservoir through micro-fractures deeply due to leakage of drilling fluids into natural fracture system or adsorption of polymer residue on fracture surface, causing severe damage to fractures and matrix (Huang and Clark, 2012; Loghry et al., 2013). Tight sandstone gas reservoirs are susceptible to various damages while oil-based drilling fluids are widely used in tight sandstone gas reservoir in Tarim basin in recent years, because oil-based drilling fluids possess the advantages of strong inhibition of shale, high temperature resistance, low formation damage, good lubrication performance and strong corrosion resistance (Zhang et al., 2015). At present, there are several main types of the oil-based drilling fluid including whole oil-based drilling fluid, low toxicity oil-based drilling fluid, high temperature resistant oil-based drilling fluid, and reversible emulsion drilling fluid. Many studies on oil-based drilling fluid treating agents have been conducted aimed at issues of oil-based drilling fluid such as sedimentation stability, emulsion stability and contamination of drilling cuttings to drilling fluid (Wang, 2011; Pan et al., 2014). Nevertheless, more and more researches’ results show that oil-based drilling fluid can also cause some damage to the oil and gas reservoirs. The basic compositions of oil-based drilling fluid are base oil, emulsifier, wetting agent, water phase and lipophilic colloid which are all potential factors causing reservoir damage. The organic bentonite is a lipophilic bentonite modified from bentonite by surfactant, so it presents as finely dispersed particle in oil phase that can easily invade into pore throats and seepage channel (Thomas et al., 1984). The wetting agent can cause wetting reversal and transform wettability on rock surface from hydrophilicity to lipophilicity, accordingly, the oil phase and lipophilic colloid are more easily attached to the surface of the pore throats, reducing effective gas flow area (Cui, 2012; Qutob and Byrne, 2015). The formation water and oil phase can easily form emulsion under the effect of emulsifier that may damage reservoirs by plugging pore throats and fractures (Wang, 2012; Qutob and Byrne, 2015). Currently, there are a few researches on damage mechanism of oil-based drilling fluids in tight sandstone gas reservoirs. Bahrami et al. (2012a,b) believed that the filtrate of oil-based mud might result in introduction of an immiscible liquid in tight gas reservoir drilled by oil-based drilling fluids, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. And Zhang et al. (2015) attributed the main factors of oil-based drilling fluids damaging tight gas reservoir to solids plugging, multi-phase flow effect, wettability reversal and emulsion plugging through laboratory experiments. Similarly, Kang et al. (2013) evaluated the damage of oil-based drilling fluid to a shale gas reservoir and confirmed the primary damage mechanisms of oil-based drilling fluid were solid phase invasion, oil trapping, alkaline damage, stress
2. Experimental methods 2.1. Equipment and materials Experimental equipment includes drilling fluid pollution instrument YBH-1 manufactured by Meter Factory of University of Petroleum, low permeability core flow testing apparatus DSRT-II developed by Yangtze University, laser particle size analyzer Bettersize2000 produced by Bettersize Instrument Co., Ltd, scanning electron microscope S-4800 produced by HITACHI, polarizing microscope ISH500 produced by FENYE Optoelectronic Equipment Co., Ltd, surface tension detector BZY-1 produced by PINGXUAN Scientific Instrument Co., Ltd, contact angle tester JC2000D5M produced by POWEREACH Industrial Limited. Two kinds of experimental oil-based drilling fluids were respectively INVERMUL oil-based drilling fluid collected from Well B2-2-20 and traditional oil-based drilling fluid collected form Well B105. The important mud properties of two oil-based drilling fluids were listed in Table 1. Natural cores were collected from Well B2 at depth of kelly bushing between 6781.5 m and 6865.5 m and rock fragments used for analysis of mercury, surface properties and scanning electron microscope were collected from Well B1 at depth between 6917.5 m and 6924.2 m as well as Well B2 at depth between 6770 m and 6773 m.
Table 1 Properties of two kinds of oil-based drilling fluids. INVERMUL oil-based drilling fluid
Type Properties
After aging(140 C/16 h)
Before aging Plastic viscosity (mPa⋅s) Yield point (Pa) Gel 1000 /Gel 100 (Pa) FLAPI(mL) FLHTHP(mL) ρ(g/cm3) pH lubricating property Sedimentation stability
Sticking factor of mud cake Lubrication factor Density difference (g/cm3) Note
traditional oil-based drilling fluid Before aging
70 69 56 7.5 5.5 7 3.5/8 3.5/8.5 3/6 0.1 0 0 3 1.2 1.91 1.81 8 8 0.0262 0.0349 0.1322 0.1325 0.021 0.009 Let drilling fluids stand for 24 h and test density upper and lower layers
617
After aging(140 C/16 h) 38 3 2.25/2.5 0
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
on the contaminated surfaces were tested and compared with the previous result.
The surfactants including polyoxyethylene octylphenol ether (OP10), sorbitan monooleate polyoxyethylene ether (Tween80), cetyl trimethyl ammonium chloride (CTAC), imidazoline, sodium dodecyl benzene sulfonate (SDBS) applied in the experiment were all analytical reagents and produced by Sinopharm Chemical Reagent Co., Ltd, and calcium carbonate powder of different specifications also made by Sinopharm Chemical Reagent Co., Ltd were prepared.
2.2.4. Evaluation method of oil phase trapping The oil phase trapping damage was evaluated by using a low permeability core flow testing apparatus in the light of the reference of “Formation damage evaluation by flow test” form Chinese oil industry standards published in 2010. Details of the specific experimental steps were as follows: ①a piece of core was oven-dried to a constant weight after washing and then saturated with kerosene to the initial oil saturation; ②the core gas permeability in initial oil saturation recorded as K0 was tested; ③the core gas permeability in different oil saturation recorded as Ki was tested with kerosene squeezed into the core; ④The core permeability damage rate recorded as DWF could be calculated by the following equation:
2.2. Methods of damage mechanism of oil-based drilling fluids 2.2.1. Evaluation method of the damage degree Refer to “Lab testing method of drilling and completion fluids damaging oil formation” form Chinese oil industry standards published in 2002, the drilling fluid pollution instrument was selected to evaluate the dynamic damage degree of tight gas formation by oil-based drilling fluid. Details of the specific experimental steps were as follows: ①two sets of cores recorded as 1# and 2# respectively were oven-dried to a constant weight after washing by methylbenzene and ethanol, then saturated with formation water above 24 h in a vacuum environment, finally the backup cores were placed in a humid environment; ②the irreducible water saturation of cores was built with unsteady-state gas drive lasting for 2 h under constant confining pressure of 3 MPa and displacement pressure of 2 MPa; ③the core gas permeability in the bound water state was taken as the initial value recorded as K0; ④the cores were respectively contaminated by two kinds of oil base drilling fluids used in the B block for 125 min at a high temperature of 120 C, a constant differential pressure of 3.5 MPa and a constant shear rate of 170 s1, meanwhile, dynamic filtration at different time was record; ⑤the contaminated core gas permeability recorded as K1 was tested after displaced for an hour at a constant nitrogen gas pressure of 2 MPa. The permeability recovery rate recorded as R could be calculated by the following equation:
R¼
K1 100% K0
DWF ¼
jKi K0 j 100% K0
(2)
Where, DWF is the permeability damage rate in %; K0 is the gas permeability in initial oil saturation in 103 μm2; Ki is the gas permeability in irreducible liquid phase saturation in 103 μm2 when we need the damage rate of oil phase trapping. 2.2.5. Evaluation method of emulsion plugging The emulsion was prepared by mixing filtrate of oil-based drilling fluid with simulated formation water at different proportions and then observed under a polarizing microscope. The size of emulsion droplet was measured and accordingly, the emulsion plugging damage was evaluated. 2.3. Methods of optimization of oil-based drilling fluids Based on the problems of poor reservoir protection effect of oil-based drilling fluids, the oil-based drilling fluids should be optimized from aspects of reduction of the filtration loss, improvement of the sealing ability of the micro-fractures and reduction of the oil-water interfacial tension. A. With the principle of equal emphasis on the protection of matrix and fracture, oil-soluble calcium carbonate particles with reasonable particle size distribution should be selected by Ideal Packing Theory to form a compact mud cake with very low filter loss which can avoid invasion of the solids and filtrate. B. The surfactant should be optimized to reduce interfacial tension between oil and water effectively and prevent or remove the oil phase trapping damage in time as well as destroy the emulsion in the reservoir.
(1)
Where, R is the permeability recovery rate in %; K0 is the initial gas permeability in 103 μm2; K1 is the contaminated core gas permeability in 103 μm2. 2.2.2. Evaluation method of solids damage First, the particle size distributions of two kinds of oil based drilling fluids were measured with a laser particle size analyzer, as well the average pore throat diameter and maximum pore throat diameter of reservoir in the B block were calculated by a mercury intrusion test and the size of micro-fractures was measured by scanning electron microscope. Then the solids damage was judged according to the theory of shielding temporary plugging which believed that when median grain diameter of the temporary plugging particles is equal to or slightly larger than 1/3 times (the best is 2/3 times) of the average pore diameter of throats based on overbalanced drilling process, a good temporary plugging zone can be formed.
2.3.1. Optimization method of ideal packing technology In the Ideal Packing Theory, when the cumulative volume fraction of temporary plugging agent particles is proportional to the square root of the particle diameters, an ideal filling of the particles can be realized. Based on that, the D90 rule of thumb was proposed for implementation in site which believed that an ideal filling could be achieved when the D90 value (90% of the particles have a diameter less than this value) of the temporary plugging agent on the cumulative distribution curve is equal to the maximum diameter of pore throats or the maximum width of fractures (Ai et al., 2006; Zheng et al., 2009; Wang et al., 2007). And a baseline is defined as the connection of origin and D90 value which is a crossover point of maximum size of pore throats or fractures and 90% of the volume fraction, intuitively, the closer the curve about cumulative volume fraction and the square root of the temporary plugging particles diameters is to the baseline, the better the temporary plugging effect is. The particle diameter distributions of calcium carbonate particles in different sizes were tested by a laser particle size analyzer, and compared the result with sizes of pore throats and fractures introduced in section 2.2.2. The calcium carbonate particles were compounded according to
2.2.3. Evaluation method of wettability The influence of oil-based drilling fluid on the wettability was evaluated by measuring the contact angles of deionized water on the surface of reservoir rocks with a contact angle tester. Details of the specific experimental steps were as follows: ①the surfaces of three pieces of rocks selected from the B block at the same depth were polished until smooth with a fine sandpaper, and then the rock samples were oven-dried for preparation after boiled for 5 min in the sodium hydroxide solution at a concentration of 5%; ②the contact angle of the simulated formation water on the first rock specimen surface was tested with a contact angle tester; ③the surfaces of the second and third rock samples were polluted respectively by filtrates of two kinds of oil-based drilling fluids and airdried; ④likewise, the contact angles of the simulated formation water 618
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
the Ideal Packing Theory and the D90 rule. Details of the specific experimental steps were as follows: ①the curve about the square root of the particle diameters and the cumulative volume fraction was drawn according to the particle size distributions; ②according to the maximum diameter of pore throats and the maximum width of fractures, drew a baseline; ③the curve of particle diameter distributions of calcium carbonate particles was compared with the baseline and the calcium carbonate particles with suitable size were selected and compounded at a calculated proportion; ④the compound temporary plugging agent was added into two kinds of oil-based drilling fluids and the permeability damage rates were evaluated with the method in section 2.2.1.
A¼
4μL2 r 2 P 2rσ cos θ
(4)
Where, A is the cleaning efficiency in %; G0 is the quality of filter paper in gram; G1 is the quality of filtrate cake and filter paper in gram; G2 is the quality of filtrate cake and filter paper after cleaning in gram. 3. Results and discussion 3.1. Analysis of damage degree of the oil-based drilling fluids The results of permeability recovery rate listed in Table 2 show that the permeability recovery rates of INVERMUL oil-based drilling fluid and traditional oil-based drilling fluid were respectively 54.17% and 57.36%, both were less than 60%. The dynamic filtration losses were both 0 mL in whole process indicating that the filtrate hardly passed through the tight rocks, thus any clogging of whether the solids or filtrate, even to a small extent, could cause serious damage to the pore throats and micro-fractures inside the rock. The protection effect of oilbased drilling fluids is not ideal in the tight gas reservoir in the B block. The reasons why oil-based drilling fluids doing serious harm to the tight gas reservoir might be caused by various factors, in this paper, the damage mechanism of oil-based drilling fluids was analyzed from solids invasion and filtrate invasion.
2.3.2. Optimization methods of surfactant In tight gas reservoirs, the filtrate could invade formation inevitably with the existence of surplus capillary pressure and the damage of oil phase trapping and emulsion plugging was produced subsequently. Besides, the oil-based filtrate cake was difficult to remove and filtrate was hard to flow back. Thus the surfactant was optimized to reduce capillary force, destroy the emulsion on filtrate-cake surface and the mixture of oilbased filtrate and formation water, as well as the solid-phase cementing structure. According to the kinetic equation of liquid blocking effect, in hydrophilic strata, the time a liquid flowed through a capillary tube could be calculated by the following equation from the transformation of Poiseuille Law:
t¼
G1 G2 100% G1 -G0
(3)
3.2. Analysis of solids damage
Where, t is the time a liquid flowed through a capillary tube in s; μ is the liquid viscosity in Pas; L is the length of liquid column in m; P is the driving pressure differential in Pa; r is the radius of capillary tube; σ is the oil-water interfacial tension in N/m; θ is the contact angle of liquid on surface of capillary tube in . In the equation, the values of r, L, μ and P are all constant in a certain reservoir so the product of σ and cosθ can be the index for surfactant optimization. The smaller the product of σ and cosθ is, the lower the capillary pressure is, and the more easily the liquid flows back. The research method was as follows: ①the contact angles recorded as θ of different surfactant solutions on the surface of reservoir rocks were tested, and the interfacial tensions recorded as σ between surfactant solutions and diesel were measured; ②the surfactant was optimized through a comparison of the product of σ and cosθ; ③two pieces of filtrate cakes of oil-based drilling fluid were prepared, one of which was fixed to the outer cylinder of a six-speed rotational viscometer and rotated under a certain speed for certain time within the optimized surfactant solution, and the other one was soaked in the optimized surfactant solution for different time. The cleaning efficiency of the optimized surfactant recorded as A could be calculated by equation (4); ④the emulsion was prepared by mixing filtrate of oil-based drilling fluid with simulated formation water at the proportions of 1:1 and 1:2, then the optimized surfactant was added into it and the demulsification of emulsion was analyzed by observing and recording the separate time of oil-water, clarity of interface and the size of emulsion droplets; ⑤the cores (1#, 2#) were treated by the optimized surfactant at a high temperature of 120 C and a constant differential pressure of 3.5 MPa, then the permeability recovery rates of these two cores were measured.
The oil-based drilling fluid has strong inhibition performance of shale so the solids damage is mainly manifested in the invasion of solid particle in oil-based drilling fluid and drilling debris. The main particle size values of two kinds of oil-based drilling fluids are presented in Table 3. The contents of solid particles whose diameter was less than 5 μm and between 5 μm and 30 μm were about 50%vol and 40%vol respectively in INVERMUL oil-based drilling fluid. In accordance with the theory of shielding temporary plugging, the solid particles could form temporary plugging on the surface of pore throats and microfractures whose diameters were less than 20 μm. Similarly, in traditional oil-based drilling fluid, the contents of solid particles whose diameter was less than 3 μm and between 3 μm and 10 μm were about 50%vol and 40%vol respectively, theses solid particles could seal pore throats and micro-fractures whose diameter was less than 9 μm. The statistical information of pore throats and micro-fractures in Well B1 and Well B2 is listed in Table 4 from the analysis of intrusive mercury experiment and scanning electron microscope. The pore throat diameter of tight sandstone was tiny, and the solid particles of two kinds of oilbased drilling fluid could effectively plug the pore throats, avoiding a deep invasion of the solids and filtrate. However, the average size of micro-fractures in Well B2 was large, reaching 23 μm. The size matching relationship between solid particles in oil-based drilling fluids and fractures was poor and the content of effective solid particles was Table 3 The main particle size value of oil-base drilling fluid. Type
D10(μm)
D50(μm)
D90(μm)
INVERMUL oil-based drilling fluid traditional oil-based drilling fluid
1.139 0.897
5.915 2.830
27.694 10.473
Table 2 Results of permeability recovery rate contaminated by oil-based drilling fluids. Core
1# 2#
Treatment liquid
INVERMUL oil-based drilling fluid traditional oil-based drilling fluid
Permeability (103 μm2) Before the contamination
After the contamination
0.01665 0.01290
0.00902 0.00740
619
Dynamic filtration loss (mL)
permeability recovery rate(%)
0 0
54.17 57.36
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
Table 4 Pore throats and micro-fractures information in the B block. Well
Horizon
Average diameter of pore throats (μm)
Maximum diameter of pore throat (μm)
Average width of micro-fractures (μm)
Maximum width of micro-fractures (μm)
B1 B2
K1bs K1bs
0.6269 0.5683
3.0237 1.9613
1.2595 23.1185
4.39 70.9
insufficient, so the solid particles couldn't seal fractures effectively, resulting in solid particles invaded reservoir through micro-fractures deeply under the positive differential pressure. The tight sandstone gas reservoir is severe heterogeneous with great difference in the width of micro-fractures. Two kinds of oil-based drilling fluids used in site were limited because they could temporarily plug the pore throats while couldn't plug the fractures with large width. So the solid particles could invade reservoir deeply and easily attach to the surface of the pore throats because of the containment of a large number of lipophilic bentonite in oil-based drilling fluids.
Table 5 Effect of oil-based drilling fluid on reservoir wettability under room temperature. Soaking medium
Contact angle ( )
Wettability
Simulated formation water Filtrate of INVERMUL oil-based drilling fluid Filtrate of traditional oil-based drilling fluid
39.86 58.73
hydrophilicity weak hydrophilicity
81.20
intermediate wettability
capture filtrate of oil-based drilling fluid seriously, and eventually the oil trapping damage would come into being inevitably as the oil droplets plugged pore throats and micro-fractures under strong capillary forces.
3.3. Damage of filtrate invasion
3.3.3. Emulsion plugging and the effect of multiphase flow The filtrate of oil-based drilling fluid contains emulsifier molecules which could act on the mixture of filtrate and formation water, so the emulsion would be easily produced under the action of shearing force and fluid perturbation. In the flow process, the internal frictional resistance of the emulsion increases resulting in the increase of viscosity of emulsion and it's difficult for the gas to break through. Emulsion droplets have different sizes, the droplets with larger size can form plugging in pore throats and micro-fractures singly, and the smaller ones form plugging by superposition multiply or adsorption on the surface of seepage channel. The emulsion droplets prepared by mixing filtrate of oil-based drilling fluid and formation water at the proportion of 1:1 were shown in Fig. 2. The sizes of emulsion droplets were various and the average radius was about 8.31 μm that was larger than common ones, the reasons might be the coalescence of emulsion droplets during the process of preparation and observation. The size should be smaller under the action of shearing force and fluid perturbation during drilling. In addition, oil-based drilling fluid itself was also an emulsion and the radius of which as well as formed emulsion was smaller than the solid particles in drilling fluid, so the emulsion would plug pore throats and micro-fractures easily and cause damage. However, the emulsion system is instable and in high temperature static environment the demulsification phenomenon will happen in different degrees which are controlled by the intensity of the interfacial film. Furthermore, the intensity of the interfacial film is influenced by
The oil-based drilling fluid has the advantage of low filtration loss, while under reservoir conditions, the filtrate can inevitably enter formation, and causing a series of damage. In the following contents, damage of filtrate invasion was analyzed from wettability alteration, oil phase trapping, emulsion plugging and the effect of multiphase flow. 3.3.1. Wettability alteration The wetting agents in oil-based drilling fluids can alter the wettability of the rock surface from hydrophilic to lipophilic during the process of invading the porous or micro-fractured seepage channels. Results of contact angles of deionized water on the surface of reservoir rocks before and after polluted by filtrate of oil-based drilling fluids are shown in Table 5. According to “Determination of reservoir rock wettability” form Chinese oil industry standards, when the contact angle is between 0 and 75 , the rock wettability is hydrophilicity, when the contact angle is between 75 and 105 , the rock wettability is intermediate wettability. Furthermore, when the contact angle is about 60 , the wettability is weak hydrophilicity according to the instrument description of contact angle tester. Although two kinds of oil-base drilling fluids didn't cause wettability reversal, the wettability of hydrophilic reservoir surface was changed in a large part, which was transformed from hydrophilicity to weak hydrophilicity or intermediate wettability. Wettability is an important factor in controlling the location, flow and distribution of reservoir fluids in porous media. The transformation could lead to an increase of gas phase flow resistance and an accelerated adsorption of solid particles and emulsion on the surface. 3.3.2. Oil phase trapping It should be pointed out that oil phase trapping and oil blocking are different, the damage caused by the former happens mainly in the process where liquid phase saturation increases from the initial saturation to irreducible saturation, when the saturation increases to more than the irreducible saturation, at this point the damage to reservoirs is oil blocking damage in the traditional sense. The result of core flow test is shown in Fig. 1. Obviously, core permeability lowered along with the increasing saturation of oil and the final damage rate of permeability was 97.1% when the oil saturation was close to 100%. The initial liquid phase saturation and the bound liquid phase saturation in the B block were 14.24% and 40% respectively, so the damage rate of oil phase trapping was 61.21% belonging to moderate to strong damage according to “Formation damage evaluation by flow test” form Chinese oil industry standards. Therefore, the initial liquid phase saturation was lower than the irreducible liquid phase saturation in the tight gas reservoir, when the filtrate of oil-based drilling fluid invaded the reservoir, the micron-nano-sized pore throats and micro-fractures would
Fig. 1. Result of oil blocking damage on rock core in B Zone. 620
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
Fig. 2. Emulsion droplets of mixed oil based filtrate and formation water. Note: The large black particles in the figure were the solid phase in the filtrate.
in the B block and the baseline of fractures in Well B2 respectively, these particles could achieve the ideal filling of the pore throats and part of the micro-fractures. Therefore, the CaCO3 particles of 1000 mesh and that of 325 mesh were compounded at a proportion in quality of 79%: 21% by calculation, the optimized curve and the baseline were shown in Fig. 5. The optimized curve was on the right side of the baseline slightly, so the compound temporary plugging agent could realize ideal packing considering particle attrition under the shearing effect. And the mass/ volume fraction of compound temporary plugging agent is usually 3% in drilling fluid form experience. Further, the compound temporary plugging agent was added into the oil-based drilling fluids at a mass/volume fraction of 3%, and then the dynamic pollution experiment was conducted to evaluate the permeability recovery rate. The results listed in Table 6 show that the permeability recovery rates of the optimized INVERMUL oil-based drilling fluid and traditional oil-based drilling fluid were respectively 87.4% and 86.74%. The compound temporary plugging agent could form tight temporary mud cakes on the surface of rocks, avoiding a deep invasion of the solids and liquid phase in the drilling fluid and subsequent fluid efficiently.
structure and concentration of used surfactants as well as inorganic ions, pH value, temperature, pressure and rock type (Yan, 1993; Feng et al., 2014). After demulsification the emulsion will divide into oil-water two phases. The oil phase can invade pore throats and micro-fractures and form oil trapping damage. Meanwhile, as the third phase introduced into gas reservoir, the gas-oil-water three phase flow state will occur near the wellbore even in the throats, resulting in an additional three phase resistance. And oil is a non-wetting phase in hydrophilic reservoir, forming clusters and dispersing in the middle of the seepage channel, causing a significant decline in reservoir permeability (Bennion and Ma, 2000). The effect of multiphase flow is shown in Fig. 3. 3.4. Results of optimization 3.4.1. Result of ideal packing technology From the results of solids damage in section 3.2, the maximum diameter of pore throats was 3.0237 μm in Well B1 and 1.9613 μm in Well B2, averaging 2.5988 μm; the maximum width of fractures was 4.39 μm in Well B1 and 70.9 μm in Well B2. According to the data the baseline was drawn in Fig. 4, and the particle diameter distributions of calcium carbonate particles in four sizes were tested and also drawn in Fig. 4. The main parts in the curves of four kinds of CaCO3 particles were close to a straight line, which was a necessary condition for the ideal packing. However, a single temporary plugging agent couldn't realize ideal packing due to the large difference between four curves and the baseline. The curves of CaCO3 particles of 1000 Chinese common-used mesh and that of 325 mesh were closest to the baseline of pore throats
3.4.2. Results of surfactant optimization The contact angles of five different surfactant solutions on the surface of reservoir rocks are shown in Fig. 6. The contact angles of these surfactant solutions were all lower than that of simulated formation water, and the ability of reducing surface tension was strong. Among them, the surfactant Tween80 (Fig. 6c) was the best. The interfacial tensions between surfactant solutions and diesel measured at the temperature of 40 C and a constant rotation rate of 600 rpm are listed in Table 7. The product of σ and cosθ of surfactant SDBS was lowest and it could reduce capillary pressure effectively and relieve the damage of oil phase trapping. Therefore, surfactant SDBS was optimized to conduct the following experiments. The INVERMUL oil-based drilling fluid was selected singly to evaluate the cleaning efficiency of the optimized surfactant SDBS in order to enhance contrast. The results of cleaning effect of oil-based filtrate cakes under the conditions of static and dynamic state are shown in Table 8 and Fig. 7. Under the static condition, the cleaning efficiency reached the highest value after the filtrate cakes were soaked for 3 min (Fig. 7b). With the soaking time extended, the emulsion on the surface of filtrate cake was destroyed completely while the solid-phase cementing structure was almost intact (Fig. 7c, d, e). Under the dynamic condition, the cleaning efficiency improved obviously, the emulsion on the surface of filtrate
Fig. 3. The effect of multiphase flow diagram. Ⅰ- Single gas phase flow; Ⅱ- Gas-water twophase flow; Ⅲ- oil-gas-water three-phase flow. 621
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Fig. 4. Particle size distributions of CaCO3 particles with different particle sizes.
Fig. 5. Optimized temporary plugging curve of CaCO3 particles.
Similarly, the emulsion was prepared by mixing filtrate of INVERMUL oil-based drilling fluid with simulated formation water at the proportions of 1:1 and 1:2, and then the optimized surfactant SDBS was added into it and the observation results of demulsification was shown in Table 9 and Fig. 8. The emulsion could be formed by stirring the mixture of oil-based filtrate and formation water under the effect of emulsifiers in filtrate and natural formation. It was an unstable thermodynamic system and could separate into layers at a static state, while the separate time was long and the interface wasn't clear. And the more aqueous phase was, the shorter the separate time was, that was the reason why large amount of surfactant solutions were used for well washing. After the optimized surfactant SDBS was used, the separate time became shorter and the interface was clearer. There was more separate aqueous phase with fewer oil droplets in it. So the surfactant SDBS could remove the damage of emulsion plugging. By the analysis above, the optimized surfactant SDBS could destroy the emulsion on filtrate-cake surface and the mixture of oil-based filtrate and formation water, as well as the solid-phase cementing structure. So it could remove the damage of emulsion plugging and promote liquid phase
Table 6 Results of permeability recovery rate contaminated by optimized oil-based drilling fluids. Core
3#
4#
Treatment liquid
Optimized INVERMUL oil-based drilling fluid Optimized traditional oil-based drilling fluid
Permeability (103 μm2)
Dynamic filtration loss (mL)
permeability recovery rate(%)
0.02401
0
87.40
0.02109
0
86.74
Before the contamination
After the contamination
0.02747
0.02431
cake was destroyed in 3 min (Fig. 7g), and the solid-phase cementing structure was destroyed a lot with the time extended (Fig. 7h). Thus the optimized surfactant SDBS could help clean the oil-based cakes and then the gas permeability would increase to a certain extent. 622
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Fig. 6. The contact angles of five different surfactant solutions. Table 7 Optimization results of surfactants. Surfactant solutions
0.4% OP-10
0.4% Tween80
0.4% CTAC
0.4% Imidazoline
0.4% SDBS
Interfacial tensions (mN/m) σ*cosθ
1.18 0.98
2.88 2.43
1.09 0.89
2.20 1.86
0.80 0.67
flow back efficiently. In order to evaluate the effect on gas permeability recovery rate, the cores 1# and 2# that had already contaminated by oilbased drilling fluids were prepared, and the gas permeability of them was measured in the same way introduced in section 2.2.1 while the treatment liquid was replace by optimized surfactant SDBS solution. The results are presented in Table 10. The tested values of permeability recovery were more than 100% after treated by surfactant SDBS solution. The surfactant cleaned polluted section on the surface of cores and destroyed the emulsion inside the cores with plenty of water. Finally, the
Table 8 Oil-based cake cleaning efficiency. Speed (rpm)
Time (min)
Cleaning efficiency (%)
0 (soaking)
3 6 10 15 3 15
5.05 5.78 6.14 6.50 21.50 44.24
600
Fig. 7. Diagram of oil-based cake cleaning effect. 623
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Table 9 Demulsification of emulsion formed by oil-based filtrate and formation water. Volume ratio of filtrate and formation water
Separate time of oil-water (s) Without surfactant
0.4%w/v SDBS
Without surfactant
0.4%w/v SDBS
1:1
Separate time was 80.74s, and the interface wasn't clear Separate time was 54.74s, and the interface was relatively clear
Separate time was 18s and totally separated at 80s, the interface was clear Separate time was 44.14s, and the interface was clear
An average of 8.31
Visible oil-in-water droplet
1:2
Droplet size (μm)
Couldn't be observed due to too many bubbles
Fig. 8. Demulsification effect of emulsion formed by oil-based filtrate and formation water. Table 10 Permeability recovery rate of contaminated cores treated by surfactant solution. Cores
Treatment liquid
1# 2#
0.4% w/v SDBS 0.4% w/v SDBS
Permeability (103 μm2) Before the treatment
After the treatment
0.00777 0.00740
0.01424 0.01033
Dynamic filtration loss (mL)
permeability recovery rate(%)
0.2 0.5
183.27 139.59
Note: The difference for initial permeability of Core 1# (0.00902 in Table 1 and 0.00777 here) is because the delay of test of Core 1# and re-measure permeability.
(3) The optimized surfactant SDBS could destroy the emulsion on filtrate-cake surface and the mixture of oil-based filtrate and formation water, as well as the solid-phase cementing structure. So it could remove the damage of emulsion plugging and promote liquid phase flow back efficiently. The values of permeability recovery were more than 100% after treated by surfactant SDBS solution.
damage of emulsion plugging was removed and the gas permeability got promotion. 4. Conclusions (1) Through laboratory tests, the size matching relationship between solid particles in oil-based drilling fluids in site and fractures in the B block was poor so the solid particles couldn't seal fractures effectively, resulting in solid particles invaded reservoir through micro-fractures deeply and eventually causing serious permeability reduction around the natural fractures. Furthermore, the invasion of oil-based filtrate could transform reservoir wettability from hydrophilicity to weak hydrophilicity or intermediate wettability, leading to an increase of gas phase flow resistance. And the severe oil phase trapping damage occurred inevitably once the filtrate invaded the tight reservoir, the damage rate of which reached 61.21%. Meanwhile, the emulsion droplets formed by mixing the oil-based filtrate with the formation water were about 8 μm in size, and the emulsion had difficulty in demulsification, easily causing emulsion plugging damage and effect of multiphase flow. These main damage mechanisms caused a poor protection effect of oil-based drilling fluid in tight sandstone reservoirs, and the permeability recovery rates of two kinds of oilbased drilling fluids used in site were both less than 60% (2) By the Ideal Packing Theory, a temporary plugging agent was designed with calcium carbonate particles of 1000 mesh and that of 325 mesh at a proportion in quality of 79%: 21% and it could effectively plug the pore throats and micro-fractures, avoiding a deep invasion of the solids and filtrate. The permeability recovery rates of the optimized oil-based drilling fluid with the temporary plugging agent in were more than 85%.
Acknowledgments This work was financially supported by Program for Changjiang Scholars and Innovative Research Team in University (IRT_14R58). References Ai, G., Liu, M., Zhang, L., 2006. The application of the "ideal packing Theory"-90 empirical rule in well Kun-2. Drill. Fluid & Complet. Fluid 23 (5), 14–17. Andrews, J.T., Bahrami, H., Rezaee, R., et al., 2012. Effect of Liquid Invasion and Capillary Pressure on Wireline Formation Tester Measurements in Tight Gas Reservoirs. SPE, p. 154649. Bahrami, H., Rezaee, M.R., Ostojic, J., et al., 2011. Evaluation of Damage Mechanisms and Skin Factor in Tight Gas Reservoirs. SPE, p. 142284. Bahrami, H., Rezaee, M.R., Clennell, Ben, 2012a. Water blocking damage in hydraulically fractured tight sand gas reservoirs: an example from Perth Basin, Western Australia. J. Petroleum Sci. Eng. 88–89 (2), 100–106. Bahrami, H., Rezaee, R., Saeedi, A., et al., 2012b. Phase Trapping Damage in Use of Water-based and Oil-based Drilling Fluids in Tight Gas Reservoirs. SPE, p. 15468. Bennion, D., Ma, T., 2000. Formation Damage Processes Reducing Productivity of Low Permeability Gas Reservoir. SPE, p. 60325. Bennion, D.B., Bietz, R.F., Thomas, F.B., et al., 1994. Reduction in productivity of oil and low permeability gas reservoirs due to aqueous phase trapping. J. Clin. Pharm. Ther. 33 (9), 45–54. Bennion, D.B., Bietz, R.F., Thomas, F.B., et al., 2000. Low Permeability Gas Reservoirs and Formation Damage -Tricks and Traps. SPE, p. 59753. Cui, Y., 2012. Evaluation research on reservoir damage of oil-based drilling fluid. Drill. Fluid & Complet. Fluid 29 (3), 13–15. 624
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Feng, L., Zhang, J., Ma, T., 2014. REMOVEMENT technology of emulsification clogging and its application in the offshore well. Drill. Prod. Technol. 37 (4), 91–93. Geng, J., Yan, J., Li, Z., et al., 2010. Mechanisms and Prevention of Damage for Formations with Low-porosity and Low-permeability. SPE, p. 130961. Huang, T., Clark, D.E., 2012. Advanced Fluid Technologies for Tight Gas Reservoir Stimulation. SPE, p. 160844. Kang, Y., Yang, B., You, L., et al., 2013. Damage evaluation of oil-based drill-in fluids to shale reservoirs. Nat. Gas. Ind. 33 (12), 99–104. Loghry, R.A., Nguyen, P.D., Mock, B.D., et al., 2013. Evaluating Treatment Methods for Enhancing Microfracture Conductivity in Tight Formations. SPE, p. 167092. Oluyemi, G., 2011. Investigation of Depletion Induced Formation Damage Mechanisms in Fractured Reservoirs. SPE, p. 143985. Pan, Y., Fu, L., Yang, S., 2014. Research progress of oil-based drilling fluid at home and abroad. Mod. Chem. Ind. 34 (4), 21–24. Qutob, Hani, Byrne, Micheal, 2015. Formation Damage in Tight Gas Reservoirs. SPE, p. 174237. Reinicke, A., Rybacki, E., Stanchits, S., et al., 2010. Hydraulic fracturing stimulation techniques and formation damage mechanisms-Implications from laboratory testing of tight sandstone-proppant systems. Chem. Erde 70 (3), 107–117. Rickman, R., Jaripatke, O., 2010. Optimizing Microemulsion/Surfactant Packages for Shale and Tight-Gas Reservoirs. SPE, p. 131107.
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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
The damage mechanism of oil-based drilling fluid for tight sandstone gas reservoir and its optimization Ming Lei a, b, Wei'an Huang a, *, Ning Li c, Jiang'hong Jia d, Jia'xue Li c, You'wei Wang a, Jing'ye Li a a
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong, 266580, China Tarim Oil Field Branch Company of PetroChina, Korla, Xinjiang, 841000, China Research Institute of Oil and Gas Engineering, Tarim Oilfield Division, Korla, Xinjiang, 841000, China d Research Institute of Drilling Technology, Sinopec Shengli Petroleum Engineering Co., Ltd., Dongying, Shandong, 257017, China b c
A R T I C L E I N F O
A B S T R A C T
Keywords: Tight gas reservoir Oil phase trapping Emulsion plugging Oil-based drilling fluid The B block in tarim basin
The B block is a typical tight sandstone gas reservoir in Tarim basin in the Xinjiang Uygur Autonomous Region, China. In this block, the skin factors of each well drilled by oil-based drilling fluids were high and the reservoir damage was serious. The permeability recovery rates of two kinds of oil-based drilling fluids used in site were both less than 60%. To investigate the damage mechanism, the particle size distribution was tested to analyze solids damage incorporating the pore throat radius and micro-fracture width in this block. The contact angles of deionized water on reservoir cores before and after polluted by oil-based filtrate were measured to analyze the wettability alteration. Core flow experiment was applied to evaluate oil phase trapping, and the emulsion droplets formed by mixing oil-based filtrate with formation water were observed to analyze emulsion plugging damage. Based on the test results, the factors causing damage to the tight sandstone gas reservoir included solid phase invasion to fractures, wettability alteration, oil phase trapping and emulsion plugging. Therefore, the oil-based drilling fluids were optimized from aspects of reduction of the filtration loss, improvement of the sealing ability of the micro-fractures and reduction of the oil-water interfacial tension. A temporary plugging agent was compounded by using the Ideal Packing Theory, which could effectively plug the microfractures. The surfactant was optimized, and it could destroy the oil-based filtrate cake effectively and break emulsion in a short time. The permeability recovery rate of optimized oil-based drilling fluids was evaluated and the results showed that permeability recovery rate was 87.40% and 86.74%. Furthermore, cores early contaminated by oil-based drilling fluid were treated by optimized surfactant, and the tested permeability recovery rate reached more than 100%.
1. Introduction Tight sandstone gas reservoirs are rich in resources and the world's tight gas 1 resources distributed in many basins around the world amounted to 114 trillion cubic meters. The tight gas recoverable resources in China amounted to 9–13 trillion cubic meters, accounting for about 22% of the national natural gas recoverable resources according to the data from Chinese Academy of Engineering. Tight sandstone gas reservoir is an important oil and gas exploration area in the future and has a good development prospect. However, tight sandstone gas reservoir is one type of unconventional gas reservoir where natural gas is enriched in sandstone with low porosity (less than 10%) and low permeability (less than 0.1 103 μm2), which usually characterized by high capillary force, high irreducible water saturation, a tiny size of pore throats, severe
heterogeneity and abundant micro-fractures (Reinicke et al., 2010; Geng et al., 2010; Zhang et al., 2008; Andrews et al., 2012). Thus, it is harder to develop by conventional technology and easier to be damaged during drilling and gas production. Liquid phase trapping is one of the most serious damage factors in this kind of gas reservoirs. On condition that the initial water saturation is generally lower than the irreducible water saturation in tight sandstone gas reservoirs, the serious liquid phase trapping can be formed by self-absorption and retention of the filtrate under the effect of relative permeability and potential capillary pressure. The damage degree of liquid phase trapping is influenced by the capillary pressure and the initial water saturation, and it is also related to the quality of the mud cake (Bennion et al., 1994, 2000; Rickman and Jaripatke, 2010; Bahrami et al., 2011; 2012a,b; Zhang et al., 2012). Meanwhile, tight sandstone gas reservoirs are formed accompany with
* Corresponding author. School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong, 266580, China. E-mail addresses: [email protected] (M. Lei), [email protected] (W. Huang). http://dx.doi.org/10.1016/j.petrol.2017.09.003 Received 10 May 2017; Received in revised form 27 August 2017; Accepted 6 September 2017 Available online 6 September 2017 0920-4105/© 2017 Elsevier B.V. All rights reserved.
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sensitivity. Summarily, Wang et al. (2014) proposed the protection status of tight gas reservoir as follows: ①although the surface tension of oil is lower than that of water, oil-based drilling fluid filtrate could be also adsorbed and retained after entering the gas reservoir; ②the change in wettability would increase the flow resistance of natural gas in the percolation channel, adversely affecting gas well production; ③oil-based filtrate invasion resulted in the change of reservoir from the original gas and water flow to gas, water, oil three-phase flow, and oil is a non-wetting phase, gathering into a mass in the middle of the percolation channel, reducing gas effective permeability. The B block is located in the Kelasu tectonic belt of Kuche depression in Tarim basin where the reservoir porosity is distributed between 1% and 9.4% with an average of 6.8% and the permeability is distributed between 0.011 103 μm2 and 8.56 103 μm2 with an average of 0.19 103 μm2. The B block belongs to a typical low permeability tight gas reservoir with low porosity, low permeability and serious heterogeneity. The skin factors of each well drilled by oil-based drilling fluids were high generally distributed between 5 and 20 and the reservoir damage was serious according to well testing interpretation. Thus, the objective of this study is to investigate main damage mechanism of oilbased drilling fluid in a certain tight sandstone gas reservoir in the B block, through testing permeability recovery rates of reservoir cores and analyzing the effect of solid phase and liquid phase on reservoir. Eventually, the oil-based drilling fluids are optimized from the aspect of ideal packing technology, oil-based filtrate cake removal, and demulsification of oil-based filtrate.
fractures in general. Fractures are sensitive to stress and once the effective stress reaches a critical value, fractures tend to contact even close, leading to crushing of the rocks then solid plugging damage occurs with aggregation of particles in the gas flow (Oluyemi, 2011). In addition, if particles in the drilling fluids could not form bridging or shielding at the fractures entrance, solid and liquid phase would invade into reservoir through micro-fractures deeply due to leakage of drilling fluids into natural fracture system or adsorption of polymer residue on fracture surface, causing severe damage to fractures and matrix (Huang and Clark, 2012; Loghry et al., 2013). Tight sandstone gas reservoirs are susceptible to various damages while oil-based drilling fluids are widely used in tight sandstone gas reservoir in Tarim basin in recent years, because oil-based drilling fluids possess the advantages of strong inhibition of shale, high temperature resistance, low formation damage, good lubrication performance and strong corrosion resistance (Zhang et al., 2015). At present, there are several main types of the oil-based drilling fluid including whole oil-based drilling fluid, low toxicity oil-based drilling fluid, high temperature resistant oil-based drilling fluid, and reversible emulsion drilling fluid. Many studies on oil-based drilling fluid treating agents have been conducted aimed at issues of oil-based drilling fluid such as sedimentation stability, emulsion stability and contamination of drilling cuttings to drilling fluid (Wang, 2011; Pan et al., 2014). Nevertheless, more and more researches’ results show that oil-based drilling fluid can also cause some damage to the oil and gas reservoirs. The basic compositions of oil-based drilling fluid are base oil, emulsifier, wetting agent, water phase and lipophilic colloid which are all potential factors causing reservoir damage. The organic bentonite is a lipophilic bentonite modified from bentonite by surfactant, so it presents as finely dispersed particle in oil phase that can easily invade into pore throats and seepage channel (Thomas et al., 1984). The wetting agent can cause wetting reversal and transform wettability on rock surface from hydrophilicity to lipophilicity, accordingly, the oil phase and lipophilic colloid are more easily attached to the surface of the pore throats, reducing effective gas flow area (Cui, 2012; Qutob and Byrne, 2015). The formation water and oil phase can easily form emulsion under the effect of emulsifier that may damage reservoirs by plugging pore throats and fractures (Wang, 2012; Qutob and Byrne, 2015). Currently, there are a few researches on damage mechanism of oil-based drilling fluids in tight sandstone gas reservoirs. Bahrami et al. (2012a,b) believed that the filtrate of oil-based mud might result in introduction of an immiscible liquid in tight gas reservoir drilled by oil-based drilling fluids, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. And Zhang et al. (2015) attributed the main factors of oil-based drilling fluids damaging tight gas reservoir to solids plugging, multi-phase flow effect, wettability reversal and emulsion plugging through laboratory experiments. Similarly, Kang et al. (2013) evaluated the damage of oil-based drilling fluid to a shale gas reservoir and confirmed the primary damage mechanisms of oil-based drilling fluid were solid phase invasion, oil trapping, alkaline damage, stress
2. Experimental methods 2.1. Equipment and materials Experimental equipment includes drilling fluid pollution instrument YBH-1 manufactured by Meter Factory of University of Petroleum, low permeability core flow testing apparatus DSRT-II developed by Yangtze University, laser particle size analyzer Bettersize2000 produced by Bettersize Instrument Co., Ltd, scanning electron microscope S-4800 produced by HITACHI, polarizing microscope ISH500 produced by FENYE Optoelectronic Equipment Co., Ltd, surface tension detector BZY-1 produced by PINGXUAN Scientific Instrument Co., Ltd, contact angle tester JC2000D5M produced by POWEREACH Industrial Limited. Two kinds of experimental oil-based drilling fluids were respectively INVERMUL oil-based drilling fluid collected from Well B2-2-20 and traditional oil-based drilling fluid collected form Well B105. The important mud properties of two oil-based drilling fluids were listed in Table 1. Natural cores were collected from Well B2 at depth of kelly bushing between 6781.5 m and 6865.5 m and rock fragments used for analysis of mercury, surface properties and scanning electron microscope were collected from Well B1 at depth between 6917.5 m and 6924.2 m as well as Well B2 at depth between 6770 m and 6773 m.
Table 1 Properties of two kinds of oil-based drilling fluids. INVERMUL oil-based drilling fluid
Type Properties
After aging(140 C/16 h)
Before aging Plastic viscosity (mPa⋅s) Yield point (Pa) Gel 1000 /Gel 100 (Pa) FLAPI(mL) FLHTHP(mL) ρ(g/cm3) pH lubricating property Sedimentation stability
Sticking factor of mud cake Lubrication factor Density difference (g/cm3) Note
traditional oil-based drilling fluid Before aging
70 69 56 7.5 5.5 7 3.5/8 3.5/8.5 3/6 0.1 0 0 3 1.2 1.91 1.81 8 8 0.0262 0.0349 0.1322 0.1325 0.021 0.009 Let drilling fluids stand for 24 h and test density upper and lower layers
617
After aging(140 C/16 h) 38 3 2.25/2.5 0
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
on the contaminated surfaces were tested and compared with the previous result.
The surfactants including polyoxyethylene octylphenol ether (OP10), sorbitan monooleate polyoxyethylene ether (Tween80), cetyl trimethyl ammonium chloride (CTAC), imidazoline, sodium dodecyl benzene sulfonate (SDBS) applied in the experiment were all analytical reagents and produced by Sinopharm Chemical Reagent Co., Ltd, and calcium carbonate powder of different specifications also made by Sinopharm Chemical Reagent Co., Ltd were prepared.
2.2.4. Evaluation method of oil phase trapping The oil phase trapping damage was evaluated by using a low permeability core flow testing apparatus in the light of the reference of “Formation damage evaluation by flow test” form Chinese oil industry standards published in 2010. Details of the specific experimental steps were as follows: ①a piece of core was oven-dried to a constant weight after washing and then saturated with kerosene to the initial oil saturation; ②the core gas permeability in initial oil saturation recorded as K0 was tested; ③the core gas permeability in different oil saturation recorded as Ki was tested with kerosene squeezed into the core; ④The core permeability damage rate recorded as DWF could be calculated by the following equation:
2.2. Methods of damage mechanism of oil-based drilling fluids 2.2.1. Evaluation method of the damage degree Refer to “Lab testing method of drilling and completion fluids damaging oil formation” form Chinese oil industry standards published in 2002, the drilling fluid pollution instrument was selected to evaluate the dynamic damage degree of tight gas formation by oil-based drilling fluid. Details of the specific experimental steps were as follows: ①two sets of cores recorded as 1# and 2# respectively were oven-dried to a constant weight after washing by methylbenzene and ethanol, then saturated with formation water above 24 h in a vacuum environment, finally the backup cores were placed in a humid environment; ②the irreducible water saturation of cores was built with unsteady-state gas drive lasting for 2 h under constant confining pressure of 3 MPa and displacement pressure of 2 MPa; ③the core gas permeability in the bound water state was taken as the initial value recorded as K0; ④the cores were respectively contaminated by two kinds of oil base drilling fluids used in the B block for 125 min at a high temperature of 120 C, a constant differential pressure of 3.5 MPa and a constant shear rate of 170 s1, meanwhile, dynamic filtration at different time was record; ⑤the contaminated core gas permeability recorded as K1 was tested after displaced for an hour at a constant nitrogen gas pressure of 2 MPa. The permeability recovery rate recorded as R could be calculated by the following equation:
R¼
K1 100% K0
DWF ¼
jKi K0 j 100% K0
(2)
Where, DWF is the permeability damage rate in %; K0 is the gas permeability in initial oil saturation in 103 μm2; Ki is the gas permeability in irreducible liquid phase saturation in 103 μm2 when we need the damage rate of oil phase trapping. 2.2.5. Evaluation method of emulsion plugging The emulsion was prepared by mixing filtrate of oil-based drilling fluid with simulated formation water at different proportions and then observed under a polarizing microscope. The size of emulsion droplet was measured and accordingly, the emulsion plugging damage was evaluated. 2.3. Methods of optimization of oil-based drilling fluids Based on the problems of poor reservoir protection effect of oil-based drilling fluids, the oil-based drilling fluids should be optimized from aspects of reduction of the filtration loss, improvement of the sealing ability of the micro-fractures and reduction of the oil-water interfacial tension. A. With the principle of equal emphasis on the protection of matrix and fracture, oil-soluble calcium carbonate particles with reasonable particle size distribution should be selected by Ideal Packing Theory to form a compact mud cake with very low filter loss which can avoid invasion of the solids and filtrate. B. The surfactant should be optimized to reduce interfacial tension between oil and water effectively and prevent or remove the oil phase trapping damage in time as well as destroy the emulsion in the reservoir.
(1)
Where, R is the permeability recovery rate in %; K0 is the initial gas permeability in 103 μm2; K1 is the contaminated core gas permeability in 103 μm2. 2.2.2. Evaluation method of solids damage First, the particle size distributions of two kinds of oil based drilling fluids were measured with a laser particle size analyzer, as well the average pore throat diameter and maximum pore throat diameter of reservoir in the B block were calculated by a mercury intrusion test and the size of micro-fractures was measured by scanning electron microscope. Then the solids damage was judged according to the theory of shielding temporary plugging which believed that when median grain diameter of the temporary plugging particles is equal to or slightly larger than 1/3 times (the best is 2/3 times) of the average pore diameter of throats based on overbalanced drilling process, a good temporary plugging zone can be formed.
2.3.1. Optimization method of ideal packing technology In the Ideal Packing Theory, when the cumulative volume fraction of temporary plugging agent particles is proportional to the square root of the particle diameters, an ideal filling of the particles can be realized. Based on that, the D90 rule of thumb was proposed for implementation in site which believed that an ideal filling could be achieved when the D90 value (90% of the particles have a diameter less than this value) of the temporary plugging agent on the cumulative distribution curve is equal to the maximum diameter of pore throats or the maximum width of fractures (Ai et al., 2006; Zheng et al., 2009; Wang et al., 2007). And a baseline is defined as the connection of origin and D90 value which is a crossover point of maximum size of pore throats or fractures and 90% of the volume fraction, intuitively, the closer the curve about cumulative volume fraction and the square root of the temporary plugging particles diameters is to the baseline, the better the temporary plugging effect is. The particle diameter distributions of calcium carbonate particles in different sizes were tested by a laser particle size analyzer, and compared the result with sizes of pore throats and fractures introduced in section 2.2.2. The calcium carbonate particles were compounded according to
2.2.3. Evaluation method of wettability The influence of oil-based drilling fluid on the wettability was evaluated by measuring the contact angles of deionized water on the surface of reservoir rocks with a contact angle tester. Details of the specific experimental steps were as follows: ①the surfaces of three pieces of rocks selected from the B block at the same depth were polished until smooth with a fine sandpaper, and then the rock samples were oven-dried for preparation after boiled for 5 min in the sodium hydroxide solution at a concentration of 5%; ②the contact angle of the simulated formation water on the first rock specimen surface was tested with a contact angle tester; ③the surfaces of the second and third rock samples were polluted respectively by filtrates of two kinds of oil-based drilling fluids and airdried; ④likewise, the contact angles of the simulated formation water 618
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the Ideal Packing Theory and the D90 rule. Details of the specific experimental steps were as follows: ①the curve about the square root of the particle diameters and the cumulative volume fraction was drawn according to the particle size distributions; ②according to the maximum diameter of pore throats and the maximum width of fractures, drew a baseline; ③the curve of particle diameter distributions of calcium carbonate particles was compared with the baseline and the calcium carbonate particles with suitable size were selected and compounded at a calculated proportion; ④the compound temporary plugging agent was added into two kinds of oil-based drilling fluids and the permeability damage rates were evaluated with the method in section 2.2.1.
A¼
4μL2 r 2 P 2rσ cos θ
(4)
Where, A is the cleaning efficiency in %; G0 is the quality of filter paper in gram; G1 is the quality of filtrate cake and filter paper in gram; G2 is the quality of filtrate cake and filter paper after cleaning in gram. 3. Results and discussion 3.1. Analysis of damage degree of the oil-based drilling fluids The results of permeability recovery rate listed in Table 2 show that the permeability recovery rates of INVERMUL oil-based drilling fluid and traditional oil-based drilling fluid were respectively 54.17% and 57.36%, both were less than 60%. The dynamic filtration losses were both 0 mL in whole process indicating that the filtrate hardly passed through the tight rocks, thus any clogging of whether the solids or filtrate, even to a small extent, could cause serious damage to the pore throats and micro-fractures inside the rock. The protection effect of oilbased drilling fluids is not ideal in the tight gas reservoir in the B block. The reasons why oil-based drilling fluids doing serious harm to the tight gas reservoir might be caused by various factors, in this paper, the damage mechanism of oil-based drilling fluids was analyzed from solids invasion and filtrate invasion.
2.3.2. Optimization methods of surfactant In tight gas reservoirs, the filtrate could invade formation inevitably with the existence of surplus capillary pressure and the damage of oil phase trapping and emulsion plugging was produced subsequently. Besides, the oil-based filtrate cake was difficult to remove and filtrate was hard to flow back. Thus the surfactant was optimized to reduce capillary force, destroy the emulsion on filtrate-cake surface and the mixture of oilbased filtrate and formation water, as well as the solid-phase cementing structure. According to the kinetic equation of liquid blocking effect, in hydrophilic strata, the time a liquid flowed through a capillary tube could be calculated by the following equation from the transformation of Poiseuille Law:
t¼
G1 G2 100% G1 -G0
(3)
3.2. Analysis of solids damage
Where, t is the time a liquid flowed through a capillary tube in s; μ is the liquid viscosity in Pas; L is the length of liquid column in m; P is the driving pressure differential in Pa; r is the radius of capillary tube; σ is the oil-water interfacial tension in N/m; θ is the contact angle of liquid on surface of capillary tube in . In the equation, the values of r, L, μ and P are all constant in a certain reservoir so the product of σ and cosθ can be the index for surfactant optimization. The smaller the product of σ and cosθ is, the lower the capillary pressure is, and the more easily the liquid flows back. The research method was as follows: ①the contact angles recorded as θ of different surfactant solutions on the surface of reservoir rocks were tested, and the interfacial tensions recorded as σ between surfactant solutions and diesel were measured; ②the surfactant was optimized through a comparison of the product of σ and cosθ; ③two pieces of filtrate cakes of oil-based drilling fluid were prepared, one of which was fixed to the outer cylinder of a six-speed rotational viscometer and rotated under a certain speed for certain time within the optimized surfactant solution, and the other one was soaked in the optimized surfactant solution for different time. The cleaning efficiency of the optimized surfactant recorded as A could be calculated by equation (4); ④the emulsion was prepared by mixing filtrate of oil-based drilling fluid with simulated formation water at the proportions of 1:1 and 1:2, then the optimized surfactant was added into it and the demulsification of emulsion was analyzed by observing and recording the separate time of oil-water, clarity of interface and the size of emulsion droplets; ⑤the cores (1#, 2#) were treated by the optimized surfactant at a high temperature of 120 C and a constant differential pressure of 3.5 MPa, then the permeability recovery rates of these two cores were measured.
The oil-based drilling fluid has strong inhibition performance of shale so the solids damage is mainly manifested in the invasion of solid particle in oil-based drilling fluid and drilling debris. The main particle size values of two kinds of oil-based drilling fluids are presented in Table 3. The contents of solid particles whose diameter was less than 5 μm and between 5 μm and 30 μm were about 50%vol and 40%vol respectively in INVERMUL oil-based drilling fluid. In accordance with the theory of shielding temporary plugging, the solid particles could form temporary plugging on the surface of pore throats and microfractures whose diameters were less than 20 μm. Similarly, in traditional oil-based drilling fluid, the contents of solid particles whose diameter was less than 3 μm and between 3 μm and 10 μm were about 50%vol and 40%vol respectively, theses solid particles could seal pore throats and micro-fractures whose diameter was less than 9 μm. The statistical information of pore throats and micro-fractures in Well B1 and Well B2 is listed in Table 4 from the analysis of intrusive mercury experiment and scanning electron microscope. The pore throat diameter of tight sandstone was tiny, and the solid particles of two kinds of oilbased drilling fluid could effectively plug the pore throats, avoiding a deep invasion of the solids and filtrate. However, the average size of micro-fractures in Well B2 was large, reaching 23 μm. The size matching relationship between solid particles in oil-based drilling fluids and fractures was poor and the content of effective solid particles was Table 3 The main particle size value of oil-base drilling fluid. Type
D10(μm)
D50(μm)
D90(μm)
INVERMUL oil-based drilling fluid traditional oil-based drilling fluid
1.139 0.897
5.915 2.830
27.694 10.473
Table 2 Results of permeability recovery rate contaminated by oil-based drilling fluids. Core
1# 2#
Treatment liquid
INVERMUL oil-based drilling fluid traditional oil-based drilling fluid
Permeability (103 μm2) Before the contamination
After the contamination
0.01665 0.01290
0.00902 0.00740
619
Dynamic filtration loss (mL)
permeability recovery rate(%)
0 0
54.17 57.36
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Table 4 Pore throats and micro-fractures information in the B block. Well
Horizon
Average diameter of pore throats (μm)
Maximum diameter of pore throat (μm)
Average width of micro-fractures (μm)
Maximum width of micro-fractures (μm)
B1 B2
K1bs K1bs
0.6269 0.5683
3.0237 1.9613
1.2595 23.1185
4.39 70.9
insufficient, so the solid particles couldn't seal fractures effectively, resulting in solid particles invaded reservoir through micro-fractures deeply under the positive differential pressure. The tight sandstone gas reservoir is severe heterogeneous with great difference in the width of micro-fractures. Two kinds of oil-based drilling fluids used in site were limited because they could temporarily plug the pore throats while couldn't plug the fractures with large width. So the solid particles could invade reservoir deeply and easily attach to the surface of the pore throats because of the containment of a large number of lipophilic bentonite in oil-based drilling fluids.
Table 5 Effect of oil-based drilling fluid on reservoir wettability under room temperature. Soaking medium
Contact angle ( )
Wettability
Simulated formation water Filtrate of INVERMUL oil-based drilling fluid Filtrate of traditional oil-based drilling fluid
39.86 58.73
hydrophilicity weak hydrophilicity
81.20
intermediate wettability
capture filtrate of oil-based drilling fluid seriously, and eventually the oil trapping damage would come into being inevitably as the oil droplets plugged pore throats and micro-fractures under strong capillary forces.
3.3. Damage of filtrate invasion
3.3.3. Emulsion plugging and the effect of multiphase flow The filtrate of oil-based drilling fluid contains emulsifier molecules which could act on the mixture of filtrate and formation water, so the emulsion would be easily produced under the action of shearing force and fluid perturbation. In the flow process, the internal frictional resistance of the emulsion increases resulting in the increase of viscosity of emulsion and it's difficult for the gas to break through. Emulsion droplets have different sizes, the droplets with larger size can form plugging in pore throats and micro-fractures singly, and the smaller ones form plugging by superposition multiply or adsorption on the surface of seepage channel. The emulsion droplets prepared by mixing filtrate of oil-based drilling fluid and formation water at the proportion of 1:1 were shown in Fig. 2. The sizes of emulsion droplets were various and the average radius was about 8.31 μm that was larger than common ones, the reasons might be the coalescence of emulsion droplets during the process of preparation and observation. The size should be smaller under the action of shearing force and fluid perturbation during drilling. In addition, oil-based drilling fluid itself was also an emulsion and the radius of which as well as formed emulsion was smaller than the solid particles in drilling fluid, so the emulsion would plug pore throats and micro-fractures easily and cause damage. However, the emulsion system is instable and in high temperature static environment the demulsification phenomenon will happen in different degrees which are controlled by the intensity of the interfacial film. Furthermore, the intensity of the interfacial film is influenced by
The oil-based drilling fluid has the advantage of low filtration loss, while under reservoir conditions, the filtrate can inevitably enter formation, and causing a series of damage. In the following contents, damage of filtrate invasion was analyzed from wettability alteration, oil phase trapping, emulsion plugging and the effect of multiphase flow. 3.3.1. Wettability alteration The wetting agents in oil-based drilling fluids can alter the wettability of the rock surface from hydrophilic to lipophilic during the process of invading the porous or micro-fractured seepage channels. Results of contact angles of deionized water on the surface of reservoir rocks before and after polluted by filtrate of oil-based drilling fluids are shown in Table 5. According to “Determination of reservoir rock wettability” form Chinese oil industry standards, when the contact angle is between 0 and 75 , the rock wettability is hydrophilicity, when the contact angle is between 75 and 105 , the rock wettability is intermediate wettability. Furthermore, when the contact angle is about 60 , the wettability is weak hydrophilicity according to the instrument description of contact angle tester. Although two kinds of oil-base drilling fluids didn't cause wettability reversal, the wettability of hydrophilic reservoir surface was changed in a large part, which was transformed from hydrophilicity to weak hydrophilicity or intermediate wettability. Wettability is an important factor in controlling the location, flow and distribution of reservoir fluids in porous media. The transformation could lead to an increase of gas phase flow resistance and an accelerated adsorption of solid particles and emulsion on the surface. 3.3.2. Oil phase trapping It should be pointed out that oil phase trapping and oil blocking are different, the damage caused by the former happens mainly in the process where liquid phase saturation increases from the initial saturation to irreducible saturation, when the saturation increases to more than the irreducible saturation, at this point the damage to reservoirs is oil blocking damage in the traditional sense. The result of core flow test is shown in Fig. 1. Obviously, core permeability lowered along with the increasing saturation of oil and the final damage rate of permeability was 97.1% when the oil saturation was close to 100%. The initial liquid phase saturation and the bound liquid phase saturation in the B block were 14.24% and 40% respectively, so the damage rate of oil phase trapping was 61.21% belonging to moderate to strong damage according to “Formation damage evaluation by flow test” form Chinese oil industry standards. Therefore, the initial liquid phase saturation was lower than the irreducible liquid phase saturation in the tight gas reservoir, when the filtrate of oil-based drilling fluid invaded the reservoir, the micron-nano-sized pore throats and micro-fractures would
Fig. 1. Result of oil blocking damage on rock core in B Zone. 620
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Journal of Petroleum Science and Engineering 158 (2017) 616–625
Fig. 2. Emulsion droplets of mixed oil based filtrate and formation water. Note: The large black particles in the figure were the solid phase in the filtrate.
in the B block and the baseline of fractures in Well B2 respectively, these particles could achieve the ideal filling of the pore throats and part of the micro-fractures. Therefore, the CaCO3 particles of 1000 mesh and that of 325 mesh were compounded at a proportion in quality of 79%: 21% by calculation, the optimized curve and the baseline were shown in Fig. 5. The optimized curve was on the right side of the baseline slightly, so the compound temporary plugging agent could realize ideal packing considering particle attrition under the shearing effect. And the mass/ volume fraction of compound temporary plugging agent is usually 3% in drilling fluid form experience. Further, the compound temporary plugging agent was added into the oil-based drilling fluids at a mass/volume fraction of 3%, and then the dynamic pollution experiment was conducted to evaluate the permeability recovery rate. The results listed in Table 6 show that the permeability recovery rates of the optimized INVERMUL oil-based drilling fluid and traditional oil-based drilling fluid were respectively 87.4% and 86.74%. The compound temporary plugging agent could form tight temporary mud cakes on the surface of rocks, avoiding a deep invasion of the solids and liquid phase in the drilling fluid and subsequent fluid efficiently.
structure and concentration of used surfactants as well as inorganic ions, pH value, temperature, pressure and rock type (Yan, 1993; Feng et al., 2014). After demulsification the emulsion will divide into oil-water two phases. The oil phase can invade pore throats and micro-fractures and form oil trapping damage. Meanwhile, as the third phase introduced into gas reservoir, the gas-oil-water three phase flow state will occur near the wellbore even in the throats, resulting in an additional three phase resistance. And oil is a non-wetting phase in hydrophilic reservoir, forming clusters and dispersing in the middle of the seepage channel, causing a significant decline in reservoir permeability (Bennion and Ma, 2000). The effect of multiphase flow is shown in Fig. 3. 3.4. Results of optimization 3.4.1. Result of ideal packing technology From the results of solids damage in section 3.2, the maximum diameter of pore throats was 3.0237 μm in Well B1 and 1.9613 μm in Well B2, averaging 2.5988 μm; the maximum width of fractures was 4.39 μm in Well B1 and 70.9 μm in Well B2. According to the data the baseline was drawn in Fig. 4, and the particle diameter distributions of calcium carbonate particles in four sizes were tested and also drawn in Fig. 4. The main parts in the curves of four kinds of CaCO3 particles were close to a straight line, which was a necessary condition for the ideal packing. However, a single temporary plugging agent couldn't realize ideal packing due to the large difference between four curves and the baseline. The curves of CaCO3 particles of 1000 Chinese common-used mesh and that of 325 mesh were closest to the baseline of pore throats
3.4.2. Results of surfactant optimization The contact angles of five different surfactant solutions on the surface of reservoir rocks are shown in Fig. 6. The contact angles of these surfactant solutions were all lower than that of simulated formation water, and the ability of reducing surface tension was strong. Among them, the surfactant Tween80 (Fig. 6c) was the best. The interfacial tensions between surfactant solutions and diesel measured at the temperature of 40 C and a constant rotation rate of 600 rpm are listed in Table 7. The product of σ and cosθ of surfactant SDBS was lowest and it could reduce capillary pressure effectively and relieve the damage of oil phase trapping. Therefore, surfactant SDBS was optimized to conduct the following experiments. The INVERMUL oil-based drilling fluid was selected singly to evaluate the cleaning efficiency of the optimized surfactant SDBS in order to enhance contrast. The results of cleaning effect of oil-based filtrate cakes under the conditions of static and dynamic state are shown in Table 8 and Fig. 7. Under the static condition, the cleaning efficiency reached the highest value after the filtrate cakes were soaked for 3 min (Fig. 7b). With the soaking time extended, the emulsion on the surface of filtrate cake was destroyed completely while the solid-phase cementing structure was almost intact (Fig. 7c, d, e). Under the dynamic condition, the cleaning efficiency improved obviously, the emulsion on the surface of filtrate
Fig. 3. The effect of multiphase flow diagram. Ⅰ- Single gas phase flow; Ⅱ- Gas-water twophase flow; Ⅲ- oil-gas-water three-phase flow. 621
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Fig. 4. Particle size distributions of CaCO3 particles with different particle sizes.
Fig. 5. Optimized temporary plugging curve of CaCO3 particles.
Similarly, the emulsion was prepared by mixing filtrate of INVERMUL oil-based drilling fluid with simulated formation water at the proportions of 1:1 and 1:2, and then the optimized surfactant SDBS was added into it and the observation results of demulsification was shown in Table 9 and Fig. 8. The emulsion could be formed by stirring the mixture of oil-based filtrate and formation water under the effect of emulsifiers in filtrate and natural formation. It was an unstable thermodynamic system and could separate into layers at a static state, while the separate time was long and the interface wasn't clear. And the more aqueous phase was, the shorter the separate time was, that was the reason why large amount of surfactant solutions were used for well washing. After the optimized surfactant SDBS was used, the separate time became shorter and the interface was clearer. There was more separate aqueous phase with fewer oil droplets in it. So the surfactant SDBS could remove the damage of emulsion plugging. By the analysis above, the optimized surfactant SDBS could destroy the emulsion on filtrate-cake surface and the mixture of oil-based filtrate and formation water, as well as the solid-phase cementing structure. So it could remove the damage of emulsion plugging and promote liquid phase
Table 6 Results of permeability recovery rate contaminated by optimized oil-based drilling fluids. Core
3#
4#
Treatment liquid
Optimized INVERMUL oil-based drilling fluid Optimized traditional oil-based drilling fluid
Permeability (103 μm2)
Dynamic filtration loss (mL)
permeability recovery rate(%)
0.02401
0
87.40
0.02109
0
86.74
Before the contamination
After the contamination
0.02747
0.02431
cake was destroyed in 3 min (Fig. 7g), and the solid-phase cementing structure was destroyed a lot with the time extended (Fig. 7h). Thus the optimized surfactant SDBS could help clean the oil-based cakes and then the gas permeability would increase to a certain extent. 622
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Fig. 6. The contact angles of five different surfactant solutions. Table 7 Optimization results of surfactants. Surfactant solutions
0.4% OP-10
0.4% Tween80
0.4% CTAC
0.4% Imidazoline
0.4% SDBS
Interfacial tensions (mN/m) σ*cosθ
1.18 0.98
2.88 2.43
1.09 0.89
2.20 1.86
0.80 0.67
flow back efficiently. In order to evaluate the effect on gas permeability recovery rate, the cores 1# and 2# that had already contaminated by oilbased drilling fluids were prepared, and the gas permeability of them was measured in the same way introduced in section 2.2.1 while the treatment liquid was replace by optimized surfactant SDBS solution. The results are presented in Table 10. The tested values of permeability recovery were more than 100% after treated by surfactant SDBS solution. The surfactant cleaned polluted section on the surface of cores and destroyed the emulsion inside the cores with plenty of water. Finally, the
Table 8 Oil-based cake cleaning efficiency. Speed (rpm)
Time (min)
Cleaning efficiency (%)
0 (soaking)
3 6 10 15 3 15
5.05 5.78 6.14 6.50 21.50 44.24
600
Fig. 7. Diagram of oil-based cake cleaning effect. 623
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Table 9 Demulsification of emulsion formed by oil-based filtrate and formation water. Volume ratio of filtrate and formation water
Separate time of oil-water (s) Without surfactant
0.4%w/v SDBS
Without surfactant
0.4%w/v SDBS
1:1
Separate time was 80.74s, and the interface wasn't clear Separate time was 54.74s, and the interface was relatively clear
Separate time was 18s and totally separated at 80s, the interface was clear Separate time was 44.14s, and the interface was clear
An average of 8.31
Visible oil-in-water droplet
1:2
Droplet size (μm)
Couldn't be observed due to too many bubbles
Fig. 8. Demulsification effect of emulsion formed by oil-based filtrate and formation water. Table 10 Permeability recovery rate of contaminated cores treated by surfactant solution. Cores
Treatment liquid
1# 2#
0.4% w/v SDBS 0.4% w/v SDBS
Permeability (103 μm2) Before the treatment
After the treatment
0.00777 0.00740
0.01424 0.01033
Dynamic filtration loss (mL)
permeability recovery rate(%)
0.2 0.5
183.27 139.59
Note: The difference for initial permeability of Core 1# (0.00902 in Table 1 and 0.00777 here) is because the delay of test of Core 1# and re-measure permeability.
(3) The optimized surfactant SDBS could destroy the emulsion on filtrate-cake surface and the mixture of oil-based filtrate and formation water, as well as the solid-phase cementing structure. So it could remove the damage of emulsion plugging and promote liquid phase flow back efficiently. The values of permeability recovery were more than 100% after treated by surfactant SDBS solution.
damage of emulsion plugging was removed and the gas permeability got promotion. 4. Conclusions (1) Through laboratory tests, the size matching relationship between solid particles in oil-based drilling fluids in site and fractures in the B block was poor so the solid particles couldn't seal fractures effectively, resulting in solid particles invaded reservoir through micro-fractures deeply and eventually causing serious permeability reduction around the natural fractures. Furthermore, the invasion of oil-based filtrate could transform reservoir wettability from hydrophilicity to weak hydrophilicity or intermediate wettability, leading to an increase of gas phase flow resistance. And the severe oil phase trapping damage occurred inevitably once the filtrate invaded the tight reservoir, the damage rate of which reached 61.21%. Meanwhile, the emulsion droplets formed by mixing the oil-based filtrate with the formation water were about 8 μm in size, and the emulsion had difficulty in demulsification, easily causing emulsion plugging damage and effect of multiphase flow. These main damage mechanisms caused a poor protection effect of oil-based drilling fluid in tight sandstone reservoirs, and the permeability recovery rates of two kinds of oilbased drilling fluids used in site were both less than 60% (2) By the Ideal Packing Theory, a temporary plugging agent was designed with calcium carbonate particles of 1000 mesh and that of 325 mesh at a proportion in quality of 79%: 21% and it could effectively plug the pore throats and micro-fractures, avoiding a deep invasion of the solids and filtrate. The permeability recovery rates of the optimized oil-based drilling fluid with the temporary plugging agent in were more than 85%.
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