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Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin
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ScienceDirect Natural Gas Industry B xx (2018) 1e8 www.elsevier.com/locate/ngib
Research Article
Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin*,** Yue Hong a, Liu Fei b,*, Xue Heng c,d, Sang Yu a, Zhou Changlin b & Wang Yezhong e b
a PetroChina Southwest Oil & Gas Field Company, Chengdu, Sichuan 610051, China Engineering Technology Research Institute, PetroChina Southwest Oil & Gas Field Company, Chengdu, Sichuan 610017, China c Zhenhua Oil Co., Ltd., Beijing 100031, China d Chengdu North Petroleum Exploration and Development Technology Co., Ltd., Chengdu, Sichuan 610051, China e Sichuan Shale Gas Exploration and Development Co., Ltd., Chengdu, Sichuan 610051, China
Received 24 May 2017; accepted 25 October 2017
Abstract The Lower Cambrian Longwangmiao dolomite gas reservoirs in the Sichuan Basin are characterized by well-developed natural microfractures and dissolved pores and cavities. Due to the strong heterogeneity of reservoirs and the serious damage of drilling and completion fluids, acid placement is difficult, and especially the acidizing stimulation of long-interval highly deviated wells or horizontal wells is more difficult. In this paper, the diverting mechanism and rheological behavior of viscoelastic surfactant (VES) based diverting acid was firstly investigated, and the diverting acid with good diversion performance and low secondary damage was selected as the main acid. Then, based on the experimental results of its rheological behaviors, an empirical model of effective viscosity was fitted and a two-scale wormhole propagation model was coupled. And accordingly, a mathematical model for the acidizing of self-diverting acid was established to simulate the pH value, Ca2þ concentration, effective viscosity and wormhole shape under the effect of diverting acid in long-interval highly deviated wells that are nonuniformly damaged. Finally, gelled acid and 5% VES diverting acid were compared in terms of their etched wormhole shapes, flow rate distribution and acid imbibition profiles. It is shown that the diverting acid can obviously improve the acid imbibition profile of strongheterogeneity reservoirs to intensify low-permeability reservoir stimulation. In view of the strong heterogeneity of Longwangmiao dolomite reservoirs and the complexities of drilling and completion fluid damage in the Sichuan Basin, a placement technology was developed for variable VES concentration diverting acid in horizontal wells and long-interval highly deviated wells completed with slotted liners. This acid placement technology has been practically applied in 8 wells and their cumulative gas production rate tested at the wellhead is 1233.46 104 m3/d. The average production stimulation ratio per well is up to 1.95. It provides a support for the efficient development of the Longwangmiao giant gas reservoir. © 2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
* Project supported by the National Science and Technology Major Project “Large-scale Oil and Gas Fields and CBM Development: Demonstration Project of Large-scale Carbonate Gas Fields in Sichuan Basin” (Code: 2016ZX05052), CNPC Major Science and Technology Project “Research and Application of Deep-Temperature and High-Pressure Sulfur Gas Reservoir Reformation Technology in Sichuan Basin” (Code: 2016E-0609). ** This is the English version of the originally published article in Natural Gas Industry (in Chinese), which can be found at https://doi.org/10.3787/j.issn. 1000-0976.2017.10.006. * Corresponding author. E-mail address: [email protected] (Liu F.). Peer review under responsibility of Sichuan Petroleum Administration.
Keywords: Sichuan Basin; Early Cambrian; Longwangmiao Fm gas reservoir; Dolomite; Diverting acid; Rheological behavior; Matrix acidizing; Numerical simulation; Field application; Highly-efficient development
1. Introduction The Lower Cambrian Longwangmiao Fm gas reservoirs in the Moxi block of the Sichuan Basin are the largest monolithic carbonate gas reservoirs ever discovered in China [1,2]. They are composed of dolomite and contain microfractures and
https://doi.org/10.1016/j.ngib.2018.04.007 2352-8540/© 2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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millimeterecentimeter-sized dissolution pores. With strong heterogeneity, these reservoirs are dominantly fractured-cavity reservoirs and fracture-pore or pore reservoirs locally [3]. They are more than 4500 m in depth, and characterized by low porosity (2.48e8.91%, with an average of 5.19%), medium to low permeability (0.01e10.00 mD), high temperature (140.21 C), high pressure (pressure coefficient of 1.64) and acidity (with H2S content of 5.00e11.68 g/m3 and CO2 content of 21.50e48.83 g/m3). Drilling fluid loss or influx during the overbalanced drilling is serious. The permeability damage of matrix rock sample is 98.20% and the permeability damage of fracture rock sample is 82.23e89.23% [4,5]. Thus, it is urgent to carry out acidizing stimulation in order to fully relieve the damages of drilling and completion fluids and release the natural flow of gas [6,7]. However, in long-interval highly deviated wells and horizontal wells, the characteristics of drilling fluid damages are complex, and the depth and extent of damages of drilling and completion fluid in flux are significantly heterogeneous. In addition, the reservoirs have natural strong heterogeneity. With consideration to these factors, acid placement is particularly important for the stimulation of long-interval highly deviated wells and horizontal wells. Viscoelastic surfactant diverting acid is a kind of polymer-free acid liquid system. Its viscosity increases and then decreases with the aciderock reaction. It can realize self-diversion [8]. The system is widely used in matrix acidification of carbonate reservoir [9e12]. 2. Steering mechanism 2.1. Viscosity variation mechanism The key viscoelastic surfactants commonly used for diverting acid are zwitterionic surfactants or cationic quaternary ammonium surfactants. Taking zwitterionic surfactants for example, they exhibit various charge characteristics at different pH values. When the pH value is lower than the isoelectric point, its anion group ionization is weak and it shows cationic characteristics. In this case, the surfactant molecules are distributed in the form of monomer, so the fresh acid has low viscosity and mainly enters the intervals with high permeability or low damage that has high acid absorption ability. With the increase of pH value, the ionization degree of anionic groups increases, the anionic properties increase and the cationic properties decrease. The neutral characteristics begin to appear from the isoelectric point, the charge effect is weakened, and the surfactant molecules are spherical or short rod-like micelles. Under the cross-linking of divalent cations (Ca2þ and Mg2þ) generated by the aciderock reaction, spherical or short rod-like micelles entangle with each other to form wormlike micelles with a spatial network structure. Then the viscosity of the system increases sharply and the highpermeability zone is temporarily blocked, forcing the subsequent acid to enter the low-permeability zone or high-damage zone [8]. With the further reduction of Hþ concentration, or when encountering the crude oil, natural gas and other hydrocarbon substances in the reservoir, worm-like micelles
change into spherical micelles, resulting in automatic gel breaking and viscosity reduction, which is conducive to residual acid flowback (Fig. 1). 2.2. Rheological behavior The rheological behavior of diverting acid changes with the aciderock reaction process, which is the root cause for diverting. It is found that acid concentration or pH value, VES concentration and Ca2þ concentration are the main factors that affect the viscosity of the diverting acid, and the effect of Mg2þ and Naþ is relatively small [13]. In simulating the spent acids of diverting acid at a specific time during the aciderock reaction, HCl acid solution was first added according to the setting concentration of hydrochloric acid and surfactant was added at a suitable concentration. According to the aciderock reaction metrology relationship, aciderock reaction product CaCl2 calculated [14] by the consumption of acid (the difference between the amount of 20% fresh acid and the amount of residual acid) was added to determine its apparent viscosity in the 170 s1. The apparent viscosity curves of the residual diverting acid at a mass concentration of 5% under different VES concentrations are shown in Fig. 2. The apparent viscosity of the diverting acid at a VES concentration of 5% varies with pH and Ca2þ concentration, as is shown in Fig. 3. Using the empirical rheological model of diverting acid proposed by Liu et al. [15], the empirical model of the rheological behavior of diverting acid can be fitted as follows. meff ¼ m0 þ mmax f ðpHÞf Ca2þ f ðVESÞ f ðpHÞ ¼
f Ca
2þ
erfðb,pH cÞ þ 1 W1
ð2Þ
" # CCa2þ Cm;Ca2þ 2 ¼ exp W2 "
CVES Cm;VES f ðVESÞ ¼ exp 0:5 W1
ð1Þ
ð3Þ
2 # ð4Þ
where, meff represents the effective viscosity, mPa$s; similarly, m0: the apparent viscosity of fresh diverting acid, which is set to be 5.68 mPa s; mmax: the maximum apparent viscosity of the diverting acid, which is set to be 126.52 mPa s; C2þ Ca : the mass concentration of CaCl2; C2þ : the CaCl mass concentration m,Ca 2 corresponding to the maximum apparent viscosity of the diverting acid, which is set to be 25%; CVES:the VES mass concentration; Cm,VES: the VES concentration corresponding to the maximum apparent viscosity of the diverting acid, which is set to be 5%; W1, W2, W3, b and c respectively represent the fitting parameters (W1 ¼ 1.85, W2 ¼ 14, W3 ¼ 1.756, b ¼ 1.2, c ¼ 1.5, dimensionless).
Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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Fig. 1. Viscoelastic mechanism of diverting acid.
3. Acidification simulation Two-scale models were commonly used to simulate the wormhole expansion caused by matrix acidification of carbonate reservoir [16]. However, to simulate the matrix acidification of diverting acid, it is necessary to couple a rheological model of diverting acid. The diverting acid pH can be calculated from the acid concentration (i.e., Hþ concentration), while the Ca2þ and VES concentrations need to be recalculated. 3.1. Acidification model Based on the principle of conservation of mass, changes in the concentration of Ca2þ and VES during the acidification of diverting acid can be tracked [15]:
Fig. 2. Influence of VES mass fraction on the apparent viscosity.
vð4CCa2þ Þ þ VðUCCa2þ Þ ¼ vt V 4De;Ca2þ VCCa2þ þ 0:5kc av Cf Cs
ð5Þ
vð4CVES Þ þ VðUCVES Þ ¼ Vð4De;VES VCVES Þ ð6Þ vt Coupled with a two-scale wormhole expansion model, the acidification process of diverting acid can be simulated: 8 106 K > > U ¼ Vp > > > meff > > > > > v4 > > > < vt þ VU ¼ 0 ð7Þ > > > v 4Cf þ VUCf ¼ V4De VCf kc av Cf Cs > > > vt > > > > > v4 kc av Cf Cs b > > : ¼ vt rs
Fig. 3. Apparent viscosity of diverting acid at different pH values and Ca2þ concentrations.
Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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where, 4 is the porosity; similarly, t: the time, s; V: the 2þ gradient operator; U: the seepage velocity, m/s; DCa : the e effective mass transfer coefficients of Ca2þ, m2/s; kc is the mass transfer velocity, m/s; av is the specific surface, m2/m3; Cf is the acid concentration, kmol/m3; Cs: the acid concentration of the pore wall, kmol/m3; De,VES: the effective mass transfer coefficient of surfactant, m2/s; K: the permeability, mD; p: the pressure, MPa; De: the effective mass transfer coefficient of acid, m2/s; b: the corrosion capacity of acid, kg/ kmol; rs: the rock density, kg/m3. The initial conditions are as follows: 8 pðr; t ¼ 0Þ ¼ pe > > < Cf ðr; t ¼ 0Þ ¼ 0 ð8Þ C 2þ ðr; t ¼ 0Þ ¼ 0 > > : Ca CVES ðr; t ¼ 0Þ ¼ 0 The boundary conditions are as follows: 8X qðr ¼ rw ; tÞ ¼ qinj > > > > < pðr ¼ re ; tÞ ¼ pe Cf ðr ¼ rw ; tÞ ¼ Cf0 > > > > CCa2þ ðr ¼ rw ; tÞ ¼ 0 : 0 CVES ðr ¼ rw ; tÞ ¼ CVES
ð9Þ
where, pe is the pore pressure of reservoirs, MPa; similarly, qinj: the injection displacement, m3/s; re: the discharge radius, m; rw:the borehole radius, m; C0f : the injected acid concentration, kmol/m3; C0VES: the VES concentration of injected acid. Based on the empirical relationship of permeability, mass transfer coefficient, specific surface area and pore radius that changes with the porosity [17e19], the model can be solved. 3.2. Core-scale simulation Artificial marble cores were used to carry out parallel test [20,21] of diverting acid flow simulation in cores at the temperature of 120 C. Each group of cores contained a highpermeability core and a low-permeability core. The highpermeability core had the initial permeability (K0) of 30.98e60.56mD, which was used to simulate the interval with dissolution pores. The low-permeability had the initial permeability (K0) of core 3.48e6.23 mD, which was used to simulate the intervals without pores. The initial permeability
differential (Kdiff) was 7.29e11.02. Experiments were conducted with diverting acids with VES concentrations of 4.0% and 5.0%, respectively (Table 1). From the experimental results, it can be seen that the permeability (Kacid) of high-permeability core after acidification is 356.44e568.32mD, with the stimulation multiple of 9.3e11.5. The permeability (Kacid) of low-permeability core after acidification is 9.24e10.67mD, with the stimulation multiple of 1.5e2.7. The permeability differential (Kdiff) is 38.58e53.26 after acidification, and the diverting acid with a VES concentration of 5% has better diversion performance. The core data of the second experiment were adopted for acidification simulation using the diverting acid acidification mathematical model and the diverting acid rheological empirical fitting model. The wormhole shapes after acidification with a HCl gelled acid concentration of 20% and a VES concentration of 5% were compared. With the injection displacement of 2 mL/min, the morphology of the eroding wormholes was shown in Fig. 4 when the injection volume was 100 mL. The flow distribution comparison among the cores is shown in Fig. 5. It can be seen from Figs. 4 and 5 that after gelled acid acidizing, the length of wormholes in the high-permeability core is about 6.5 cm, and the length of wormholes in lowpermeability cores is only 0.7 cm. The initial liquid absorption of low-permeability core was 9%. After reservoir stimulation, its liquid absorption was 1% and its total liquid intake was 6%, indicating that the low-permeability core was not stimulated obviously. However, after diverting acid acidizing, the length of wormholes was 4.5 cm, the length of wormholes was 1.5 cm, and the stimulation degree of low-permeability cores was doubled. The initial absorption of low-permeability core accounted for 9%. With the aciderock reaction, the high-viscosity area formed in the high-permeability core, increasing the seepage resistance; and the fluid absorption proportion of low-permeability cores increased to 23%, forcing the acid to enter the low-permeability core. Then a highviscosity area was formed in the high and low-permeability cores. There were fluctuations in the liquid absorption proportion of high and low-permeability cores. The total liquid absorption of low-permeability cores accounted for 18%. The diverting acid causes 12% of the acid to enter the lowpermeability core, which can effectively improve the acidabsorbing profile of the heterogeneous reservoir.
Table 1 Parallel core acidification experiment with diverting acid. No.
Core no.
VES concentration
K0/mD
Kacid/mD
Kdiff (before/after)
Stimulation multiple
1
No. No. No. No. No. No. No. No.
4.0%
45.44 6.23 60.56 5.86 50.24 4.56 30.98 3.48
496.20 9.61 568.32 10.67 468.32 10.24 356.44 9.24
7.29/51.63
10.9 1.5 9.4 1.8 9.3 2.2 11.5 2.7
2 3 4
1 2 3 4 5 6 7 8
4.0% 5.0% 5.0%
10.33/53.26 11.02/45.73 8.90/38.58
Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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Fig. 5. Flow distribution of different acids in parallel cores.
Fig. 4. Comparison of wormholes of parallel cores caused by acid etching with different acids.
4. Field application Well Moxi 008-17-X1 is a highly-deviated development well at the east high point of the Moxi structure. During the overbalanced drilling of the Longwangmiao Formation in this well with the drilling fluid of 1.70e1.75 g/cm3, gas cut was seen for five times and the total hydrocarbon in gas survey reached a maximum of 65.32%. Logging interpretation showed 4 reservoirs, with a cumulative thickness of 528.6 m, a reservoir thickness of 451.0 m, an average porosity of 4.7% and an average permeability of 1.0mD, in which the thickness of Type I reservoir was 1.25 m (4 ¼ 12.8%), the thickness of Type II reservoir was 80.9 m (4 ¼ 7.3%), and the thickness of Type III reservoir was 368.88 m (4 ¼ 4.1%). The imaging logging shows that fractures and dissolved pores and cavities are well-developed. The reservoir is characterized by long intervals, different degrees of pore, hole and crack development, strong
Fig. 6. Drilling fluid filtrate invasion depth profile along the wellbore.
Fig. 7. Drilling fluid damage skin factor profile along the wellbore.
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Fig. 9. Comparison of cumulative acid absorption profiles between diverting acid and gelled acid.
Fig. 8. Distribution of acidification simulation parameters with VES concentration of 5%.
heterogeneity and complicated damage of drilling and completion fluids. Considering drilling fluid solid-phase filter cake deposition and erosion, filtrate invasion, and permeability damage [22], it is possible to calculate the drilling fluid filtrate invasion depth and skin factor profile along the wellbore profile (Figs. 6 and 7). It can be seen from the damage profile that the invasion depth of drilling fluid filtrate and the damage skin are generally in the shape of an ellipse with a large heel end and a small toe end. However, due to the uneven development of pores, holes and cracks, there are local fluctuations.
In this well, liner completion was adopted with a slotted section of 4738.0e5400.0 m, and only general acidification can be used. Based on the established model of diverting acid acidizing, the distribution of pH value, Ca2þ concentration, acid viscosity and acid-etched wormholes in the process of diverting acid acidizing by using the difference solution in the cylindrical coordinate system (r, q, z) (Fig. 8). It can be seen that there is fresh acid with low pH value, low Ca2þ concentration and low viscosity inside the acid-etched wormholes (red area in Fig. 8-d), while around the wormholes (green area in Fig. 8-a), the fresh acid inside the wormholes reacts with the wall rock of the wormhole, the acid concentration decreases, and the pH value increases to 2e3. The generated Ca2þ is displaced into the reservoir and forms a high-viscosity area around the wormhole (Fig. 8-c), forcing the acid to enter other intervals. In addition, the cumulative acid entry profiles of the diverted acid with 5% VES concentration and the conventional gelled acid were compared (Fig. 9). The diverted acid formed a high-viscosity area in the interval with a high liquid absorption ability, forcing the acid to enter the interval with a weak liquid absorption ability, so that the liquid absorption volume of the interval with a high liquid absorption ability decreased and the entire fluid entry profile became more uniform. As the viscosity of diverting acid changes with the progress of aciderock reaction, it is possible to achieve the purpose of improving the acid-absorbing profile of the long-interval reservoir with strong heterogeneity and realizing the targeted acid placement. The well was acidified with diverting acid at VES concentration of 4% and 5%. The construction curve is shown in Fig. 10. After acid entered the formation, the displacement increased from 6.0 m3/min to 8.2 m3/min and pump pressure decreased from 60.14 MPa to 45.44 MPa. Thus, the acid solution relieved the damage of drilling fluid filter cake. Then the displacement was maintained, the pump pressure continued to decline to 37.7 MPa, the acid-etched wormholes caused by diverting acid broke through the damage zone, and a significant effect of plugging removal appeared. In the process, the
Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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Fig. 10. Construction curve of diverting acid acidizing in Well Moxi 008-17-X1.
Table 2 Statistics of diverting acid acidizing with different VES concentrations in the Longwangmiao Fm gas reservoirs. Well no.
Moxi Moxi Moxi Moxi Moxi Moxi Moxi Moxi
008-H1 008-H19 009-X5 008-X16 008-17-X1 008-20-H2 008-6-X2 008-12-X1
Interval/m
4699.5e5436.0 4689.7e5600.0 5045.9e5650.6 4962.4e5448.4 4738.0e5302.8 4881.0e5830.0 4781.7e5280.0 4856.8e5335.0
Diverting acid injection/m3
Displacement/ (m3$min1)
Pump pressure/ MPa
517.62 674.82 619.83 599.16 676.47 600.00 680.00 599.45
5.4e6.1 4.5e5.1 3.0e3.2 6.0e6.5 8.2e8.3 4.0e5.5 6.3e6.8 3.4e3.6
86e91 65e70 68e70 65e67 55e60 65e70 61e67 67e70
pump pressure increased from 41.31 MPa to 43.93 MPa, showing an obvious diversion effect. The well was tested with a Ø50.8 mm critical velocity flowmeter. The test output before acidification was 143.18 104 m3/d, the test output after acidification was 227.07 104 m3/d, and the unobstructed flow was converted to be 800 104 m3/d. The production stimulation ratio was 1.59. Acidification tests with different VES concentrations were conducted in 8 wells in the Longwangmiao Fm gas reservoirs (Table 2). After reservoir stimulation, the cumulative test output was 1233.46 104 m3/d with an average production stimulation ratio of 1.95. Production stimulation effect was obvious. 5. Conclusions 1) The strong heterogeneity and the complexity of drilling and completion fluid damage of the Longwangmiao Fm dolomite reservoirs cause the difficulty in placing the acid in the targeted area, and the viscosity of the VES diverting acid increases acid with the aciderock reaction. Diverting acid can obviously improve the acid-absorbing profile of reservoirs with strong heterogeneity and increase the stimulation degree of low-permeability reservoirs. 2) The concentrations of calcium ions and VES were tracked during the diverting acid acidizing, which was combined with the empirical model of the diverting acid rheological
Test output/(104 m3$d1) Before acidification
After acidification
78.73 44.48 113.00 119.95 143.18 86.34 55.61 53.59
182.77 155.04 176.62 165.59 227.07 110.85 106.77 108.75
Production stimulation ratio
2.32 3.49 1.56 1.38 1.59 1.28 1.92 2.03
behavior and two-scale wormhole expansion model to realize the numerical simulation of diverting acid acidizing. 3) The placement technology developed for variable VES concentration diverting acid in horizontal wells and long-interval highly deviated wells completed with slotted liners has a remarkable field application effect and can effectively resolve the problem of uneven acid absorption profile caused by strong reservoir heterogeneity and the complexity of damage degree, so that the natural productivity of gas wells will be developed.
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[13] Qu Zhanqing, Qu Guanzheng, Qi Ning, He Limin, Li Xiaqing & Wu Shiqiang. Evaluation of the performances of medium and lowtemperature VES-BAT self-diverting acid. Pet Geol Oilfield Dev Daqing 2013;32(2):130e5. [14] Zhao Zengying, Yang Xianyou, Lian Shengjiang & Zhang Xiuli. Viscosity behavior of viscoelastic surfactant based self-diverting hydrochloric acid for carbonate reservoir stimulation. Oilfield Chem 2005;22(4):307e9. [15] Liu Pingli, Xue Heng, Zhao Liqiang, Fu Yangyang, Luo Zhifeng & Qu Zhanqing. Analysis and simulation of rheological behavior and diverting mechanism of in situ self-diverting acid. J Petrol Sci Eng 2015;132:39e52. [16] Kalia N & Balakotaiah V. Modeling and analysis of wormhole formation in reactive dissolution of carbonate rocks. Chem Eng Sci 2007;62(4): 919e28. [17] Mou Jianye, Li Shuangming, Zhao Xin & Cai Xin. Modeling wormhole propagation behavior based on real pore spatial distributions. Sci Technol Eng 2014;14(35):40e6. [18] Xue Heng, Zhao Liqiang, Liu Pingli, Cui Mingyue, Jiang Weidong, Liang Chong, et al. Dynamic simulation of 3-D multiple-scale wormhole propagation in carbonate rocks. Oil Gas Geol 2016;37(5):792e8. [19] Liu Ming, Zhang Shicheng & Mou Jianye. Fractal nature of acid-etched wormholes and the influence of acid type on wormholes. Petrol Explor Dev 2012;39(5):591e6. [20] He Jun, Zou Honglan & Wu Haihong. Acidizing techniques for improving gas production in gas reservoir. Acta Pet Sin 2006;27(4): 97e100. [21] Jiang Weidong, Liu He, Yan Jun, Liang Chong, He Anle, Zhang Hewen, et al. A novel fiber temporary plugging and diverting acid fracturing technology: an experimental study and field practices. Nat Gas Ind 2015;35(11):54e9. [22] Wang Peishan. Optimizing of matrix acidizing mode for horizontal wells in carbonate reservoir. Chengdu: Southwest Petroleum University; 2014.
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Research Article
Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin*,** Yue Hong a, Liu Fei b,*, Xue Heng c,d, Sang Yu a, Zhou Changlin b & Wang Yezhong e b
a PetroChina Southwest Oil & Gas Field Company, Chengdu, Sichuan 610051, China Engineering Technology Research Institute, PetroChina Southwest Oil & Gas Field Company, Chengdu, Sichuan 610017, China c Zhenhua Oil Co., Ltd., Beijing 100031, China d Chengdu North Petroleum Exploration and Development Technology Co., Ltd., Chengdu, Sichuan 610051, China e Sichuan Shale Gas Exploration and Development Co., Ltd., Chengdu, Sichuan 610051, China
Received 24 May 2017; accepted 25 October 2017
Abstract The Lower Cambrian Longwangmiao dolomite gas reservoirs in the Sichuan Basin are characterized by well-developed natural microfractures and dissolved pores and cavities. Due to the strong heterogeneity of reservoirs and the serious damage of drilling and completion fluids, acid placement is difficult, and especially the acidizing stimulation of long-interval highly deviated wells or horizontal wells is more difficult. In this paper, the diverting mechanism and rheological behavior of viscoelastic surfactant (VES) based diverting acid was firstly investigated, and the diverting acid with good diversion performance and low secondary damage was selected as the main acid. Then, based on the experimental results of its rheological behaviors, an empirical model of effective viscosity was fitted and a two-scale wormhole propagation model was coupled. And accordingly, a mathematical model for the acidizing of self-diverting acid was established to simulate the pH value, Ca2þ concentration, effective viscosity and wormhole shape under the effect of diverting acid in long-interval highly deviated wells that are nonuniformly damaged. Finally, gelled acid and 5% VES diverting acid were compared in terms of their etched wormhole shapes, flow rate distribution and acid imbibition profiles. It is shown that the diverting acid can obviously improve the acid imbibition profile of strongheterogeneity reservoirs to intensify low-permeability reservoir stimulation. In view of the strong heterogeneity of Longwangmiao dolomite reservoirs and the complexities of drilling and completion fluid damage in the Sichuan Basin, a placement technology was developed for variable VES concentration diverting acid in horizontal wells and long-interval highly deviated wells completed with slotted liners. This acid placement technology has been practically applied in 8 wells and their cumulative gas production rate tested at the wellhead is 1233.46 104 m3/d. The average production stimulation ratio per well is up to 1.95. It provides a support for the efficient development of the Longwangmiao giant gas reservoir. © 2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
* Project supported by the National Science and Technology Major Project “Large-scale Oil and Gas Fields and CBM Development: Demonstration Project of Large-scale Carbonate Gas Fields in Sichuan Basin” (Code: 2016ZX05052), CNPC Major Science and Technology Project “Research and Application of Deep-Temperature and High-Pressure Sulfur Gas Reservoir Reformation Technology in Sichuan Basin” (Code: 2016E-0609). ** This is the English version of the originally published article in Natural Gas Industry (in Chinese), which can be found at https://doi.org/10.3787/j.issn. 1000-0976.2017.10.006. * Corresponding author. E-mail address: [email protected] (Liu F.). Peer review under responsibility of Sichuan Petroleum Administration.
Keywords: Sichuan Basin; Early Cambrian; Longwangmiao Fm gas reservoir; Dolomite; Diverting acid; Rheological behavior; Matrix acidizing; Numerical simulation; Field application; Highly-efficient development
1. Introduction The Lower Cambrian Longwangmiao Fm gas reservoirs in the Moxi block of the Sichuan Basin are the largest monolithic carbonate gas reservoirs ever discovered in China [1,2]. They are composed of dolomite and contain microfractures and
https://doi.org/10.1016/j.ngib.2018.04.007 2352-8540/© 2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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millimeterecentimeter-sized dissolution pores. With strong heterogeneity, these reservoirs are dominantly fractured-cavity reservoirs and fracture-pore or pore reservoirs locally [3]. They are more than 4500 m in depth, and characterized by low porosity (2.48e8.91%, with an average of 5.19%), medium to low permeability (0.01e10.00 mD), high temperature (140.21 C), high pressure (pressure coefficient of 1.64) and acidity (with H2S content of 5.00e11.68 g/m3 and CO2 content of 21.50e48.83 g/m3). Drilling fluid loss or influx during the overbalanced drilling is serious. The permeability damage of matrix rock sample is 98.20% and the permeability damage of fracture rock sample is 82.23e89.23% [4,5]. Thus, it is urgent to carry out acidizing stimulation in order to fully relieve the damages of drilling and completion fluids and release the natural flow of gas [6,7]. However, in long-interval highly deviated wells and horizontal wells, the characteristics of drilling fluid damages are complex, and the depth and extent of damages of drilling and completion fluid in flux are significantly heterogeneous. In addition, the reservoirs have natural strong heterogeneity. With consideration to these factors, acid placement is particularly important for the stimulation of long-interval highly deviated wells and horizontal wells. Viscoelastic surfactant diverting acid is a kind of polymer-free acid liquid system. Its viscosity increases and then decreases with the aciderock reaction. It can realize self-diversion [8]. The system is widely used in matrix acidification of carbonate reservoir [9e12]. 2. Steering mechanism 2.1. Viscosity variation mechanism The key viscoelastic surfactants commonly used for diverting acid are zwitterionic surfactants or cationic quaternary ammonium surfactants. Taking zwitterionic surfactants for example, they exhibit various charge characteristics at different pH values. When the pH value is lower than the isoelectric point, its anion group ionization is weak and it shows cationic characteristics. In this case, the surfactant molecules are distributed in the form of monomer, so the fresh acid has low viscosity and mainly enters the intervals with high permeability or low damage that has high acid absorption ability. With the increase of pH value, the ionization degree of anionic groups increases, the anionic properties increase and the cationic properties decrease. The neutral characteristics begin to appear from the isoelectric point, the charge effect is weakened, and the surfactant molecules are spherical or short rod-like micelles. Under the cross-linking of divalent cations (Ca2þ and Mg2þ) generated by the aciderock reaction, spherical or short rod-like micelles entangle with each other to form wormlike micelles with a spatial network structure. Then the viscosity of the system increases sharply and the highpermeability zone is temporarily blocked, forcing the subsequent acid to enter the low-permeability zone or high-damage zone [8]. With the further reduction of Hþ concentration, or when encountering the crude oil, natural gas and other hydrocarbon substances in the reservoir, worm-like micelles
change into spherical micelles, resulting in automatic gel breaking and viscosity reduction, which is conducive to residual acid flowback (Fig. 1). 2.2. Rheological behavior The rheological behavior of diverting acid changes with the aciderock reaction process, which is the root cause for diverting. It is found that acid concentration or pH value, VES concentration and Ca2þ concentration are the main factors that affect the viscosity of the diverting acid, and the effect of Mg2þ and Naþ is relatively small [13]. In simulating the spent acids of diverting acid at a specific time during the aciderock reaction, HCl acid solution was first added according to the setting concentration of hydrochloric acid and surfactant was added at a suitable concentration. According to the aciderock reaction metrology relationship, aciderock reaction product CaCl2 calculated [14] by the consumption of acid (the difference between the amount of 20% fresh acid and the amount of residual acid) was added to determine its apparent viscosity in the 170 s1. The apparent viscosity curves of the residual diverting acid at a mass concentration of 5% under different VES concentrations are shown in Fig. 2. The apparent viscosity of the diverting acid at a VES concentration of 5% varies with pH and Ca2þ concentration, as is shown in Fig. 3. Using the empirical rheological model of diverting acid proposed by Liu et al. [15], the empirical model of the rheological behavior of diverting acid can be fitted as follows. meff ¼ m0 þ mmax f ðpHÞf Ca2þ f ðVESÞ f ðpHÞ ¼
f Ca
2þ
erfðb,pH cÞ þ 1 W1
ð2Þ
" # CCa2þ Cm;Ca2þ 2 ¼ exp W2 "
CVES Cm;VES f ðVESÞ ¼ exp 0:5 W1
ð1Þ
ð3Þ
2 # ð4Þ
where, meff represents the effective viscosity, mPa$s; similarly, m0: the apparent viscosity of fresh diverting acid, which is set to be 5.68 mPa s; mmax: the maximum apparent viscosity of the diverting acid, which is set to be 126.52 mPa s; C2þ Ca : the mass concentration of CaCl2; C2þ : the CaCl mass concentration m,Ca 2 corresponding to the maximum apparent viscosity of the diverting acid, which is set to be 25%; CVES:the VES mass concentration; Cm,VES: the VES concentration corresponding to the maximum apparent viscosity of the diverting acid, which is set to be 5%; W1, W2, W3, b and c respectively represent the fitting parameters (W1 ¼ 1.85, W2 ¼ 14, W3 ¼ 1.756, b ¼ 1.2, c ¼ 1.5, dimensionless).
Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007
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Fig. 1. Viscoelastic mechanism of diverting acid.
3. Acidification simulation Two-scale models were commonly used to simulate the wormhole expansion caused by matrix acidification of carbonate reservoir [16]. However, to simulate the matrix acidification of diverting acid, it is necessary to couple a rheological model of diverting acid. The diverting acid pH can be calculated from the acid concentration (i.e., Hþ concentration), while the Ca2þ and VES concentrations need to be recalculated. 3.1. Acidification model Based on the principle of conservation of mass, changes in the concentration of Ca2þ and VES during the acidification of diverting acid can be tracked [15]:
Fig. 2. Influence of VES mass fraction on the apparent viscosity.
vð4CCa2þ Þ þ VðUCCa2þ Þ ¼ vt V 4De;Ca2þ VCCa2þ þ 0:5kc av Cf Cs
ð5Þ
vð4CVES Þ þ VðUCVES Þ ¼ Vð4De;VES VCVES Þ ð6Þ vt Coupled with a two-scale wormhole expansion model, the acidification process of diverting acid can be simulated: 8 106 K > > U ¼ Vp > > > meff > > > > > v4 > > > < vt þ VU ¼ 0 ð7Þ > > > v 4Cf þ VUCf ¼ V4De VCf kc av Cf Cs > > > vt > > > > > v4 kc av Cf Cs b > > : ¼ vt rs
Fig. 3. Apparent viscosity of diverting acid at different pH values and Ca2þ concentrations.
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where, 4 is the porosity; similarly, t: the time, s; V: the 2þ gradient operator; U: the seepage velocity, m/s; DCa : the e effective mass transfer coefficients of Ca2þ, m2/s; kc is the mass transfer velocity, m/s; av is the specific surface, m2/m3; Cf is the acid concentration, kmol/m3; Cs: the acid concentration of the pore wall, kmol/m3; De,VES: the effective mass transfer coefficient of surfactant, m2/s; K: the permeability, mD; p: the pressure, MPa; De: the effective mass transfer coefficient of acid, m2/s; b: the corrosion capacity of acid, kg/ kmol; rs: the rock density, kg/m3. The initial conditions are as follows: 8 pðr; t ¼ 0Þ ¼ pe > > < Cf ðr; t ¼ 0Þ ¼ 0 ð8Þ C 2þ ðr; t ¼ 0Þ ¼ 0 > > : Ca CVES ðr; t ¼ 0Þ ¼ 0 The boundary conditions are as follows: 8X qðr ¼ rw ; tÞ ¼ qinj > > > > < pðr ¼ re ; tÞ ¼ pe Cf ðr ¼ rw ; tÞ ¼ Cf0 > > > > CCa2þ ðr ¼ rw ; tÞ ¼ 0 : 0 CVES ðr ¼ rw ; tÞ ¼ CVES
ð9Þ
where, pe is the pore pressure of reservoirs, MPa; similarly, qinj: the injection displacement, m3/s; re: the discharge radius, m; rw:the borehole radius, m; C0f : the injected acid concentration, kmol/m3; C0VES: the VES concentration of injected acid. Based on the empirical relationship of permeability, mass transfer coefficient, specific surface area and pore radius that changes with the porosity [17e19], the model can be solved. 3.2. Core-scale simulation Artificial marble cores were used to carry out parallel test [20,21] of diverting acid flow simulation in cores at the temperature of 120 C. Each group of cores contained a highpermeability core and a low-permeability core. The highpermeability core had the initial permeability (K0) of 30.98e60.56mD, which was used to simulate the interval with dissolution pores. The low-permeability had the initial permeability (K0) of core 3.48e6.23 mD, which was used to simulate the intervals without pores. The initial permeability
differential (Kdiff) was 7.29e11.02. Experiments were conducted with diverting acids with VES concentrations of 4.0% and 5.0%, respectively (Table 1). From the experimental results, it can be seen that the permeability (Kacid) of high-permeability core after acidification is 356.44e568.32mD, with the stimulation multiple of 9.3e11.5. The permeability (Kacid) of low-permeability core after acidification is 9.24e10.67mD, with the stimulation multiple of 1.5e2.7. The permeability differential (Kdiff) is 38.58e53.26 after acidification, and the diverting acid with a VES concentration of 5% has better diversion performance. The core data of the second experiment were adopted for acidification simulation using the diverting acid acidification mathematical model and the diverting acid rheological empirical fitting model. The wormhole shapes after acidification with a HCl gelled acid concentration of 20% and a VES concentration of 5% were compared. With the injection displacement of 2 mL/min, the morphology of the eroding wormholes was shown in Fig. 4 when the injection volume was 100 mL. The flow distribution comparison among the cores is shown in Fig. 5. It can be seen from Figs. 4 and 5 that after gelled acid acidizing, the length of wormholes in the high-permeability core is about 6.5 cm, and the length of wormholes in lowpermeability cores is only 0.7 cm. The initial liquid absorption of low-permeability core was 9%. After reservoir stimulation, its liquid absorption was 1% and its total liquid intake was 6%, indicating that the low-permeability core was not stimulated obviously. However, after diverting acid acidizing, the length of wormholes was 4.5 cm, the length of wormholes was 1.5 cm, and the stimulation degree of low-permeability cores was doubled. The initial absorption of low-permeability core accounted for 9%. With the aciderock reaction, the high-viscosity area formed in the high-permeability core, increasing the seepage resistance; and the fluid absorption proportion of low-permeability cores increased to 23%, forcing the acid to enter the low-permeability core. Then a highviscosity area was formed in the high and low-permeability cores. There were fluctuations in the liquid absorption proportion of high and low-permeability cores. The total liquid absorption of low-permeability cores accounted for 18%. The diverting acid causes 12% of the acid to enter the lowpermeability core, which can effectively improve the acidabsorbing profile of the heterogeneous reservoir.
Table 1 Parallel core acidification experiment with diverting acid. No.
Core no.
VES concentration
K0/mD
Kacid/mD
Kdiff (before/after)
Stimulation multiple
1
No. No. No. No. No. No. No. No.
4.0%
45.44 6.23 60.56 5.86 50.24 4.56 30.98 3.48
496.20 9.61 568.32 10.67 468.32 10.24 356.44 9.24
7.29/51.63
10.9 1.5 9.4 1.8 9.3 2.2 11.5 2.7
2 3 4
1 2 3 4 5 6 7 8
4.0% 5.0% 5.0%
10.33/53.26 11.02/45.73 8.90/38.58
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Fig. 5. Flow distribution of different acids in parallel cores.
Fig. 4. Comparison of wormholes of parallel cores caused by acid etching with different acids.
4. Field application Well Moxi 008-17-X1 is a highly-deviated development well at the east high point of the Moxi structure. During the overbalanced drilling of the Longwangmiao Formation in this well with the drilling fluid of 1.70e1.75 g/cm3, gas cut was seen for five times and the total hydrocarbon in gas survey reached a maximum of 65.32%. Logging interpretation showed 4 reservoirs, with a cumulative thickness of 528.6 m, a reservoir thickness of 451.0 m, an average porosity of 4.7% and an average permeability of 1.0mD, in which the thickness of Type I reservoir was 1.25 m (4 ¼ 12.8%), the thickness of Type II reservoir was 80.9 m (4 ¼ 7.3%), and the thickness of Type III reservoir was 368.88 m (4 ¼ 4.1%). The imaging logging shows that fractures and dissolved pores and cavities are well-developed. The reservoir is characterized by long intervals, different degrees of pore, hole and crack development, strong
Fig. 6. Drilling fluid filtrate invasion depth profile along the wellbore.
Fig. 7. Drilling fluid damage skin factor profile along the wellbore.
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Fig. 9. Comparison of cumulative acid absorption profiles between diverting acid and gelled acid.
Fig. 8. Distribution of acidification simulation parameters with VES concentration of 5%.
heterogeneity and complicated damage of drilling and completion fluids. Considering drilling fluid solid-phase filter cake deposition and erosion, filtrate invasion, and permeability damage [22], it is possible to calculate the drilling fluid filtrate invasion depth and skin factor profile along the wellbore profile (Figs. 6 and 7). It can be seen from the damage profile that the invasion depth of drilling fluid filtrate and the damage skin are generally in the shape of an ellipse with a large heel end and a small toe end. However, due to the uneven development of pores, holes and cracks, there are local fluctuations.
In this well, liner completion was adopted with a slotted section of 4738.0e5400.0 m, and only general acidification can be used. Based on the established model of diverting acid acidizing, the distribution of pH value, Ca2þ concentration, acid viscosity and acid-etched wormholes in the process of diverting acid acidizing by using the difference solution in the cylindrical coordinate system (r, q, z) (Fig. 8). It can be seen that there is fresh acid with low pH value, low Ca2þ concentration and low viscosity inside the acid-etched wormholes (red area in Fig. 8-d), while around the wormholes (green area in Fig. 8-a), the fresh acid inside the wormholes reacts with the wall rock of the wormhole, the acid concentration decreases, and the pH value increases to 2e3. The generated Ca2þ is displaced into the reservoir and forms a high-viscosity area around the wormhole (Fig. 8-c), forcing the acid to enter other intervals. In addition, the cumulative acid entry profiles of the diverted acid with 5% VES concentration and the conventional gelled acid were compared (Fig. 9). The diverted acid formed a high-viscosity area in the interval with a high liquid absorption ability, forcing the acid to enter the interval with a weak liquid absorption ability, so that the liquid absorption volume of the interval with a high liquid absorption ability decreased and the entire fluid entry profile became more uniform. As the viscosity of diverting acid changes with the progress of aciderock reaction, it is possible to achieve the purpose of improving the acid-absorbing profile of the long-interval reservoir with strong heterogeneity and realizing the targeted acid placement. The well was acidified with diverting acid at VES concentration of 4% and 5%. The construction curve is shown in Fig. 10. After acid entered the formation, the displacement increased from 6.0 m3/min to 8.2 m3/min and pump pressure decreased from 60.14 MPa to 45.44 MPa. Thus, the acid solution relieved the damage of drilling fluid filter cake. Then the displacement was maintained, the pump pressure continued to decline to 37.7 MPa, the acid-etched wormholes caused by diverting acid broke through the damage zone, and a significant effect of plugging removal appeared. In the process, the
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Fig. 10. Construction curve of diverting acid acidizing in Well Moxi 008-17-X1.
Table 2 Statistics of diverting acid acidizing with different VES concentrations in the Longwangmiao Fm gas reservoirs. Well no.
Moxi Moxi Moxi Moxi Moxi Moxi Moxi Moxi
008-H1 008-H19 009-X5 008-X16 008-17-X1 008-20-H2 008-6-X2 008-12-X1
Interval/m
4699.5e5436.0 4689.7e5600.0 5045.9e5650.6 4962.4e5448.4 4738.0e5302.8 4881.0e5830.0 4781.7e5280.0 4856.8e5335.0
Diverting acid injection/m3
Displacement/ (m3$min1)
Pump pressure/ MPa
517.62 674.82 619.83 599.16 676.47 600.00 680.00 599.45
5.4e6.1 4.5e5.1 3.0e3.2 6.0e6.5 8.2e8.3 4.0e5.5 6.3e6.8 3.4e3.6
86e91 65e70 68e70 65e67 55e60 65e70 61e67 67e70
pump pressure increased from 41.31 MPa to 43.93 MPa, showing an obvious diversion effect. The well was tested with a Ø50.8 mm critical velocity flowmeter. The test output before acidification was 143.18 104 m3/d, the test output after acidification was 227.07 104 m3/d, and the unobstructed flow was converted to be 800 104 m3/d. The production stimulation ratio was 1.59. Acidification tests with different VES concentrations were conducted in 8 wells in the Longwangmiao Fm gas reservoirs (Table 2). After reservoir stimulation, the cumulative test output was 1233.46 104 m3/d with an average production stimulation ratio of 1.95. Production stimulation effect was obvious. 5. Conclusions 1) The strong heterogeneity and the complexity of drilling and completion fluid damage of the Longwangmiao Fm dolomite reservoirs cause the difficulty in placing the acid in the targeted area, and the viscosity of the VES diverting acid increases acid with the aciderock reaction. Diverting acid can obviously improve the acid-absorbing profile of reservoirs with strong heterogeneity and increase the stimulation degree of low-permeability reservoirs. 2) The concentrations of calcium ions and VES were tracked during the diverting acid acidizing, which was combined with the empirical model of the diverting acid rheological
Test output/(104 m3$d1) Before acidification
After acidification
78.73 44.48 113.00 119.95 143.18 86.34 55.61 53.59
182.77 155.04 176.62 165.59 227.07 110.85 106.77 108.75
Production stimulation ratio
2.32 3.49 1.56 1.38 1.59 1.28 1.92 2.03
behavior and two-scale wormhole expansion model to realize the numerical simulation of diverting acid acidizing. 3) The placement technology developed for variable VES concentration diverting acid in horizontal wells and long-interval highly deviated wells completed with slotted liners has a remarkable field application effect and can effectively resolve the problem of uneven acid absorption profile caused by strong reservoir heterogeneity and the complexity of damage degree, so that the natural productivity of gas wells will be developed.
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Please cite this article in press as: Yue H, et al., Numerical simulation and field application of diverting acid acidizing in the Lower Cambrian Longwangmiao Fm gas reservoirs in the Sichuan Basin, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.04.007