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Gas kick during carbonate reservoirs drilling and its risk assessment
PETROLEUM EXPLORATION AND DEVELOPMENT Volume 44, Issue 3, June 2017 Online English edition of the Chinese language journal Cite this article as: PETROL. EXPLOR. DEVELOP., 2017, 44(3): 462–469.
RESEARCH PAPER
Gas kick during carbonate reservoirs drilling and its risk assessment GUO Yanli1, SUN Baojiang1, *, GAO Yonghai1, LI Hao1, WU Changfu2 1. School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China; 2. Engineering Technology Branch, CNOOC Energy Technology & Services Limited, Shenzhen 518000, China
Abstract: The gas kick characteristics during carbonate reservoir drilling were analyzed taking carbonate reservoirs in Shunnan area of Tazhong as an example, a quantitative evaluation method for gas kick risk was established, and then a case was simulated. Looking into reservoir space characteristics and gas invasion mechanisms of carbonate reservoirs in Shunnan area based on drilling geologic data, it is found that the reservoirs are rich in fractures, pores and caves, and the gas invades into wellbore through gas-liquid replacement and differential pressure. By fully considering the gas invasion mechanism, gas migration law and wellbore temperature-pressure field, and introducing the gas volume fraction density function, a quantitative evaluation method for gas kick risk and a method for ranking well control risk were established. The case study shows that the wellhead back pressure method can be used to tell the mode of gas invasion; pore-fracture-cave and acid gas characteristics in carbonate reservoirs have stronger effect on the gas volume fraction in wellbore, and may cause hidden and severe gas kick; the effects of well depth, well diameter, drilling fluid density, drilling fluid displacement, drilling fluid viscosity and drilling rate on gas kick risks weaken in that order. Key words: carbonate reservoir; well drilling; gas kick; gas-liquid replacement; well control; risk assessment
Introduction Carbonate reservoirs are often drilled during oil and gas exploration at home and abroad, and the karst fracture-cave carbonate reservoirs in Sichuan Basin, Ordos Basin and Tarim Basin of China have been drilled successfully in recent years[13]. Most of the reservoirs in Tahe Oilfield are located in the Ordovician carbonate formation, in which the reservoir space is discontinuous or reticular, forming fracture-cave reservoirs with complex vertical and lateral reservoir properties[46]. The carbonate reservoirs in Tazhong area have large burial depth, high geothermal gradient, and fractures and caves in mixed distribution, posing great challenge to the optimization of wellbore structure and drilling technology. Narrow safe density window of fracture-cave gas layer, lack of effective methods to maintain stable pressure fracture gas layers, high temperature and high pressure, and corrosive and poisonous gases, all add difficulty to the safe and efficient drilling of the gas reservoirs. Hence, preventing and controlling gas kicks in high-pressure gas wells has become the main technical problem during the oil and gas drilling in this area. In recent years, the techniques such as managed pressure
drilling for horizontal wells, closed loop drilling system, plugging and killing technology for blowout-lost circulation coexistence formation have been developed for the well control of carbonate reservoirs in Tazhong area[79]. Some researches were also carried out on the coexistence of blowout and leakage caused by the gravity displace in fracture-cave carbonate reservoirs[1015]. In view of the multiphase flow in annulus, many researchers proposed mathematical models for different conditions from different angles[1624]. Common gas kick risk assessment methods are mostly qualitative or semi-quantitative models established using analytic hierarchy process or fault tree method with uncertainties[2526]. In this study, the gas kick characteristics during the carbonate reservoirs drilling in Tazhong Shunnan area are analyzed based on geological data, and a quantitative evaluation method for gas kick risk is established to guide the design of field operation parameters and reduce the gas kick risk.
1.
Gas kick in carbonate reservoir drilling
The oil and gas reservoirs in Tazhong Shunnan area are mainly distributed in the Ordovician carbonate formation, including Yijianfang Formation, Yingshan Formation and
Received date: 25 Jun. 2016; Revised date: 13 Mar. 2017. * Corresponding author. E-mail: [email protected] Foundation item: Supported by the National Key Basic Research Program of China (973 Program) (2015CB251200); the National Science and Technology Major Project of China (2016ZX05020-006); the Program for Changjiang Scholars and Innovative Research Team in University (No. IRT_14R58). Copyright © 2017, Research Institute of Petroleum Exploration and Development, PetroChina. Published by Elsevier BV. All rights reserved.
GUO Yanli et al. / Petroleum Exploration and Development, 2017, 44(3): 462–469
Fig. 1.
Carbonate cores taken from the Ordovician in Tazhong Shunnan area.
Penglaiba Formation. The pore-fracture-cave characteristics in the carbonate reservoirs were analyzed based on the cores and imaging logging data of the Ordovician carbonate rocks in Shunnan area (Figs. 1 and 2). For Well A, 1# core (Fig. 1a) has two large fractures of 57 mm wide; 2 # core (Fig. 1b) has seven medium fractures of 13 mm wide; 3 # core (Fig. 1c) has two large fractures of 58 mm wide and six medium fractures of 12 mm wide. All the three cores contain some small caves of 13 mm in diameter. For Well B, 1# core (Fig. 1d) has one vertical fracture of 0.10.3 mm wide running through the core; 2# and 3# cores (Fig. 1e, 1f) have one horizontal fracture of about 0.1 mm wide each. The imaging logging data of Well-C (Fig. 2) show the development of fractures and caves too.
Fig. 2. Imaging logging of the Ordovician carbonate rock in Tazhong Shunnan area.
It can be seen from the cores that fractures less than 3 mm and caves of 110 mm in diameter are abundant; large scale fractures (more than 3 mm wide) and caves (more than 10 mm in diameter) are seen occasionally; most fractures are high angle ones, crossing with some vertical ones; the fractures, pores and caves are mostly filled by formation fluids, making well kick and leakage likely. Based on the reservoir space characteristics of the carbonate reservoirs and the overflow phenomenon during the drilling of Well C in Tazhong Shunnan area (Table 1), the gas kick characteristics have been looked into from the perspectives of gas kick type and acid gas phase change. Due to the pore-fracture-cave structure of the carbonate reservoirs, the gas kick types can transform from the differential pressure invasion to the gas-liquid replacement invasion (with the density difference between formation gas and drilling fluid as the driving force[13]). Differential pressure invasion occurs when the cave or fracture pressure is larger than the bottom hole pressure; gas-liquid replacement invasion occurs when the former is less than the latter. Table 1 shows the overflows occurring in Well C of Shunnan area. It can be seen that the liquid level of drilling fluid pit became stable after increasing the drilling fluid density two times, but the flame height decreased from 10-12 m to 6-7 m, and then no longer reduced. That means the gas kept invading at the bottom hole during the increasing of drilling fluid density, and only weakened overflow in strength. Because the formation pressure was larger than the bottom hole pressure at the early stage, and the gas kick was differential pressure invasion; and then it transformed into gas-liquid replacement invasion after increasing the drilling fluid density. Although the overflow kept going on, it couldn't be reflected by the recording of the liquid level of drilling fluid pit, for it was caused by the formation gas phase change. The phase diagrams of CH4, CO2, H2S and their mixture were analyzed (Fig. 3, calculated by PVTsim software). The phase states of natural gas containing acid gas may undergo in turn the supercritical phase, liquid phase, gas-liquid phase and gas phase in the formation temperature range. The formation gas can be in the supercritical or liquid states when invading
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Table 1.
Overflows during the drilling of Well C in Tazhong Shunnan area
Date
Liquid level of drilling fluid pit
Flame height
Next step
21:36:00, ignition succeeds, flame height 12 m; 23:20:00, flame height rises to 10 m
To increase the drilling fluid density from 1.65 g/cm3 to 1.70 g/cm3
03:15:00, liquid level is stable, flame height 78 m
To increase the drilling fluid density from 1.70 g/cm3 to 1.75 g/cm3, circulating ventilation
10:00:00 to 20:30:00, flame height 45 m
Replacing the rubber core
00:35:00, flame height rises to 1215 m, batch flow at wellhead; 01:04:00, flame height 67 m; 03:20:00, flame height 1012 m; 03:30:00, flame height 67 m
Circulating ventilation
21:05:00, liquid level rise by 0.5 m3; circulation at wellhead back pressure of 2 MPa, liquid level rises by 0.5 14 Jan. m3; pump off, well shut-in and observation for 15 min, casing pressure rises from 0.5 MPa to 4.5 MPa 03:00:00 to 03:15:00, liquid level rises by 0.6 m3; 15 Jan. 03:15:00, restore the wellhead back pressure to 6.5 MPa, liquid level is stable 15 Jan.
10:00:00 to 20:30:00, liquid level is stable
00:35:00, liquid level rises by 0.5 m3, increases wellhead back pressure from 2 MPa to 6 MPa; 01:04:00, adjust wellhead back pressure to 4 MPa, liquid level stable; 16 Jan. 03:20:00, adjust wellhead back pressure to 2 MPa, liquid level rises by 0.7 m3; 03:30:00, restore wellhead back pressure to 4 MPa, liquid level stable
Fig. 3.
a constant (reservoir productivity) under a certain condition of reservoir characteristics and wellbore structure. Since the carbonate reservoirs in Shunnan area are large in burial depth, high in temperature and pressure, and contain acid gas, it is difficult to identify the gas kick type according to drilling parameters. Zhang et al.[13] proposed to distinguish the gas kick type using the wellhead back pressure: when the bottom hole pressure changed from underbalance to overbalance by applying the wellbore back pressure, if the drilling fluid pit gained volume or outlet flow rate basically kept stable, it was regarded as pressure difference invasion; if the drilling fluid pit gain kept increasing in the previous trend, it was regarded as gas-liquid replacement invasion.
Formation gas phase diagram.
into the bottom hole, so the exchange volume between the gas and drilling fluid per unit time is small. Therefore, the liquid level of drilling fluid pit has no obvious change within a short time.
2. Analysis model of gas kick in carbonate reservoir drilling 2.1.
Gas kick volume
Based on the analysis of gas kick characteristics during the carbonate reservoir drilling, gas kick volume models for differential pressure invasion and gas-liquid replacement invasion were established, respectively. The differential pressure invasion is mainly affected by the negative pressure between bottom hole pressure and formation pressure, drilled reservoir thickness, reservoir permeability and gas properties. The gas kick volume model can be established based on the percolation mechanics theory[27]:
Qg
774.6 KH pe2 pw2 T g Z ln re rw
(1)
The gas-liquid replacement invasion is mainly affected by factors such as reservoir permeability, porosity and borehole radius, in other words, its gas kick volume model is a function of the above three parameters. Therefore, it can be assumed as
2.2.
Wellbore temperature-pressure field
The wellbore temperature-pressure field is the basis for calculation of the annular pressure distribution and hydraulic parameter design in the drilling engineering. Considering various drilling conditions and influencing factors, many scholars have carried out extensive researches on wellbore temperature-pressure field[1624]. Since the effects of acid gas such as CO2 and H2S must be considered in the carbonate reservoir drilling, the model must have a higher accuracy. Therefore, the wellbore multiphase flow model considering acid gas in the reference [24] has been used in this study, and its governing equations, auxiliary equations and solution methods are elaborated in reference [24]. 2.3.
Wellbore gas volume fraction
When the gas invade into bottom hole and rises up along the wellbore in drilling, the gas-liquid two-phase flow pattern usually transforms from bubble flow to slug flow[28]; if the gas kick is severe, the flow pattern will turn into churn flow or annular flow. Due to different calculating methods for gas drift velocity and gas volume fraction in different flow patterns, the effect of flow pattern must be considered in calculating the gas volume fraction[29]. (1) Bubble flow. The existence condition of bubble flow is:
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GUO Yanli et al. / Petroleum Exploration and Development, 2017, 44(3): 462–469
vsg k1 0.429vsl 0.357vgr
(2)
The gas drift velocity equation is:
g l g vgr 1.53 l2
0.25
(3)
The gas volume fraction equation is:
Eg vsg
c v
0 am
vgr
(4)
(2) Slug flow. The existence condition of it is:
vsg k1 0.429vsl 0.357vgr
(5)
The gas drift velocity equation is:
D vgr 0.3 0.22 dr Dp
g Ddr Dp l g l
0.5
(6)
The gas volume fraction equation is the same as that of bubble flow, but the velocity distribution coefficient c0 is different. (3) Churn flow. The existence condition of it is:
g vsg2 25.41lg l vsl2 38.9 l vsl2 > 74.4 2 1.7 l vsl2 74.4 g vsg 0.005 1 l vsl2 0.333 vsg k2 g l g g2
(7)
0.25
(8)
The gas drift velocity and gas volume fraction equations are the same as that of slug flow, but the velocity distribution coefficient c0 is different. (4) Annular flow. The existence condition of it is: 0.333 vsg k2 g l g g2
0.25
(9)
The gas volume fraction equation is:
Eg 1 Y 0.8
where, Y 1 x x 2.4.
0.9
l
g
0.5
0.378
(10)
g . 0.1
l
Wellbore gas volume fraction density function
The change of wellbore gas volume fraction directly results in the wellbore pressure change, when the invading gas rises up along the wellbore during drilling process. The wellbore gas volume fraction can be predicted by combining eq. (1)-eq. (10) and the model of wellbore temperature-pressure field. That is, the distribution profile of wellbore gas volume fraction within a certain overflow time can be obtained. A quantitative evaluation method for the gas kick risk during the drilling process has been proposed by introducing the following gas volume fraction density function. The function is defined as the cumulative curve of gas volume fraction along the well depth within a certain overflow time:
acg t
hwh
hbh
Eg h dh
can be classified into reservoir characteristics, gas characteristics and field operation design, etc. The gas kick risks during carbonate reservoir drilling in Shunnan area were evaluated using the proposed gas kick analysis model. The basic data are as follows: well depth of 2 652 m; case diameter of 244.5 mm (9.625 in); drill string diameter of 127.0 mm (5 in); rate of penetration of 5 m/h; drilling fluid displacement of 30 L/s; drilling fluid density and viscosity of 0.98 g/cm3 and 14 mPa·s, respectively; surface temperature of 20 C; geothermal gradient of 0.031 C/m; formation fracturing pressure gradient of 0.014 MPa/m; relative density of formation oil and natural gas of 0.80 and 0.92, respectively. 3.1. Effects of gas kick type and gas properties on wellbore gas volume fraction By using wellhead back pressure to tell the gas kick type, the variation patterns of wellbore gas volume fraction under differential pressure invasion and gas-liquid replacement invasion have been obtained, respectively (Fig. 4). It can be seen from Fig. 4 that before applying wellhead back pressure, the overflow curves simulated for 10 mins under two different invasion types are similar; after applying wellhead back pressure, the overflow curves simulated for 10 mins under the two types of invasions show that there is no longer any gas invading into the bottom hole in the differential pressure invasion mode, but gas invading keeps going on in the gas-liquid replacement invasion mode. It also indicates that it is feasible to tell the gas kick type by the method of applying wellhead back pressure[13]. Taking gas-liquid replacement as an example, the effect of gas kick volume on the wellbore gas volume fraction was analyzed (Fig. 5). It can be seen that under the same overflow time, the larger the gas kick volume is, the larger the wellbore gas volume fraction and the higher the gas rising up velocity are. Taking gas-liquid replacement invasion as an example, the change pattern under effects of acid gases (CO2, H2S) on the wellbore gas volume fraction were also obtained by simulating overflow for 10 mins (Fig. 6). Under the same gas inflow rate, the higher the acid gas content is, the smaller the well-
(11)
3. Assessment of gas kick risk during carbonate reservoir drilling There are many incentives of gas kick risk[1415, 30], which
Fig. 4. Variations of wellbore gas volume fraction in differential pressure invasion and gas-liquid replacement invasion.
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containing acid gas is hard to detect, due to its smaller volume at the bottom hole and its slower rising up velocity along the wellbore. 3.2.
Fig. 5. Variations of wellbore gas volume fraction under different gas kick volumes in gas-liquid replacement invasion.
Quantitative evaluation method for gas kick risk
The acid gas and reservoir permeability etc. have strong influences on the gas kick risk, but they are uncontrollable. In contrast, the field operation parameters can be adjusted to prevent gas kick. Therefore, considering the effects of field operation parameters on wellbore gas volume fraction, the wellbore gas volume fraction density function was used to establish a quantitative evaluation method for the gas kick risk based on the dimensionless field operation parameters. The procedures are as follows. 3.2.1. Effects of field operation parameters on wellbore gas volume fraction
Fig. 6. Variations of wellbore gas volume fraction under different invasion gas types.
bore gas volume fraction is. Under the same acid gas content, the wellbore gas volume fraction is smaller when the gas containing H2S compared to the gas containing CO2. The rising velocity of natural gas with acid gas in the wellbore is smaller than that of pure natural gas. Because the acid gases (especially H2S) have high solubility in drilling fluid and are in supercritical state[21] after invading into the bottom hole from the carbonate reservoirs. Therefore, the gas kick of natural gas
Fig. 7.
The field operation parameters are the basic parameters of well control design and are controllable. Therefore, the first step of gas kick risk assessment is to obtain the effect law of field operation parameters on wellbore gas volume fraction, including mechanical parameters, drilling fluid physical parameters and wellbore structure parameters. When analyzing the effect of one parameter, only this parameter took different values and other parameters were the same with the basic data. The variations of wellbore gas volume fraction with different physical parameter construction parameters were obtained by simulating overflow for 10 mins (Fig. 7). 3.2.2. Dimensionless operation parameters and sensitive factor calculation Based on the effects of operation parameters on wellbore gas volume fraction, the wellbore gas volume fraction densities under different operation parameters were calculated using eq. (11) (Table 2).
Variations of wellbore gas volume fraction with different physical parameters.
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Table 2.
Wellbore gas volume fraction densities under different operation parameters
Drilling fluid displacement/(L·s1)
Rate of penetration/(m·h1)
Drilling fluid density/(g·cm3)
Drilling fluid viscosity/(mPa·s)
Well diameter/mm
Well depth/m
Wellbore gas volume fraction density/m
12
5
0.98
10
244.5
2 652
96.104
22
5
0.98
10
244.5
2 652
94.752
30
5
0.98
10
244.5
2 652
94.241
30
10
0.98
10
244.5
2 652
94.200
30
20
0.98
10
244.5
2 652
94.200
30
30
0.98
10
244.5
2 652
94.199
30
5
0.98
10
244.5
2 652
94.241
30
5
1.07
10
244.5
2 652
86.535
30
5
1.30
10
244.5
2 652
72.256
30
5
0.98
10
244.5
2 652
94.241
30
5
0.98
20
244.5
2 652
93.461
30
5
0.98
30
244.5
2 652
92.352
30
5
0.98
10
219.1
2 652
119.338
30
5
0.98
10
244.5
2 652
94.241
30
5
0.98
10
269.9
2 652
76.671
30
5
0.98
10
244.5
1 500
169.015
30
5
0.98
10
244.5
2 016
98.567
30
5
0.98
10
244.5
2 652
94.241
Due to different units and ranges, the effects of the operation parameters on wellbore gas volume fraction density cannot be compared quantitatively. Therefore, the operation parameters were transformed into dimensionless ones by using the basic data as standard, and then the sensitivity factor was calculated. Taking the drilling fluid displacement as an example, the specific calculation method is as follows. (1) Dimensionless method of the drilling fluid displacement and wellbore gas volume fraction density: i Qi Qstd (12)
i acgi acg, std
(13)
In this case, Q1, Q2 and Qstd are 12, 22 and 30 L/s, respectively; ρacg1, ρacg2 and ρacg, std are 96.104, 94.752 and 94.241 m; α1, α2, β1, β2calculated by eq. (12)，and eq. (13) are 0.400, 0.733, 1.020 and 1.005 respectively. (2) Define the sensitivity factor of drilling fluid displacement as: 1 2 1 2 (14) The sensitivity factor of drilling fluid displacement calculated by eq. (14) is 0.045. Similarly, the calculated sensitivity factors of rate of penetration, drilling fluid density, drilling fluid viscosity, well diameter and well depth are 1.1×105, 0.646, 0.012, 2.179 and 3.842, respectively. 3.2.3.
Quantitative description of gas kick risk
The sensitivity factor of a parameter reflects the response intensity of wellbore gas volume fraction density to the change of the parameter. That is, the larger the absolute value of the sensitivity factor is, the higher the response intensity is.
The negative values indicate that the wellbore gas volume fraction density has negative correlation with the corresponding parameters. That is, the gas kick risk becomes smaller with the increase of the parameter. It can be seen that rate of penetration has little effect on gas kick risk; drilling fluid displacement and viscosity have small effects, and well diameter, well depth and drilling fluid density have large effects on gas kick risk. Therefore, the wellbore structure, drilling assembly and drilling fluid can be optimized based on pore-fracturecave characteristics and sensitivity factor of field parameters in carbonate reservoir drilling. 3.3.
Method for ranking well control risk
Well killing measures are usually taken when gas kick occurs in drilling, during which judging the difficulty and risk of well control is the key for selecting killing methods and related measures. Therefore, a method for ranking well control risk has been proposed based on the wellbore gas volume fraction density function. Fig. 8 shows the variations of wellbore gas volume fraction density with time in this case. Hereby, the well control risks are classified into three levels: (1) The first grade well control risk, refers to the risk when the invading gas mixture is close to the bottom hole and relatively small in volume, this kind of risk is hard to detect but easy to be brought under control. (2) The second grade well control risk refers to the risk with drop of wellbore pressure and larger invaded gas volume as the gas mixture rises up, at this point, some gas is released from the drilling fluid, and rise of drilling fluid level in mud pit can be monitored. (3) The third grade well control risk refers to the risk when gas mixture rises up and expands drastically near the wellhead. If the overflow in
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Qg—gas kick volume, m3/d; Qstd—standard drilling fluid displacement, L/s; re, rw—supply boundary and borehole radius, m; T—reservoir temperature, K; vgr—gas drift velocity, m/s; vsl, vsg, vam—apparent phase velocity of liquid, gas and their mixture, m/s; x—gas flow factor; Z—reservoir gas compressibility factor; αi—dimensionless drilling fluid displacement; βi—dimensionless wellbore gas volume fraction density; Fig. 8. Ranking of well control risks based on wellbore gas volume fraction density function.
Δt—overflow time, s;
bottom hole continued at this time, well control difficulty level would increase, and blowout is likely to happen.
ρacg—wellbore gas volume fraction density within a certain over-
4.
μg, μl—viscosity of gas and liquid phase, mPa·s; flow time, m; ρacg, std—standard wellbore gas volume fraction density, m;
Conclusions
ρg, ρl—density of gas and liquid phase, kg/m3;
The gas kick characteristics during carbonate reservoir drilling were analyzed based on the geologic data in Tazhong Shunnan area, which shows that the gas invades into a wellbore mainly in two modes, gas-liquid replacement and differential pressure. The pore-fracture-cave characteristics of carbonate reservoirs and high solubility and supercritical phase of acid gases have great influence on wellbore gas volume fraction, which can cause hidden and severe gas kicks. Fully considering the gas invasion mechanism, gas migration law in wellbore and wellbore temperature-pressure field, a model of predicting wellbore gas volume fraction has been built after gas invasion. Moreover, a quantitative evaluation method for gas kick risk by introducing the gas volume fraction density function has been proposed. The case study shows that the influences of well depth, well diameter, drilling fluid density, drilling fluid displacement, drilling fluid viscosity and rate of penetration on gas kick risk weaken in turn, and the risk decreases with the increase of the parameters. Moreover, the well control risks are classified into three levels based on the variations of wellbore gas volume fraction density with time, which can guide the selection of killing methods and related measures.
σ—surface tension, N/m; χ—sensitive factor of drilling fluid displacement. Subscript: i—data number.
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RESEARCH PAPER
Gas kick during carbonate reservoirs drilling and its risk assessment GUO Yanli1, SUN Baojiang1, *, GAO Yonghai1, LI Hao1, WU Changfu2 1. School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China; 2. Engineering Technology Branch, CNOOC Energy Technology & Services Limited, Shenzhen 518000, China
Abstract: The gas kick characteristics during carbonate reservoir drilling were analyzed taking carbonate reservoirs in Shunnan area of Tazhong as an example, a quantitative evaluation method for gas kick risk was established, and then a case was simulated. Looking into reservoir space characteristics and gas invasion mechanisms of carbonate reservoirs in Shunnan area based on drilling geologic data, it is found that the reservoirs are rich in fractures, pores and caves, and the gas invades into wellbore through gas-liquid replacement and differential pressure. By fully considering the gas invasion mechanism, gas migration law and wellbore temperature-pressure field, and introducing the gas volume fraction density function, a quantitative evaluation method for gas kick risk and a method for ranking well control risk were established. The case study shows that the wellhead back pressure method can be used to tell the mode of gas invasion; pore-fracture-cave and acid gas characteristics in carbonate reservoirs have stronger effect on the gas volume fraction in wellbore, and may cause hidden and severe gas kick; the effects of well depth, well diameter, drilling fluid density, drilling fluid displacement, drilling fluid viscosity and drilling rate on gas kick risks weaken in that order. Key words: carbonate reservoir; well drilling; gas kick; gas-liquid replacement; well control; risk assessment
Introduction Carbonate reservoirs are often drilled during oil and gas exploration at home and abroad, and the karst fracture-cave carbonate reservoirs in Sichuan Basin, Ordos Basin and Tarim Basin of China have been drilled successfully in recent years[13]. Most of the reservoirs in Tahe Oilfield are located in the Ordovician carbonate formation, in which the reservoir space is discontinuous or reticular, forming fracture-cave reservoirs with complex vertical and lateral reservoir properties[46]. The carbonate reservoirs in Tazhong area have large burial depth, high geothermal gradient, and fractures and caves in mixed distribution, posing great challenge to the optimization of wellbore structure and drilling technology. Narrow safe density window of fracture-cave gas layer, lack of effective methods to maintain stable pressure fracture gas layers, high temperature and high pressure, and corrosive and poisonous gases, all add difficulty to the safe and efficient drilling of the gas reservoirs. Hence, preventing and controlling gas kicks in high-pressure gas wells has become the main technical problem during the oil and gas drilling in this area. In recent years, the techniques such as managed pressure
drilling for horizontal wells, closed loop drilling system, plugging and killing technology for blowout-lost circulation coexistence formation have been developed for the well control of carbonate reservoirs in Tazhong area[79]. Some researches were also carried out on the coexistence of blowout and leakage caused by the gravity displace in fracture-cave carbonate reservoirs[1015]. In view of the multiphase flow in annulus, many researchers proposed mathematical models for different conditions from different angles[1624]. Common gas kick risk assessment methods are mostly qualitative or semi-quantitative models established using analytic hierarchy process or fault tree method with uncertainties[2526]. In this study, the gas kick characteristics during the carbonate reservoirs drilling in Tazhong Shunnan area are analyzed based on geological data, and a quantitative evaluation method for gas kick risk is established to guide the design of field operation parameters and reduce the gas kick risk.
1.
Gas kick in carbonate reservoir drilling
The oil and gas reservoirs in Tazhong Shunnan area are mainly distributed in the Ordovician carbonate formation, including Yijianfang Formation, Yingshan Formation and
Received date: 25 Jun. 2016; Revised date: 13 Mar. 2017. * Corresponding author. E-mail: [email protected] Foundation item: Supported by the National Key Basic Research Program of China (973 Program) (2015CB251200); the National Science and Technology Major Project of China (2016ZX05020-006); the Program for Changjiang Scholars and Innovative Research Team in University (No. IRT_14R58). Copyright © 2017, Research Institute of Petroleum Exploration and Development, PetroChina. Published by Elsevier BV. All rights reserved.
GUO Yanli et al. / Petroleum Exploration and Development, 2017, 44(3): 462–469
Fig. 1.
Carbonate cores taken from the Ordovician in Tazhong Shunnan area.
Penglaiba Formation. The pore-fracture-cave characteristics in the carbonate reservoirs were analyzed based on the cores and imaging logging data of the Ordovician carbonate rocks in Shunnan area (Figs. 1 and 2). For Well A, 1# core (Fig. 1a) has two large fractures of 57 mm wide; 2 # core (Fig. 1b) has seven medium fractures of 13 mm wide; 3 # core (Fig. 1c) has two large fractures of 58 mm wide and six medium fractures of 12 mm wide. All the three cores contain some small caves of 13 mm in diameter. For Well B, 1# core (Fig. 1d) has one vertical fracture of 0.10.3 mm wide running through the core; 2# and 3# cores (Fig. 1e, 1f) have one horizontal fracture of about 0.1 mm wide each. The imaging logging data of Well-C (Fig. 2) show the development of fractures and caves too.
Fig. 2. Imaging logging of the Ordovician carbonate rock in Tazhong Shunnan area.
It can be seen from the cores that fractures less than 3 mm and caves of 110 mm in diameter are abundant; large scale fractures (more than 3 mm wide) and caves (more than 10 mm in diameter) are seen occasionally; most fractures are high angle ones, crossing with some vertical ones; the fractures, pores and caves are mostly filled by formation fluids, making well kick and leakage likely. Based on the reservoir space characteristics of the carbonate reservoirs and the overflow phenomenon during the drilling of Well C in Tazhong Shunnan area (Table 1), the gas kick characteristics have been looked into from the perspectives of gas kick type and acid gas phase change. Due to the pore-fracture-cave structure of the carbonate reservoirs, the gas kick types can transform from the differential pressure invasion to the gas-liquid replacement invasion (with the density difference between formation gas and drilling fluid as the driving force[13]). Differential pressure invasion occurs when the cave or fracture pressure is larger than the bottom hole pressure; gas-liquid replacement invasion occurs when the former is less than the latter. Table 1 shows the overflows occurring in Well C of Shunnan area. It can be seen that the liquid level of drilling fluid pit became stable after increasing the drilling fluid density two times, but the flame height decreased from 10-12 m to 6-7 m, and then no longer reduced. That means the gas kept invading at the bottom hole during the increasing of drilling fluid density, and only weakened overflow in strength. Because the formation pressure was larger than the bottom hole pressure at the early stage, and the gas kick was differential pressure invasion; and then it transformed into gas-liquid replacement invasion after increasing the drilling fluid density. Although the overflow kept going on, it couldn't be reflected by the recording of the liquid level of drilling fluid pit, for it was caused by the formation gas phase change. The phase diagrams of CH4, CO2, H2S and their mixture were analyzed (Fig. 3, calculated by PVTsim software). The phase states of natural gas containing acid gas may undergo in turn the supercritical phase, liquid phase, gas-liquid phase and gas phase in the formation temperature range. The formation gas can be in the supercritical or liquid states when invading
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Table 1.
Overflows during the drilling of Well C in Tazhong Shunnan area
Date
Liquid level of drilling fluid pit
Flame height
Next step
21:36:00, ignition succeeds, flame height 12 m; 23:20:00, flame height rises to 10 m
To increase the drilling fluid density from 1.65 g/cm3 to 1.70 g/cm3
03:15:00, liquid level is stable, flame height 78 m
To increase the drilling fluid density from 1.70 g/cm3 to 1.75 g/cm3, circulating ventilation
10:00:00 to 20:30:00, flame height 45 m
Replacing the rubber core
00:35:00, flame height rises to 1215 m, batch flow at wellhead; 01:04:00, flame height 67 m; 03:20:00, flame height 1012 m; 03:30:00, flame height 67 m
Circulating ventilation
21:05:00, liquid level rise by 0.5 m3; circulation at wellhead back pressure of 2 MPa, liquid level rises by 0.5 14 Jan. m3; pump off, well shut-in and observation for 15 min, casing pressure rises from 0.5 MPa to 4.5 MPa 03:00:00 to 03:15:00, liquid level rises by 0.6 m3; 15 Jan. 03:15:00, restore the wellhead back pressure to 6.5 MPa, liquid level is stable 15 Jan.
10:00:00 to 20:30:00, liquid level is stable
00:35:00, liquid level rises by 0.5 m3, increases wellhead back pressure from 2 MPa to 6 MPa; 01:04:00, adjust wellhead back pressure to 4 MPa, liquid level stable; 16 Jan. 03:20:00, adjust wellhead back pressure to 2 MPa, liquid level rises by 0.7 m3; 03:30:00, restore wellhead back pressure to 4 MPa, liquid level stable
Fig. 3.
a constant (reservoir productivity) under a certain condition of reservoir characteristics and wellbore structure. Since the carbonate reservoirs in Shunnan area are large in burial depth, high in temperature and pressure, and contain acid gas, it is difficult to identify the gas kick type according to drilling parameters. Zhang et al.[13] proposed to distinguish the gas kick type using the wellhead back pressure: when the bottom hole pressure changed from underbalance to overbalance by applying the wellbore back pressure, if the drilling fluid pit gained volume or outlet flow rate basically kept stable, it was regarded as pressure difference invasion; if the drilling fluid pit gain kept increasing in the previous trend, it was regarded as gas-liquid replacement invasion.
Formation gas phase diagram.
into the bottom hole, so the exchange volume between the gas and drilling fluid per unit time is small. Therefore, the liquid level of drilling fluid pit has no obvious change within a short time.
2. Analysis model of gas kick in carbonate reservoir drilling 2.1.
Gas kick volume
Based on the analysis of gas kick characteristics during the carbonate reservoir drilling, gas kick volume models for differential pressure invasion and gas-liquid replacement invasion were established, respectively. The differential pressure invasion is mainly affected by the negative pressure between bottom hole pressure and formation pressure, drilled reservoir thickness, reservoir permeability and gas properties. The gas kick volume model can be established based on the percolation mechanics theory[27]:
Qg
774.6 KH pe2 pw2 T g Z ln re rw
(1)
The gas-liquid replacement invasion is mainly affected by factors such as reservoir permeability, porosity and borehole radius, in other words, its gas kick volume model is a function of the above three parameters. Therefore, it can be assumed as
2.2.
Wellbore temperature-pressure field
The wellbore temperature-pressure field is the basis for calculation of the annular pressure distribution and hydraulic parameter design in the drilling engineering. Considering various drilling conditions and influencing factors, many scholars have carried out extensive researches on wellbore temperature-pressure field[1624]. Since the effects of acid gas such as CO2 and H2S must be considered in the carbonate reservoir drilling, the model must have a higher accuracy. Therefore, the wellbore multiphase flow model considering acid gas in the reference [24] has been used in this study, and its governing equations, auxiliary equations and solution methods are elaborated in reference [24]. 2.3.
Wellbore gas volume fraction
When the gas invade into bottom hole and rises up along the wellbore in drilling, the gas-liquid two-phase flow pattern usually transforms from bubble flow to slug flow[28]; if the gas kick is severe, the flow pattern will turn into churn flow or annular flow. Due to different calculating methods for gas drift velocity and gas volume fraction in different flow patterns, the effect of flow pattern must be considered in calculating the gas volume fraction[29]. (1) Bubble flow. The existence condition of bubble flow is:
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vsg k1 0.429vsl 0.357vgr
(2)
The gas drift velocity equation is:
g l g vgr 1.53 l2
0.25
(3)
The gas volume fraction equation is:
Eg vsg
c v
0 am
vgr
(4)
(2) Slug flow. The existence condition of it is:
vsg k1 0.429vsl 0.357vgr
(5)
The gas drift velocity equation is:
D vgr 0.3 0.22 dr Dp
g Ddr Dp l g l
0.5
(6)
The gas volume fraction equation is the same as that of bubble flow, but the velocity distribution coefficient c0 is different. (3) Churn flow. The existence condition of it is:
g vsg2 25.41lg l vsl2 38.9 l vsl2 > 74.4 2 1.7 l vsl2 74.4 g vsg 0.005 1 l vsl2 0.333 vsg k2 g l g g2
(7)
0.25
(8)
The gas drift velocity and gas volume fraction equations are the same as that of slug flow, but the velocity distribution coefficient c0 is different. (4) Annular flow. The existence condition of it is: 0.333 vsg k2 g l g g2
0.25
(9)
The gas volume fraction equation is:
Eg 1 Y 0.8
where, Y 1 x x 2.4.
0.9
l
g
0.5
0.378
(10)
g . 0.1
l
Wellbore gas volume fraction density function
The change of wellbore gas volume fraction directly results in the wellbore pressure change, when the invading gas rises up along the wellbore during drilling process. The wellbore gas volume fraction can be predicted by combining eq. (1)-eq. (10) and the model of wellbore temperature-pressure field. That is, the distribution profile of wellbore gas volume fraction within a certain overflow time can be obtained. A quantitative evaluation method for the gas kick risk during the drilling process has been proposed by introducing the following gas volume fraction density function. The function is defined as the cumulative curve of gas volume fraction along the well depth within a certain overflow time:
acg t
hwh
hbh
Eg h dh
can be classified into reservoir characteristics, gas characteristics and field operation design, etc. The gas kick risks during carbonate reservoir drilling in Shunnan area were evaluated using the proposed gas kick analysis model. The basic data are as follows: well depth of 2 652 m; case diameter of 244.5 mm (9.625 in); drill string diameter of 127.0 mm (5 in); rate of penetration of 5 m/h; drilling fluid displacement of 30 L/s; drilling fluid density and viscosity of 0.98 g/cm3 and 14 mPa·s, respectively; surface temperature of 20 C; geothermal gradient of 0.031 C/m; formation fracturing pressure gradient of 0.014 MPa/m; relative density of formation oil and natural gas of 0.80 and 0.92, respectively. 3.1. Effects of gas kick type and gas properties on wellbore gas volume fraction By using wellhead back pressure to tell the gas kick type, the variation patterns of wellbore gas volume fraction under differential pressure invasion and gas-liquid replacement invasion have been obtained, respectively (Fig. 4). It can be seen from Fig. 4 that before applying wellhead back pressure, the overflow curves simulated for 10 mins under two different invasion types are similar; after applying wellhead back pressure, the overflow curves simulated for 10 mins under the two types of invasions show that there is no longer any gas invading into the bottom hole in the differential pressure invasion mode, but gas invading keeps going on in the gas-liquid replacement invasion mode. It also indicates that it is feasible to tell the gas kick type by the method of applying wellhead back pressure[13]. Taking gas-liquid replacement as an example, the effect of gas kick volume on the wellbore gas volume fraction was analyzed (Fig. 5). It can be seen that under the same overflow time, the larger the gas kick volume is, the larger the wellbore gas volume fraction and the higher the gas rising up velocity are. Taking gas-liquid replacement invasion as an example, the change pattern under effects of acid gases (CO2, H2S) on the wellbore gas volume fraction were also obtained by simulating overflow for 10 mins (Fig. 6). Under the same gas inflow rate, the higher the acid gas content is, the smaller the well-
(11)
3. Assessment of gas kick risk during carbonate reservoir drilling There are many incentives of gas kick risk[1415, 30], which
Fig. 4. Variations of wellbore gas volume fraction in differential pressure invasion and gas-liquid replacement invasion.
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containing acid gas is hard to detect, due to its smaller volume at the bottom hole and its slower rising up velocity along the wellbore. 3.2.
Fig. 5. Variations of wellbore gas volume fraction under different gas kick volumes in gas-liquid replacement invasion.
Quantitative evaluation method for gas kick risk
The acid gas and reservoir permeability etc. have strong influences on the gas kick risk, but they are uncontrollable. In contrast, the field operation parameters can be adjusted to prevent gas kick. Therefore, considering the effects of field operation parameters on wellbore gas volume fraction, the wellbore gas volume fraction density function was used to establish a quantitative evaluation method for the gas kick risk based on the dimensionless field operation parameters. The procedures are as follows. 3.2.1. Effects of field operation parameters on wellbore gas volume fraction
Fig. 6. Variations of wellbore gas volume fraction under different invasion gas types.
bore gas volume fraction is. Under the same acid gas content, the wellbore gas volume fraction is smaller when the gas containing H2S compared to the gas containing CO2. The rising velocity of natural gas with acid gas in the wellbore is smaller than that of pure natural gas. Because the acid gases (especially H2S) have high solubility in drilling fluid and are in supercritical state[21] after invading into the bottom hole from the carbonate reservoirs. Therefore, the gas kick of natural gas
Fig. 7.
The field operation parameters are the basic parameters of well control design and are controllable. Therefore, the first step of gas kick risk assessment is to obtain the effect law of field operation parameters on wellbore gas volume fraction, including mechanical parameters, drilling fluid physical parameters and wellbore structure parameters. When analyzing the effect of one parameter, only this parameter took different values and other parameters were the same with the basic data. The variations of wellbore gas volume fraction with different physical parameter construction parameters were obtained by simulating overflow for 10 mins (Fig. 7). 3.2.2. Dimensionless operation parameters and sensitive factor calculation Based on the effects of operation parameters on wellbore gas volume fraction, the wellbore gas volume fraction densities under different operation parameters were calculated using eq. (11) (Table 2).
Variations of wellbore gas volume fraction with different physical parameters.
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Table 2.
Wellbore gas volume fraction densities under different operation parameters
Drilling fluid displacement/(L·s1)
Rate of penetration/(m·h1)
Drilling fluid density/(g·cm3)
Drilling fluid viscosity/(mPa·s)
Well diameter/mm
Well depth/m
Wellbore gas volume fraction density/m
12
5
0.98
10
244.5
2 652
96.104
22
5
0.98
10
244.5
2 652
94.752
30
5
0.98
10
244.5
2 652
94.241
30
10
0.98
10
244.5
2 652
94.200
30
20
0.98
10
244.5
2 652
94.200
30
30
0.98
10
244.5
2 652
94.199
30
5
0.98
10
244.5
2 652
94.241
30
5
1.07
10
244.5
2 652
86.535
30
5
1.30
10
244.5
2 652
72.256
30
5
0.98
10
244.5
2 652
94.241
30
5
0.98
20
244.5
2 652
93.461
30
5
0.98
30
244.5
2 652
92.352
30
5
0.98
10
219.1
2 652
119.338
30
5
0.98
10
244.5
2 652
94.241
30
5
0.98
10
269.9
2 652
76.671
30
5
0.98
10
244.5
1 500
169.015
30
5
0.98
10
244.5
2 016
98.567
30
5
0.98
10
244.5
2 652
94.241
Due to different units and ranges, the effects of the operation parameters on wellbore gas volume fraction density cannot be compared quantitatively. Therefore, the operation parameters were transformed into dimensionless ones by using the basic data as standard, and then the sensitivity factor was calculated. Taking the drilling fluid displacement as an example, the specific calculation method is as follows. (1) Dimensionless method of the drilling fluid displacement and wellbore gas volume fraction density: i Qi Qstd (12)
i acgi acg, std
(13)
In this case, Q1, Q2 and Qstd are 12, 22 and 30 L/s, respectively; ρacg1, ρacg2 and ρacg, std are 96.104, 94.752 and 94.241 m; α1, α2, β1, β2calculated by eq. (12)，and eq. (13) are 0.400, 0.733, 1.020 and 1.005 respectively. (2) Define the sensitivity factor of drilling fluid displacement as: 1 2 1 2 (14) The sensitivity factor of drilling fluid displacement calculated by eq. (14) is 0.045. Similarly, the calculated sensitivity factors of rate of penetration, drilling fluid density, drilling fluid viscosity, well diameter and well depth are 1.1×105, 0.646, 0.012, 2.179 and 3.842, respectively. 3.2.3.
Quantitative description of gas kick risk
The sensitivity factor of a parameter reflects the response intensity of wellbore gas volume fraction density to the change of the parameter. That is, the larger the absolute value of the sensitivity factor is, the higher the response intensity is.
The negative values indicate that the wellbore gas volume fraction density has negative correlation with the corresponding parameters. That is, the gas kick risk becomes smaller with the increase of the parameter. It can be seen that rate of penetration has little effect on gas kick risk; drilling fluid displacement and viscosity have small effects, and well diameter, well depth and drilling fluid density have large effects on gas kick risk. Therefore, the wellbore structure, drilling assembly and drilling fluid can be optimized based on pore-fracturecave characteristics and sensitivity factor of field parameters in carbonate reservoir drilling. 3.3.
Method for ranking well control risk
Well killing measures are usually taken when gas kick occurs in drilling, during which judging the difficulty and risk of well control is the key for selecting killing methods and related measures. Therefore, a method for ranking well control risk has been proposed based on the wellbore gas volume fraction density function. Fig. 8 shows the variations of wellbore gas volume fraction density with time in this case. Hereby, the well control risks are classified into three levels: (1) The first grade well control risk, refers to the risk when the invading gas mixture is close to the bottom hole and relatively small in volume, this kind of risk is hard to detect but easy to be brought under control. (2) The second grade well control risk refers to the risk with drop of wellbore pressure and larger invaded gas volume as the gas mixture rises up, at this point, some gas is released from the drilling fluid, and rise of drilling fluid level in mud pit can be monitored. (3) The third grade well control risk refers to the risk when gas mixture rises up and expands drastically near the wellhead. If the overflow in
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Qg—gas kick volume, m3/d; Qstd—standard drilling fluid displacement, L/s; re, rw—supply boundary and borehole radius, m; T—reservoir temperature, K; vgr—gas drift velocity, m/s; vsl, vsg, vam—apparent phase velocity of liquid, gas and their mixture, m/s; x—gas flow factor; Z—reservoir gas compressibility factor; αi—dimensionless drilling fluid displacement; βi—dimensionless wellbore gas volume fraction density; Fig. 8. Ranking of well control risks based on wellbore gas volume fraction density function.
Δt—overflow time, s;
bottom hole continued at this time, well control difficulty level would increase, and blowout is likely to happen.
ρacg—wellbore gas volume fraction density within a certain over-
4.
μg, μl—viscosity of gas and liquid phase, mPa·s; flow time, m; ρacg, std—standard wellbore gas volume fraction density, m;
Conclusions
ρg, ρl—density of gas and liquid phase, kg/m3;
The gas kick characteristics during carbonate reservoir drilling were analyzed based on the geologic data in Tazhong Shunnan area, which shows that the gas invades into a wellbore mainly in two modes, gas-liquid replacement and differential pressure. The pore-fracture-cave characteristics of carbonate reservoirs and high solubility and supercritical phase of acid gases have great influence on wellbore gas volume fraction, which can cause hidden and severe gas kicks. Fully considering the gas invasion mechanism, gas migration law in wellbore and wellbore temperature-pressure field, a model of predicting wellbore gas volume fraction has been built after gas invasion. Moreover, a quantitative evaluation method for gas kick risk by introducing the gas volume fraction density function has been proposed. The case study shows that the influences of well depth, well diameter, drilling fluid density, drilling fluid displacement, drilling fluid viscosity and rate of penetration on gas kick risk weaken in turn, and the risk decreases with the increase of the parameters. Moreover, the well control risks are classified into three levels based on the variations of wellbore gas volume fraction density with time, which can guide the selection of killing methods and related measures.
σ—surface tension, N/m; χ—sensitive factor of drilling fluid displacement. Subscript: i—data number.
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