# Recovery Method and Parameter Optimization of a Pilot Test for Conformance Control Flooding and Thermal Recovery in the Offshore Heavy Oilfield

Authors: Yanxia Zhou; Xiangguo Lu; Bao Cao; Yigang Liu; Yunbao Zhang; Xun Zhong
Journal: Geofluids
 (2021)

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## Abstract

NB35-2 oilfield is a typical offshore sandstone reservoir with viscous crude oil and high permeability. Due to the inherent severe heterogeneity, the efficiency of conventional water flooding is pretty low and usually accompanied with early water breakthrough. In order to recover the residual oil and better realize its potential, applications of enhanced oil recovery (EOR) technology are necessary. However, the selection of EOR method and related parameters may directly impact the final results and can be noticeably different for different reservoirs; therefore, to optimize the oil production rate and final oil recovery, systematical optimization of every detail based on the condition of a specific reservoir is of key importance. In this paper, physical simulations were first conducted to select the best recovery methods for the target area based on the static geophysical model under the guidance of reservoir engineering theory. Then, detailed development variants for each method were determined by numerical simulation with the support of data obtained from previous pilot tests (polymer gel flooding and thermal fluid huff and puff) conducted in this area. Three exploitation methods were developed for the target well group, including polymer gel flooding (conformance control, Pattern 1), steam huff and puff (thermal recovery method, Pattern 2), and a combination of polymer gel flooding and steam huff and puff (conformance control and thermal recovery, Pattern 3). The numerical simulation result also showed that Pattern 3 yielded the highest oil recovery. Moreover, the amount of additional oil being recovered by applying Pattern 3 was even higher than the total additional oil being extracted by Patterns 1 and 2. In addition, sensitivity analysis was conducted to rank the most important parameters based on the three Patterns. At last, it is thought that the synergistic effect between conformance control and thermal recovery made more oil recovered, which was intuitively clarified in the mechanism analysis.


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## Body

## 1. Introduction

At present, the production of terrestrial oil and gas is decreasing year by year, while the oil demand of national industrial construction and people’s daily lives is steadily increasing [1, 2]. However, the good news is the great potentials in offshore oilfields have offered great opportunities to mitigate this issue [3]. Bohai Oilfield is a famous offshore oilfield with huge crude oil reserves in China, with heavy oil occupying about two-thirds of its total reserves. NB35-2 oilfield lies in the center of the Bohai Sea with high permeability (average permeability of most layers around 1000~5000×10−3 μm2) and serious heterogeneity, and its crude oil is of high viscosity (450~950 mPa·s). The distances between the injection wells and the production wells (at least 300 m) are always large; most importantly, the water flooding oil recovery is pretty low (about 15%) in this area. Therefore, effective exploitation technologies should be taken to recover the residual oil after conventional water flooding. At present, steam huff and puff or steam flooding is the normally applied technology to exploit heavy oil reservoirs [4–7]. However, in the process of steam huff and puff, formation pressure may suffer from significant loss. Therefore, the recovery factor of conventional steam huff and huff is very low [8–10]. Although steam flooding effectively supplies formation pressure, the steam fluid channeling is always a serious challenge because of the reservoir anisotropy and high mobility of the steam, which not only decreases the sweep volume and thermal efficiency but also harms the normal operation of oil well artificial lifting system [11]. In recent years, polymer flooding and polymer gel flooding technologies received much attention because of their better adaptability, lower cost, and higher efficiency. Since 1996, Daqing Oilfield has developed an industrial application of polymer flooding technology, and the application scale is enlarging year by year. The increment proportion of oil production by polymer flooding towards total oil output is also rising. According to the statistics, more than 1000×104 t additional oil has been recovered in the continuous ten years [12–14]. Another success story of conformance control is that Henan Oilfield has been carried out using polymer gel before the polymer flooding since 2004. After the conformance control, the injection pressure rose, apparent infectivity index dropped, and the water injection profile was noticeably improved. The polymer concentration of produced liquid in the block reduced greatly, leading to significant oil increment and water cut reduction [15]. Though single conformance control flooding and single thermal recovery have achieved good effect in increasing oil recovery and decreasing water cut, now, there is still a concerned question for petroleum technologist and scientist whether the combined operation (“conformance control flooding and thermal recovery”) can get a better effect. To maximize the effectiveness of the combined operation, recovery methods and parameter optimization were carried out in this work focusing on injection and production process in the target well group and analysis of field test results. This work follows the guide of oil reservoir engineering theory to establish the static geophysical model and perform the dynamic numerical modeling on the basis of some fundamental information and data of the target well group in the NB35-2 oilfield.


## 2. Materials and Methods

### 2.1. Experimental Materials

The polymer used is partially hydrolyzed polyacrylamide with relative molecular weight of1900×104 g/mole provided by Daqing refining chemical company. The cross-linking agent is an organic chromium with 2.89 wt.% Cr3+. The simulated oils are mixtures of heavy crude oil and kerosene in order to prepare oils with different viscosities (850 mPa·s, 428 mPa·s, 120 mPa·s, and 23 mPa·s at 50°C). Formation water with salinity of 4441.76 mg/L obtained from NB35-2 was applied to prepare the solutions. The experiment core is a 3D simulation model with heterogeneous inner layer [16]. Its external dimension is height×width×length of 4.5cm×30cm×30cm. This core sample is glued by quartz sand and epoxy and surrounded by a strong epoxy resin layer, so it has high pressure resistance. Each core is composed of three layers with different permeability (gas permeability, 3200×10-3μm2, 1600×10-3μm2, and 800×10-3μm2) to simulate the heterogeneity of the real formation. The thickness of each layer is around 1.5 cm.


### 2.2. Instrument and Facilities

The viscosity of flooding agent is tested by DV-II Brinell viscosity instrument at the rotation speed of 6 r/min. The experiment displacement facilities mainly include advection pump, pressure gauge, and displacing agent container. Except the advection pump, the other facilities are placed in an oven with a constant temperature of 65°C. The schematic diagram of experimental set-up is shown in Figure1.Figure 1
Schematic diagram of experimental set-up.


### 2.3. Physical Simulation

There were four large-size artificial cores for physical simulation of four displacement schemes, including water flooding (1st scheme), thermal recovery after water flooding (2nd scheme), conformance control after water flooding (3rd scheme), and conformance control flooding and thermal recovery after water flooding (4th scheme). Before the start of the experiment, all four cores were saturated with formation water after being evacuated and then saturated original oil (850 mPa·s) in 1st and 3rd scheme. Due to the fact it is difficult to simulate the effect of injected hot fluid on the viscosity of crude oil near the bottom of the well, for the first time, this paper used the crude oil of different viscosity saturated in the vicinity of the thermal recovery well to reflect the range of action of the thermal fluid. [17] On the basis of previous physical simulation experience, the heating radius of the thermal fluid is 3/10 distance between the water well and oil well. In this effected range by thermal fluid, three kinds of viscosity distribution were followed by 23 mPa·s, 120 mPa·s, and 428 mPa·s from oil well. The viscosity of other range in the 3D physical model still keeps original crude viscosity with 850 mPa·s. The detailed experimental procedures are as follows:
(1)
1st scheme: ordinary water flooding until the water cut of produced liquid reaches 98%(2)
2nd scheme: conducting water flooding at injection well and thermal recovery technology at oil wells until the water cut of produced liquid reaches 98%(3)
3rd scheme: for water well, 0.03PVCr3+ polymer gel (concentration of polymer of 1200 mg/L, mass ration of polymer gel to Cr3+ of 180 to 1) was injected after the ordinary water flooding to water cut reaches 98%, and then subsequent water flooding was conducted until the water cut of produced liquid reaches 98%(4)
4th scheme: for water well, 0.03PVCr3+ polymer gel (concentration of polymer of 1200 mg/L, mass ration of polymer gel to Cr3+ of 180 to 1) was injected until water cut reaches 98% after the ordinary water flooding and thermal recovery technology at oil wells, and then subsequent water flooding was conducted until the water cut of produced liquid reaches 98%Because shearing action is inevitable during the process of preparation and injection, therefore, to better simulate the real situation, the polymer solution was exposed to shearing action before the addition of Cr3+. The viscosity retention rate is around 60%.


### 2.4. Numerical Simulation

In order to further illustrate the synergistic effect between conformance control and thermal recovery method, a series of numerical simulation [18, 19] was conducted to analyze the three different recovery methods, polymer gel flooding (conformance control, Pattern 1), steam huff and puff (thermal recovery method, Pattern 2), and the combination of polymer gel flooding and steam huff and puff (conformance control flooding and thermal recovery, Pattern 3). First, the classic geologic model of NB35-2 oilfield was built using the three-dimensional geologic modeling software of Petrel. Then, CMG numerical simulation software (STARS and chemical flooding modules) was applied to optimize the injection and production parameter. In this part, the basic input parameters were obtained by fitting with the results of physical simulation results.


### 2.5. The Field Test

By combined operation with the best injection and production parameters from numerical simulation, a field test is conducted in the NB35-2 oilfield.


## 2.1. Experimental Materials

The polymer used is partially hydrolyzed polyacrylamide with relative molecular weight of1900×104 g/mole provided by Daqing refining chemical company. The cross-linking agent is an organic chromium with 2.89 wt.% Cr3+. The simulated oils are mixtures of heavy crude oil and kerosene in order to prepare oils with different viscosities (850 mPa·s, 428 mPa·s, 120 mPa·s, and 23 mPa·s at 50°C). Formation water with salinity of 4441.76 mg/L obtained from NB35-2 was applied to prepare the solutions. The experiment core is a 3D simulation model with heterogeneous inner layer [16]. Its external dimension is height×width×length of 4.5cm×30cm×30cm. This core sample is glued by quartz sand and epoxy and surrounded by a strong epoxy resin layer, so it has high pressure resistance. Each core is composed of three layers with different permeability (gas permeability, 3200×10-3μm2, 1600×10-3μm2, and 800×10-3μm2) to simulate the heterogeneity of the real formation. The thickness of each layer is around 1.5 cm.


## 2.2. Instrument and Facilities

The viscosity of flooding agent is tested by DV-II Brinell viscosity instrument at the rotation speed of 6 r/min. The experiment displacement facilities mainly include advection pump, pressure gauge, and displacing agent container. Except the advection pump, the other facilities are placed in an oven with a constant temperature of 65°C. The schematic diagram of experimental set-up is shown in Figure1.Figure 1
Schematic diagram of experimental set-up.


## 2.3. Physical Simulation

There were four large-size artificial cores for physical simulation of four displacement schemes, including water flooding (1st scheme), thermal recovery after water flooding (2nd scheme), conformance control after water flooding (3rd scheme), and conformance control flooding and thermal recovery after water flooding (4th scheme). Before the start of the experiment, all four cores were saturated with formation water after being evacuated and then saturated original oil (850 mPa·s) in 1st and 3rd scheme. Due to the fact it is difficult to simulate the effect of injected hot fluid on the viscosity of crude oil near the bottom of the well, for the first time, this paper used the crude oil of different viscosity saturated in the vicinity of the thermal recovery well to reflect the range of action of the thermal fluid. [17] On the basis of previous physical simulation experience, the heating radius of the thermal fluid is 3/10 distance between the water well and oil well. In this effected range by thermal fluid, three kinds of viscosity distribution were followed by 23 mPa·s, 120 mPa·s, and 428 mPa·s from oil well. The viscosity of other range in the 3D physical model still keeps original crude viscosity with 850 mPa·s. The detailed experimental procedures are as follows:
(1)
1st scheme: ordinary water flooding until the water cut of produced liquid reaches 98%(2)
2nd scheme: conducting water flooding at injection well and thermal recovery technology at oil wells until the water cut of produced liquid reaches 98%(3)
3rd scheme: for water well, 0.03PVCr3+ polymer gel (concentration of polymer of 1200 mg/L, mass ration of polymer gel to Cr3+ of 180 to 1) was injected after the ordinary water flooding to water cut reaches 98%, and then subsequent water flooding was conducted until the water cut of produced liquid reaches 98%(4)
4th scheme: for water well, 0.03PVCr3+ polymer gel (concentration of polymer of 1200 mg/L, mass ration of polymer gel to Cr3+ of 180 to 1) was injected until water cut reaches 98% after the ordinary water flooding and thermal recovery technology at oil wells, and then subsequent water flooding was conducted until the water cut of produced liquid reaches 98%Because shearing action is inevitable during the process of preparation and injection, therefore, to better simulate the real situation, the polymer solution was exposed to shearing action before the addition of Cr3+. The viscosity retention rate is around 60%.


## 2.4. Numerical Simulation

In order to further illustrate the synergistic effect between conformance control and thermal recovery method, a series of numerical simulation [18, 19] was conducted to analyze the three different recovery methods, polymer gel flooding (conformance control, Pattern 1), steam huff and puff (thermal recovery method, Pattern 2), and the combination of polymer gel flooding and steam huff and puff (conformance control flooding and thermal recovery, Pattern 3). First, the classic geologic model of NB35-2 oilfield was built using the three-dimensional geologic modeling software of Petrel. Then, CMG numerical simulation software (STARS and chemical flooding modules) was applied to optimize the injection and production parameter. In this part, the basic input parameters were obtained by fitting with the results of physical simulation results.


## 2.5. The Field Test

By combined operation with the best injection and production parameters from numerical simulation, a field test is conducted in the NB35-2 oilfield.


## 3. Results

### 3.1. Experimental Result Analysis

Figure2 is the schematic diagram of the 3D physical model with an inverted nine-spot pattern.Figure 2
3D-simulated physical model of 1/4 inverted nine-spot pattern: (a) used in water flooding and Pattern 1 (conformance control flooding); (b) used in Pattern 2 (thermal recovery) and Pattern 3 (conformance control flooding and thermal recovery).
(a)(b)In the 3D-simulated physical model with the inverted nine-spot pattern, water flooding, conformance control flooding, thermal recovery, and combined operation (“conformance control flooding and thermal recovery”) were carried out. Table1 shows the experiment results of the recovery ratio.Table 1
The experiment results of recovery ratio.
ParameterScheme contentsWorking viscosity of polymer gel (mPa·s)Oil saturation (%)Recovery (%)TotalIncrement11st scheme—78.58.8—22nd scheme—78.111.62.833rd scheme23.378.513.95.144th scheme22.878.117.99.1Note: taking the recovery of scheme 1 as the comparing standard, the increment of other schemes recovery can be calculated.As seen from Table1, production patterns do affect the ultimate recovery ratio. Compared with water flooding, the development effect of “thermal recovery” and “conformance control flooding” is better. The recovery increment of thermal recovery is 2.8%, compared to 5.1% for profile control flooding and 9.2% for combined operation. It can be seen that the recovery ration increment of combined operation is the highest. The reason is that the combined operation has a synergistic effect on oil production. On the one hand, conformance control flooding of the combined operation plugged the reservoir layer with high permeability. And subsequent oil displacing agent enters the middle and low permeability layer, expanding the sweep volume. On the other hand, thermal recovery enhanced the reservoir temperature and reduced the oil viscosity, thus decreasing the flow resistance of oil. Therefore, higher recovery is achieved in the combined operation.


### 3.2. Numerical Result Analysis

#### 3.2.1. Reservoir Geologic Model

NB35-2 oilfield is located in the Bohai central waters, and the depth of the water is about 12 m. The oilfield is a multiple nose-like structure reservoir composed of three types of traps which are semi-anticline, complicated fault, and slope belt. The oilfield has the characteristics of shallow burial, abundant reserves, complex fluid property, high viscosity and density, low sulfur content, low solidification point, and medium wax content. The oilfield was put into production in September 2005. Up to now, there are 25 oil wells and 1 gel injection well. The daily oil production is 220 m3/d, the ratio of total oil output to original oil in place (OOIP) is 1.5%, and the oil recovery rate is as low as 0.3%.The dynamic model of NB35-2 oilfield was established with CMG imported from the static model in Petrel. In the model, the input of the parameters includes well number database, subzone database, breakpoint point database, performance dynamic data of oil and water wells (well history data), well-log information, reservoir fluid property, and sedimentary facies data (as shown in Figure3). In the model, grid number is NX×NY×NZ129×50×62=399900, the planar grid is 50×50, and longitudinal grid is 1-2 m.Figure 3
Numerical simulation model.


#### 3.2.2. The Effect Contrast with the Three Production Patterns

(1)
As an example of the B6 well group (as shown in Figure4), the oil increment effect of the three kinds of production patterns which were conformance control flooding, thermal recovery, and combined operation (conformance control flooding & thermal recovery) was compared.(2)
Conformance control flooding: according to real production situation of the oilfield, in the numerical simulate research, B30h well started to produce oil on February 11, 2015, while B31h well on August 1, 2015. At the same time, polymer gel injection was conducted for conformance control in B6 well.(i)
Scheme design: the influence factors of oil increment effect in the conformance control flooding by polymer gel include polymer concentration, slug size, and interval time of the polymer injection. The injection scheme of conformance control flooding by polymer gel was designed by use of the orthogonal numerical test. Each influence factor has two levels (i.e., designed value, as shown in Table2). Orthogonal design table L423 is adopted to design schemes, as shown in Table 3.(ii)
Selection of Evaluation index: accumulative oil increment, production-injection ratio, and recovery ratio increment of the well group are the technical indexes to evaluate the effect of conformance control flooding. Therefore, the three evaluation indexes were integrated into a comprehensive evaluation index, as shown in the Equation (1). The comprehensive evaluation index can be as the evaluation index of the orthogonal test.
(1)ϕ=αRzy+βRct+γRcc,where ϕ is the comprehensive evaluation index of different development modes, including Pattern 1 (conformance control flooding), Pattern 2 (thermal recovery), and Pattern 3 (conformance control flooding and thermal recovery); Rzy is the accumulative oil increment (104m3); Rct is the production-injection ratio; Rcc is the recovery ratio increment (%); and α,β,γ are the weight coefficients of accumulative oil increment, production-injection ratio, and recovery ratio increment, generally being 1/3, respectively.Figure 4
The schematic diagram of the B6 well group. The blue arrow represents the target study well group, and the gray arrow represents the nonstudy well group around the target one.Table 2
Orthogonal design factors and their level values in profile control flooding.
LevelFactorPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)125000.069230000.0812Table 3
The conformance control flooding scheme and effect of B6 well group.
ParameterPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)The result of schemeComprehensive evaluation indexAccumulative oil increment (104 m3)Production-injection ratioRecovery ratio increment (%)125000.0690.9182.1121.2241.418225000.08121.2912.5151.7211.842330000.06121.0122.1361.3491.499430000.0891.3542.3841.8061.848The comprehensive evaluation index is higher, the production-injection parameters are superior, and the economic benefit of the development modes (Pattern 1, Pattern 2, or Pattern 3) will be better.(iii)
The effect analysis of oil increment: program result and comprehensive evaluation index are showed in Table3. The intuitive analysis table is shown in Table 4.Table 4
Intuitive analysis table of B6 well group.
ParameterPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Mean value 11.6301.4591.633Mean value 21.6741.8451.671Prior level30000.0812Difference of mean value between the maximum and minimum0.0430.3870.038As shown in Table4, in the orthogonal numerical test, the values of the best levels for polymer concentration, slug size, and interval time of the polymer injection are 3000 mg/L, 0.08 PV, and 12 months, respectively. According to the simulation, the combination of optimal levels was able to yield an accumulative oil increment of 1.41×104 m3 (1.88%), a production-injection ratio of 2.48, and a comprehensive evaluation index of 1.92. From the difference of the mean value between the maximum and minimum in Table 4, the primary and secondary order of injection parameters to development effect is slugsizePV>polymerconcentrationmg/L>interval time of polymer injection (month).
(3)
Thermal recovery: numerical simulation on the B6 well group was also carried out multiple thermal fluid huff, and puff was conducted in oil wells (B30h and B31h) while water flooding was conducted in injection well (B6 well).According to practical production situation of the oilfield, in the numerical simulate research, B30h well and B31h (in the B6 well group) started to thermal fluid huff and puff, respectively, on February 11 and August 1, in 2015. The injection well started water flooding at the same time.(a)
Scheme design: in order to optimize the parameters in thermal recovery, the orthogonal numerical test is carried out to analyze the influence factors. Under overall considering, there are five factors, i.e., steam injection velocity, shut-in time, steam injection temperature, the cycle time of thermal fluid huff and puff, and steam injection quality in a cycle. Each influence factor has four levels, as shown in Table5. The orthogonal design table L1645 is adopted to design schemes, as shown in Table 6.
(ii)
The effect analysis: experiment scheme and the comprehensive evaluation index (according to Equation (1)) of B30h well in B6 group are shown in Table 6. The intuitive analysis table is shown in Table 7.Table 5
Orthogonal design factors and level values in the thermal fluid huff and puff.
LevelFactorSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)1120226093500213032651240003140427015450041505275185000Table 6
The experiment scheme and its result of B30h well with thermal recovery.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)Scheme resultComprehensive evaluation indexAccumulative oil increment (m3/t)Production-injection ratioRecovery increment (%)51202260935000.7721.5822.1631.506612032651240000.8421.6382.0201.500712042701545000.9121.7592.0521.574812052751850001.0521.9132.1041.690…………………………1715022751245000.7971.7442.1511.564181503270950000.5341.5642.1371.4121915042651835001.8952.4122.6532.3202015052601540001.2632.1652.5261.985Table 7
Intuitive analysis table of B30 well in thermal recovery experiment.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)Mean value 11.5681.6361.7021.4381.826Mean value 21.6211.6331.7011.5601.702Mean value 31.6551.7131.6321.7431.582Mean value 41.8201.6811.6291.9231.553Prior level1504260183500Difference of mean value between the maximum and minimum0.2520.0800.0730.4850.273From Table7, we can see that the optimal levels of steam injection velocity, shut-in time, steam injection temperature, the cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle were, respectively, 150 t/d, 4d, 260°C, 18 months, and 3500 t, respectively. After the combination of optimal levels was able to yield an accumulative oil increment of 1.902×104 m3 (2.701%), a production-injection ratio of 2.431, and a comprehensive evaluation index of 2.345. From the difference of mean value between the maximum and minimum in Table 4, the primary and secondary order of injection parameters to development effect is the cycle time of thermalfluidhuffandpuffmonth>thesteaminjectionquantityinacyclet>steaminjectionvelocityt/d>shut‐intimed>steam injection temperature (°C).Similarly, for B31h well, the best level of steam injection velocity, shut-in time, steam injection temperature, cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle is, respectively, 140 t/d, 3d, 275°C, 18 months, and 3500 t. After numerical simulation calculation with the value of the best level, the accumulative oil increment is2.471×104 m3, production-injection ratio is 3.695, recovery efficiency increment is 4.304%, and comprehensive evaluation index is 3.490. The primary and secondary order of injection parameters to development effect is the cycle time of thermal fluid huff and puff (month) > steam injection temperature (°C) > steam injection velocity t/d>shut‐intimed>thesteaminjectionquantityinacyclet.Then, after numerical simulation calculation of the B6 well group (B30h oil well and B31h oil well) with the value of the best level, the accumulative oil increment is 2.19×104 m3, production-injection ratio is 0.6, recovery efficiency increment is 3.56%, and comprehensive evaluation index is 2.92.
(4)
Combined operation (conformance control flooding and thermal recovery): the combined operation (conformance control flooding and thermal recovery) is carried out in the B6 well group. Multiple thermal fluid huff and puff was conducted in oil wells (B30h and B31h), while conformance control flooding with polymer gel was conducted in injection well (B6 well) at the same time.According to practical production situation of the oilfield, in the simulation research, B30h and B31h wells (in the B6 well group) started to multi thermal fluid huff and puff for oil production, respectively, on February 11th and August 1st, in 2015. The injection well started conformance control flooding with polymer gel at the same time.
(i)
Scheme design: the combined operation result is affected by the comprehensive function from injection and production parameters. In order to solve the question of parameter optimization, the orthogonal numerical test is carried out to analyze the influence parameter. Through overall considering, nine factors are considered, in which six parameters are from thermal recovery development, i.e., steam injection velocity, shut-in time, injection quantity in a cycle, steam injection temperature, and the cycle time of thermal fluid huff and puff. And the three parameters are from conformance control development, i.e., polymer concentration, slug size, and the interval time of polymer injection. Considering the conservation of formation energy in the injection and production operations, production-injection ration is also considered. By way of these parameters, the effect to the production result of the combined operation can be analyzed. The production-injection ration is set 8 levels. Other parameters are set 4 levels, as shown in Table8. The orthogonal design table L3281×48 is adopted to get scheme design, as shown in Table 9.(ii)
The effect analysisTable 8
Orthogonal design factors and level values in the combined operation.
ParameterInfluence factorSteam injection velocity (t/d)Shut-in time (d)Injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratio112023500260920000.0460.82130340002651225000.0690.93140445002701530000.081214150550002751835000.10151.151.261.371.481.5Table 9
The experiment scheme and results of the combined operation.
SchemeSteam injection velocity (t/d)Shut-in time (d)Steam injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratioScheme resultComprehensive evaluation indexAccumulative oil increment (104 m3)Production-injection ratioRecovery ration increment (%)2112023500260920000.0460.85.63211.15314.55810.44822120240002651835000.08120.99.06111.40914.49711.6562312034500275925000.081514.63811.58315.42710.54924120350002701830000.0491.17.59313.03315.18611.937……………………………………4915043500265925000.10121.15.75710.95314.96110.55750150440002601830000.06619.02711.98814.44211.8195115054500270920000.0690.94.43611.52714.74310.23552150550002751835000.10150.87.38211.21214.76411.119Experiment scheme and its comprehensive evaluation index (according to Equation (1)) of B6 well group are shown in Table 9. The intuitive analytical table is shown in Table 10.Table 10
Intuitive analysis table of the B6 well group with combined operation.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratioMean value 111.15111.15711.47211.02510.61011.12211.26611.17610.658Mean value 211.15111.27811.23211.12210.82511.09011.18211.13810.933Mean value 311.12411.05310.94011.22311.33311.19511.12611.11211.152Mean value 411.16811.10710.95011.22411.82511.18711.02111.16711.098Mean value 511.217Mean value 611.224Mean value 711.391Mean value 811.515Prior level150335002751830000.0461.5Difference of mean value between the maximum and minimum0.0440.2250.5320.1991.2150.1060.2450.0640.857From Table10, we can see that the best level of steam injection velocity, shut-in time, steam injection quantity in a cycle, steam injection temperature, the cycle time of thermal fluid huff and puff, polymer concentration, slug size, interval time of conformance control flooding, and the production-injection ratio is, respectively, 150 t/d, 3d, 3500 t, 275°C, 18 months, 3000 mg/L, 0.04 PV, 6 months, and 1.5. After numerical simulation calculation with the value of the best level, the accumulative oil increment is by 5.26×1043, the production-injection ratio by 6.29, recovery efficiency increment by 7.36%, and comprehensive evaluation index by 6.30. From the difference of the mean value between maximum and minimum in Table 10, the primary and secondary order of injection parameters to development effect is the cycle time of thermal fluid huff and puff (month) > production − injection ratio > cycle time of the steam injection quantity (t) > slug size (PV) > shut-in time (d) > steam injection temperature (°C) > polymer concentration (mg/L) > interval time of polymer injection (month) > steam injection velocity (t/d).
(5)
The effect contrast of three production patterns: numerical simulation of the B6 well group was carried out with three production patterns, i.e., conformance control flooding, thermal recovery, and combined operation (conformance control flooding and thermal recovery). The result is shown in Table11 and Figure 5.Table 11
The effect contrast of three production patterns of the B6 well group.
Well groupProduction patternAccumulative oil increment (104 m3)Production-injection ratioRecovery efficiency increment (%)Comprehensive evaluation indexB6 well groupConformance control flooding1.412.481.881.92Thermal recovery2.193.063.562.94Combined operation5.266.297.366.30Figure 5
The comprehensive evaluation index of three production patters of the B6 well group.As shown in Table11 and Figure 5, in the three production patterns, i.e., profile control flooding, thermal recovery, and combined operation, the comprehensive evaluation index of the combined operation is the highest and has the best oil increment. It indicates in the process of conformance control flooding that the conformance control flooding agent first entered into the high permeable layer and blocked off the high permeability stripe. At the same time in the thermal recovery process, the thermal fluid huff and puff can heat the reservoir, increase the formation temperature, reduce the oil viscosity, and decrease flow resistance. Because there is a synergistic effect in the combined operation, its oil production increment is much better than the total of both thermal recovery and conformance control flooding.


### 3.3. The Effect Analysis of the Field Test

As an example of the B6 well group, polymer weak gel flooding was carried out in B6 injection well on July 13, 2016. Its injection allocation is 120 m3/d, the mass injection concentration of polymer at wellhead is 2800 mg/L, the wellhead viscosity is 64.0 Pa·s, and the wellhead pressure is from 3.9 MPa to 10.39 MPa. On October 1, 2017, the protection slug was injected, with the concentration of 40,000 mg/L, the viscosity of 150 mPa·s, and injection allocation of 80m3/d. Then, the wellhead pressure rose from 7.15 MPa to 9.9Mpa (as shown in Figure 6). This indicated that after the polymer gel entered into the reservoir, it first entered into the high permeability layer and had retention. This can lead to reduce overcurrent section, increase flow resistance, enhance wellhead injection pressure, and enlarge suction hydraulic difference between medium and low permeability layers. So the suction quantity increased and made a valid use of them. That achieved the purpose of conformance control flooding.Figure 6
Production profiles of the B6 well.Take B31h well for example, after conformance control flooding in B6 well on July 1, 2016, the daily oil production of B31h has a distinct rise, with the water cut greatly decreasing. After the shut-in time in the second cycle of thermal fluid huff and puff of in March 2017, the daily oil production rose by a great margin, with the water cut rapidly decreasing (as shown in Figure7). In cut-off by August 2019, the accumulative oil production of combined operation (conformance control flooding and thermal recovery) reached 4.18×104 m3. Compared with water flooding development (the accumulative oil production by numerical simulation being 1.19×104 m3), the accumulative oil increment reached 2.09×104 m3. The accumulative oil production with conformance control flooding can reach 2.21×104 m3. Its accumulative oil increment is 1.02×104 m3 compared with water flooding development. The accumulative oil production with thermal recovery is 1.93×104 m3. Its accumulative oil increment is 0.74×104 m3 compared with water flooding development, as shown in Figure 8. Thus, it can be seen that the accumulative oil increment by combined operation is much higher than the sum of oil increment by conformance control flooding and thermal recovery. It is illustrated that after thermal fluid huff and puff of B31h well, the reservoir nearby the well bottom was heated, with the viscosity of crude oil declining and the seepage resistance decreasing. Together with the effect of conformance control flooding of B6 well, the synergistic effect of both of them can achieve a better productive result.Figure 7
Production profiles the B31 well.Figure 8
Comparison of accumulative oil increment (104 m3).


### 3.4. Mechanism Analysis

From the experimental and numerical results and field test, the combined operation (“conformance control flooding and thermal recovery”) obtained a good oil recovery. The mechanism diagram is shown in Figure9. Compared with original reservoir (Figure 9(a)), after the water flooding (Figure 9(b)), only the crude oil in the near-well zone and the straight area between the injection well and production wells are produced, especially forming an obvious channel between the injection well and its diagonal O2 oil well. Due to the high viscosity of the crude oil, the mobility ratio of the oil and water is relatively high, which greatly reduced the sweep coefficient of the injected water, resulting in poor water flooding effect. If thermal recovery (Figure 9(c)) was carried out in the diagonal O2 oil well of injection well after water flooding, it is obvious that the crude oil around the O2 oil well is produced largely due to the injected thermal fluid decreasing the viscosity of the crude oil near it result in lower flow resistance. If conformance control (Figure 9(d)) was carried out in injection well after water flooding, compared with water flooding (Figure 9(b)), more oil was produced due to the increased sweep coefficient of oil displacing agent and the main produced area was the same as water flooding (Figure 9(b)) but with a larger scope. And the crude oil located on the main line between the injection well and its diagonal well is mostly produced forming a thicker channel. If combined operation (Figure 9(e)) was carried out with conformance control of injection well and thermal recovery of the diagonal O2 oil well of injection well, a better recovery result was obtained when more oil was produced. In particular, a good development effect was obtained around the thermal recovery well due to the low viscosity of the crude oil in this area and the oil displacing agent swept more area, which was called synergistic effect achieving better development results.Figure 9
Mechanism diagram. (a) Crude oil distribution in the original reservoir. (b) Crude oil distribution after water flooding. (c) Crude oil distribution after thermal recovery. (d) Crude oil distribution after conformance control. (e) Crude oil distribution after combined operation (“conformance control flooding and thermal recovery”).
(a)(b)(c)(d)(e)


## 3.1. Experimental Result Analysis

Figure2 is the schematic diagram of the 3D physical model with an inverted nine-spot pattern.Figure 2
3D-simulated physical model of 1/4 inverted nine-spot pattern: (a) used in water flooding and Pattern 1 (conformance control flooding); (b) used in Pattern 2 (thermal recovery) and Pattern 3 (conformance control flooding and thermal recovery).
(a)(b)In the 3D-simulated physical model with the inverted nine-spot pattern, water flooding, conformance control flooding, thermal recovery, and combined operation (“conformance control flooding and thermal recovery”) were carried out. Table1 shows the experiment results of the recovery ratio.Table 1
The experiment results of recovery ratio.
ParameterScheme contentsWorking viscosity of polymer gel (mPa·s)Oil saturation (%)Recovery (%)TotalIncrement11st scheme—78.58.8—22nd scheme—78.111.62.833rd scheme23.378.513.95.144th scheme22.878.117.99.1Note: taking the recovery of scheme 1 as the comparing standard, the increment of other schemes recovery can be calculated.As seen from Table1, production patterns do affect the ultimate recovery ratio. Compared with water flooding, the development effect of “thermal recovery” and “conformance control flooding” is better. The recovery increment of thermal recovery is 2.8%, compared to 5.1% for profile control flooding and 9.2% for combined operation. It can be seen that the recovery ration increment of combined operation is the highest. The reason is that the combined operation has a synergistic effect on oil production. On the one hand, conformance control flooding of the combined operation plugged the reservoir layer with high permeability. And subsequent oil displacing agent enters the middle and low permeability layer, expanding the sweep volume. On the other hand, thermal recovery enhanced the reservoir temperature and reduced the oil viscosity, thus decreasing the flow resistance of oil. Therefore, higher recovery is achieved in the combined operation.


## 3.2. Numerical Result Analysis

### 3.2.1. Reservoir Geologic Model

NB35-2 oilfield is located in the Bohai central waters, and the depth of the water is about 12 m. The oilfield is a multiple nose-like structure reservoir composed of three types of traps which are semi-anticline, complicated fault, and slope belt. The oilfield has the characteristics of shallow burial, abundant reserves, complex fluid property, high viscosity and density, low sulfur content, low solidification point, and medium wax content. The oilfield was put into production in September 2005. Up to now, there are 25 oil wells and 1 gel injection well. The daily oil production is 220 m3/d, the ratio of total oil output to original oil in place (OOIP) is 1.5%, and the oil recovery rate is as low as 0.3%.The dynamic model of NB35-2 oilfield was established with CMG imported from the static model in Petrel. In the model, the input of the parameters includes well number database, subzone database, breakpoint point database, performance dynamic data of oil and water wells (well history data), well-log information, reservoir fluid property, and sedimentary facies data (as shown in Figure3). In the model, grid number is NX×NY×NZ129×50×62=399900, the planar grid is 50×50, and longitudinal grid is 1-2 m.Figure 3
Numerical simulation model.


### 3.2.2. The Effect Contrast with the Three Production Patterns

(1)
As an example of the B6 well group (as shown in Figure4), the oil increment effect of the three kinds of production patterns which were conformance control flooding, thermal recovery, and combined operation (conformance control flooding & thermal recovery) was compared.(2)
Conformance control flooding: according to real production situation of the oilfield, in the numerical simulate research, B30h well started to produce oil on February 11, 2015, while B31h well on August 1, 2015. At the same time, polymer gel injection was conducted for conformance control in B6 well.(i)
Scheme design: the influence factors of oil increment effect in the conformance control flooding by polymer gel include polymer concentration, slug size, and interval time of the polymer injection. The injection scheme of conformance control flooding by polymer gel was designed by use of the orthogonal numerical test. Each influence factor has two levels (i.e., designed value, as shown in Table2). Orthogonal design table L423 is adopted to design schemes, as shown in Table 3.(ii)
Selection of Evaluation index: accumulative oil increment, production-injection ratio, and recovery ratio increment of the well group are the technical indexes to evaluate the effect of conformance control flooding. Therefore, the three evaluation indexes were integrated into a comprehensive evaluation index, as shown in the Equation (1). The comprehensive evaluation index can be as the evaluation index of the orthogonal test.
(1)ϕ=αRzy+βRct+γRcc,where ϕ is the comprehensive evaluation index of different development modes, including Pattern 1 (conformance control flooding), Pattern 2 (thermal recovery), and Pattern 3 (conformance control flooding and thermal recovery); Rzy is the accumulative oil increment (104m3); Rct is the production-injection ratio; Rcc is the recovery ratio increment (%); and α,β,γ are the weight coefficients of accumulative oil increment, production-injection ratio, and recovery ratio increment, generally being 1/3, respectively.Figure 4
The schematic diagram of the B6 well group. The blue arrow represents the target study well group, and the gray arrow represents the nonstudy well group around the target one.Table 2
Orthogonal design factors and their level values in profile control flooding.
LevelFactorPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)125000.069230000.0812Table 3
The conformance control flooding scheme and effect of B6 well group.
ParameterPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)The result of schemeComprehensive evaluation indexAccumulative oil increment (104 m3)Production-injection ratioRecovery ratio increment (%)125000.0690.9182.1121.2241.418225000.08121.2912.5151.7211.842330000.06121.0122.1361.3491.499430000.0891.3542.3841.8061.848The comprehensive evaluation index is higher, the production-injection parameters are superior, and the economic benefit of the development modes (Pattern 1, Pattern 2, or Pattern 3) will be better.(iii)
The effect analysis of oil increment: program result and comprehensive evaluation index are showed in Table3. The intuitive analysis table is shown in Table 4.Table 4
Intuitive analysis table of B6 well group.
ParameterPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Mean value 11.6301.4591.633Mean value 21.6741.8451.671Prior level30000.0812Difference of mean value between the maximum and minimum0.0430.3870.038As shown in Table4, in the orthogonal numerical test, the values of the best levels for polymer concentration, slug size, and interval time of the polymer injection are 3000 mg/L, 0.08 PV, and 12 months, respectively. According to the simulation, the combination of optimal levels was able to yield an accumulative oil increment of 1.41×104 m3 (1.88%), a production-injection ratio of 2.48, and a comprehensive evaluation index of 1.92. From the difference of the mean value between the maximum and minimum in Table 4, the primary and secondary order of injection parameters to development effect is slugsizePV>polymerconcentrationmg/L>interval time of polymer injection (month).
(3)
Thermal recovery: numerical simulation on the B6 well group was also carried out multiple thermal fluid huff, and puff was conducted in oil wells (B30h and B31h) while water flooding was conducted in injection well (B6 well).According to practical production situation of the oilfield, in the numerical simulate research, B30h well and B31h (in the B6 well group) started to thermal fluid huff and puff, respectively, on February 11 and August 1, in 2015. The injection well started water flooding at the same time.(a)
Scheme design: in order to optimize the parameters in thermal recovery, the orthogonal numerical test is carried out to analyze the influence factors. Under overall considering, there are five factors, i.e., steam injection velocity, shut-in time, steam injection temperature, the cycle time of thermal fluid huff and puff, and steam injection quality in a cycle. Each influence factor has four levels, as shown in Table5. The orthogonal design table L1645 is adopted to design schemes, as shown in Table 6.
(ii)
The effect analysis: experiment scheme and the comprehensive evaluation index (according to Equation (1)) of B30h well in B6 group are shown in Table 6. The intuitive analysis table is shown in Table 7.Table 5
Orthogonal design factors and level values in the thermal fluid huff and puff.
LevelFactorSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)1120226093500213032651240003140427015450041505275185000Table 6
The experiment scheme and its result of B30h well with thermal recovery.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)Scheme resultComprehensive evaluation indexAccumulative oil increment (m3/t)Production-injection ratioRecovery increment (%)51202260935000.7721.5822.1631.506612032651240000.8421.6382.0201.500712042701545000.9121.7592.0521.574812052751850001.0521.9132.1041.690…………………………1715022751245000.7971.7442.1511.564181503270950000.5341.5642.1371.4121915042651835001.8952.4122.6532.3202015052601540001.2632.1652.5261.985Table 7
Intuitive analysis table of B30 well in thermal recovery experiment.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)Mean value 11.5681.6361.7021.4381.826Mean value 21.6211.6331.7011.5601.702Mean value 31.6551.7131.6321.7431.582Mean value 41.8201.6811.6291.9231.553Prior level1504260183500Difference of mean value between the maximum and minimum0.2520.0800.0730.4850.273From Table7, we can see that the optimal levels of steam injection velocity, shut-in time, steam injection temperature, the cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle were, respectively, 150 t/d, 4d, 260°C, 18 months, and 3500 t, respectively. After the combination of optimal levels was able to yield an accumulative oil increment of 1.902×104 m3 (2.701%), a production-injection ratio of 2.431, and a comprehensive evaluation index of 2.345. From the difference of mean value between the maximum and minimum in Table 4, the primary and secondary order of injection parameters to development effect is the cycle time of thermalfluidhuffandpuffmonth>thesteaminjectionquantityinacyclet>steaminjectionvelocityt/d>shut‐intimed>steam injection temperature (°C).Similarly, for B31h well, the best level of steam injection velocity, shut-in time, steam injection temperature, cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle is, respectively, 140 t/d, 3d, 275°C, 18 months, and 3500 t. After numerical simulation calculation with the value of the best level, the accumulative oil increment is2.471×104 m3, production-injection ratio is 3.695, recovery efficiency increment is 4.304%, and comprehensive evaluation index is 3.490. The primary and secondary order of injection parameters to development effect is the cycle time of thermal fluid huff and puff (month) > steam injection temperature (°C) > steam injection velocity t/d>shut‐intimed>thesteaminjectionquantityinacyclet.Then, after numerical simulation calculation of the B6 well group (B30h oil well and B31h oil well) with the value of the best level, the accumulative oil increment is 2.19×104 m3, production-injection ratio is 0.6, recovery efficiency increment is 3.56%, and comprehensive evaluation index is 2.92.
(4)
Combined operation (conformance control flooding and thermal recovery): the combined operation (conformance control flooding and thermal recovery) is carried out in the B6 well group. Multiple thermal fluid huff and puff was conducted in oil wells (B30h and B31h), while conformance control flooding with polymer gel was conducted in injection well (B6 well) at the same time.According to practical production situation of the oilfield, in the simulation research, B30h and B31h wells (in the B6 well group) started to multi thermal fluid huff and puff for oil production, respectively, on February 11th and August 1st, in 2015. The injection well started conformance control flooding with polymer gel at the same time.
(i)
Scheme design: the combined operation result is affected by the comprehensive function from injection and production parameters. In order to solve the question of parameter optimization, the orthogonal numerical test is carried out to analyze the influence parameter. Through overall considering, nine factors are considered, in which six parameters are from thermal recovery development, i.e., steam injection velocity, shut-in time, injection quantity in a cycle, steam injection temperature, and the cycle time of thermal fluid huff and puff. And the three parameters are from conformance control development, i.e., polymer concentration, slug size, and the interval time of polymer injection. Considering the conservation of formation energy in the injection and production operations, production-injection ration is also considered. By way of these parameters, the effect to the production result of the combined operation can be analyzed. The production-injection ration is set 8 levels. Other parameters are set 4 levels, as shown in Table8. The orthogonal design table L3281×48 is adopted to get scheme design, as shown in Table 9.(ii)
The effect analysisTable 8
Orthogonal design factors and level values in the combined operation.
ParameterInfluence factorSteam injection velocity (t/d)Shut-in time (d)Injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratio112023500260920000.0460.82130340002651225000.0690.93140445002701530000.081214150550002751835000.10151.151.261.371.481.5Table 9
The experiment scheme and results of the combined operation.
SchemeSteam injection velocity (t/d)Shut-in time (d)Steam injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratioScheme resultComprehensive evaluation indexAccumulative oil increment (104 m3)Production-injection ratioRecovery ration increment (%)2112023500260920000.0460.85.63211.15314.55810.44822120240002651835000.08120.99.06111.40914.49711.6562312034500275925000.081514.63811.58315.42710.54924120350002701830000.0491.17.59313.03315.18611.937……………………………………4915043500265925000.10121.15.75710.95314.96110.55750150440002601830000.06619.02711.98814.44211.8195115054500270920000.0690.94.43611.52714.74310.23552150550002751835000.10150.87.38211.21214.76411.119Experiment scheme and its comprehensive evaluation index (according to Equation (1)) of B6 well group are shown in Table 9. The intuitive analytical table is shown in Table 10.Table 10
Intuitive analysis table of the B6 well group with combined operation.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratioMean value 111.15111.15711.47211.02510.61011.12211.26611.17610.658Mean value 211.15111.27811.23211.12210.82511.09011.18211.13810.933Mean value 311.12411.05310.94011.22311.33311.19511.12611.11211.152Mean value 411.16811.10710.95011.22411.82511.18711.02111.16711.098Mean value 511.217Mean value 611.224Mean value 711.391Mean value 811.515Prior level150335002751830000.0461.5Difference of mean value between the maximum and minimum0.0440.2250.5320.1991.2150.1060.2450.0640.857From Table10, we can see that the best level of steam injection velocity, shut-in time, steam injection quantity in a cycle, steam injection temperature, the cycle time of thermal fluid huff and puff, polymer concentration, slug size, interval time of conformance control flooding, and the production-injection ratio is, respectively, 150 t/d, 3d, 3500 t, 275°C, 18 months, 3000 mg/L, 0.04 PV, 6 months, and 1.5. After numerical simulation calculation with the value of the best level, the accumulative oil increment is by 5.26×1043, the production-injection ratio by 6.29, recovery efficiency increment by 7.36%, and comprehensive evaluation index by 6.30. From the difference of the mean value between maximum and minimum in Table 10, the primary and secondary order of injection parameters to development effect is the cycle time of thermal fluid huff and puff (month) > production − injection ratio > cycle time of the steam injection quantity (t) > slug size (PV) > shut-in time (d) > steam injection temperature (°C) > polymer concentration (mg/L) > interval time of polymer injection (month) > steam injection velocity (t/d).
(5)
The effect contrast of three production patterns: numerical simulation of the B6 well group was carried out with three production patterns, i.e., conformance control flooding, thermal recovery, and combined operation (conformance control flooding and thermal recovery). The result is shown in Table11 and Figure 5.Table 11
The effect contrast of three production patterns of the B6 well group.
Well groupProduction patternAccumulative oil increment (104 m3)Production-injection ratioRecovery efficiency increment (%)Comprehensive evaluation indexB6 well groupConformance control flooding1.412.481.881.92Thermal recovery2.193.063.562.94Combined operation5.266.297.366.30Figure 5
The comprehensive evaluation index of three production patters of the B6 well group.As shown in Table11 and Figure 5, in the three production patterns, i.e., profile control flooding, thermal recovery, and combined operation, the comprehensive evaluation index of the combined operation is the highest and has the best oil increment. It indicates in the process of conformance control flooding that the conformance control flooding agent first entered into the high permeable layer and blocked off the high permeability stripe. At the same time in the thermal recovery process, the thermal fluid huff and puff can heat the reservoir, increase the formation temperature, reduce the oil viscosity, and decrease flow resistance. Because there is a synergistic effect in the combined operation, its oil production increment is much better than the total of both thermal recovery and conformance control flooding.


## 3.2.1. Reservoir Geologic Model

NB35-2 oilfield is located in the Bohai central waters, and the depth of the water is about 12 m. The oilfield is a multiple nose-like structure reservoir composed of three types of traps which are semi-anticline, complicated fault, and slope belt. The oilfield has the characteristics of shallow burial, abundant reserves, complex fluid property, high viscosity and density, low sulfur content, low solidification point, and medium wax content. The oilfield was put into production in September 2005. Up to now, there are 25 oil wells and 1 gel injection well. The daily oil production is 220 m3/d, the ratio of total oil output to original oil in place (OOIP) is 1.5%, and the oil recovery rate is as low as 0.3%.The dynamic model of NB35-2 oilfield was established with CMG imported from the static model in Petrel. In the model, the input of the parameters includes well number database, subzone database, breakpoint point database, performance dynamic data of oil and water wells (well history data), well-log information, reservoir fluid property, and sedimentary facies data (as shown in Figure3). In the model, grid number is NX×NY×NZ129×50×62=399900, the planar grid is 50×50, and longitudinal grid is 1-2 m.Figure 3
Numerical simulation model.


## 3.2.2. The Effect Contrast with the Three Production Patterns

(1)
As an example of the B6 well group (as shown in Figure4), the oil increment effect of the three kinds of production patterns which were conformance control flooding, thermal recovery, and combined operation (conformance control flooding & thermal recovery) was compared.(2)
Conformance control flooding: according to real production situation of the oilfield, in the numerical simulate research, B30h well started to produce oil on February 11, 2015, while B31h well on August 1, 2015. At the same time, polymer gel injection was conducted for conformance control in B6 well.(i)
Scheme design: the influence factors of oil increment effect in the conformance control flooding by polymer gel include polymer concentration, slug size, and interval time of the polymer injection. The injection scheme of conformance control flooding by polymer gel was designed by use of the orthogonal numerical test. Each influence factor has two levels (i.e., designed value, as shown in Table2). Orthogonal design table L423 is adopted to design schemes, as shown in Table 3.(ii)
Selection of Evaluation index: accumulative oil increment, production-injection ratio, and recovery ratio increment of the well group are the technical indexes to evaluate the effect of conformance control flooding. Therefore, the three evaluation indexes were integrated into a comprehensive evaluation index, as shown in the Equation (1). The comprehensive evaluation index can be as the evaluation index of the orthogonal test.
(1)ϕ=αRzy+βRct+γRcc,where ϕ is the comprehensive evaluation index of different development modes, including Pattern 1 (conformance control flooding), Pattern 2 (thermal recovery), and Pattern 3 (conformance control flooding and thermal recovery); Rzy is the accumulative oil increment (104m3); Rct is the production-injection ratio; Rcc is the recovery ratio increment (%); and α,β,γ are the weight coefficients of accumulative oil increment, production-injection ratio, and recovery ratio increment, generally being 1/3, respectively.Figure 4
The schematic diagram of the B6 well group. The blue arrow represents the target study well group, and the gray arrow represents the nonstudy well group around the target one.Table 2
Orthogonal design factors and their level values in profile control flooding.
LevelFactorPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)125000.069230000.0812Table 3
The conformance control flooding scheme and effect of B6 well group.
ParameterPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)The result of schemeComprehensive evaluation indexAccumulative oil increment (104 m3)Production-injection ratioRecovery ratio increment (%)125000.0690.9182.1121.2241.418225000.08121.2912.5151.7211.842330000.06121.0122.1361.3491.499430000.0891.3542.3841.8061.848The comprehensive evaluation index is higher, the production-injection parameters are superior, and the economic benefit of the development modes (Pattern 1, Pattern 2, or Pattern 3) will be better.(iii)
The effect analysis of oil increment: program result and comprehensive evaluation index are showed in Table3. The intuitive analysis table is shown in Table 4.Table 4
Intuitive analysis table of B6 well group.
ParameterPolymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Mean value 11.6301.4591.633Mean value 21.6741.8451.671Prior level30000.0812Difference of mean value between the maximum and minimum0.0430.3870.038As shown in Table4, in the orthogonal numerical test, the values of the best levels for polymer concentration, slug size, and interval time of the polymer injection are 3000 mg/L, 0.08 PV, and 12 months, respectively. According to the simulation, the combination of optimal levels was able to yield an accumulative oil increment of 1.41×104 m3 (1.88%), a production-injection ratio of 2.48, and a comprehensive evaluation index of 1.92. From the difference of the mean value between the maximum and minimum in Table 4, the primary and secondary order of injection parameters to development effect is slugsizePV>polymerconcentrationmg/L>interval time of polymer injection (month).
(3)
Thermal recovery: numerical simulation on the B6 well group was also carried out multiple thermal fluid huff, and puff was conducted in oil wells (B30h and B31h) while water flooding was conducted in injection well (B6 well).According to practical production situation of the oilfield, in the numerical simulate research, B30h well and B31h (in the B6 well group) started to thermal fluid huff and puff, respectively, on February 11 and August 1, in 2015. The injection well started water flooding at the same time.(a)
Scheme design: in order to optimize the parameters in thermal recovery, the orthogonal numerical test is carried out to analyze the influence factors. Under overall considering, there are five factors, i.e., steam injection velocity, shut-in time, steam injection temperature, the cycle time of thermal fluid huff and puff, and steam injection quality in a cycle. Each influence factor has four levels, as shown in Table5. The orthogonal design table L1645 is adopted to design schemes, as shown in Table 6.
(ii)
The effect analysis: experiment scheme and the comprehensive evaluation index (according to Equation (1)) of B30h well in B6 group are shown in Table 6. The intuitive analysis table is shown in Table 7.Table 5
Orthogonal design factors and level values in the thermal fluid huff and puff.
LevelFactorSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)1120226093500213032651240003140427015450041505275185000Table 6
The experiment scheme and its result of B30h well with thermal recovery.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)Scheme resultComprehensive evaluation indexAccumulative oil increment (m3/t)Production-injection ratioRecovery increment (%)51202260935000.7721.5822.1631.506612032651240000.8421.6382.0201.500712042701545000.9121.7592.0521.574812052751850001.0521.9132.1041.690…………………………1715022751245000.7971.7442.1511.564181503270950000.5341.5642.1371.4121915042651835001.8952.4122.6532.3202015052601540001.2632.1652.5261.985Table 7
Intuitive analysis table of B30 well in thermal recovery experiment.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Steam injection quantity in a cycle (t)Mean value 11.5681.6361.7021.4381.826Mean value 21.6211.6331.7011.5601.702Mean value 31.6551.7131.6321.7431.582Mean value 41.8201.6811.6291.9231.553Prior level1504260183500Difference of mean value between the maximum and minimum0.2520.0800.0730.4850.273From Table7, we can see that the optimal levels of steam injection velocity, shut-in time, steam injection temperature, the cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle were, respectively, 150 t/d, 4d, 260°C, 18 months, and 3500 t, respectively. After the combination of optimal levels was able to yield an accumulative oil increment of 1.902×104 m3 (2.701%), a production-injection ratio of 2.431, and a comprehensive evaluation index of 2.345. From the difference of mean value between the maximum and minimum in Table 4, the primary and secondary order of injection parameters to development effect is the cycle time of thermalfluidhuffandpuffmonth>thesteaminjectionquantityinacyclet>steaminjectionvelocityt/d>shut‐intimed>steam injection temperature (°C).Similarly, for B31h well, the best level of steam injection velocity, shut-in time, steam injection temperature, cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle is, respectively, 140 t/d, 3d, 275°C, 18 months, and 3500 t. After numerical simulation calculation with the value of the best level, the accumulative oil increment is2.471×104 m3, production-injection ratio is 3.695, recovery efficiency increment is 4.304%, and comprehensive evaluation index is 3.490. The primary and secondary order of injection parameters to development effect is the cycle time of thermal fluid huff and puff (month) > steam injection temperature (°C) > steam injection velocity t/d>shut‐intimed>thesteaminjectionquantityinacyclet.Then, after numerical simulation calculation of the B6 well group (B30h oil well and B31h oil well) with the value of the best level, the accumulative oil increment is 2.19×104 m3, production-injection ratio is 0.6, recovery efficiency increment is 3.56%, and comprehensive evaluation index is 2.92.
(4)
Combined operation (conformance control flooding and thermal recovery): the combined operation (conformance control flooding and thermal recovery) is carried out in the B6 well group. Multiple thermal fluid huff and puff was conducted in oil wells (B30h and B31h), while conformance control flooding with polymer gel was conducted in injection well (B6 well) at the same time.According to practical production situation of the oilfield, in the simulation research, B30h and B31h wells (in the B6 well group) started to multi thermal fluid huff and puff for oil production, respectively, on February 11th and August 1st, in 2015. The injection well started conformance control flooding with polymer gel at the same time.
(i)
Scheme design: the combined operation result is affected by the comprehensive function from injection and production parameters. In order to solve the question of parameter optimization, the orthogonal numerical test is carried out to analyze the influence parameter. Through overall considering, nine factors are considered, in which six parameters are from thermal recovery development, i.e., steam injection velocity, shut-in time, injection quantity in a cycle, steam injection temperature, and the cycle time of thermal fluid huff and puff. And the three parameters are from conformance control development, i.e., polymer concentration, slug size, and the interval time of polymer injection. Considering the conservation of formation energy in the injection and production operations, production-injection ration is also considered. By way of these parameters, the effect to the production result of the combined operation can be analyzed. The production-injection ration is set 8 levels. Other parameters are set 4 levels, as shown in Table8. The orthogonal design table L3281×48 is adopted to get scheme design, as shown in Table 9.(ii)
The effect analysisTable 8
Orthogonal design factors and level values in the combined operation.
ParameterInfluence factorSteam injection velocity (t/d)Shut-in time (d)Injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratio112023500260920000.0460.82130340002651225000.0690.93140445002701530000.081214150550002751835000.10151.151.261.371.481.5Table 9
The experiment scheme and results of the combined operation.
SchemeSteam injection velocity (t/d)Shut-in time (d)Steam injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratioScheme resultComprehensive evaluation indexAccumulative oil increment (104 m3)Production-injection ratioRecovery ration increment (%)2112023500260920000.0460.85.63211.15314.55810.44822120240002651835000.08120.99.06111.40914.49711.6562312034500275925000.081514.63811.58315.42710.54924120350002701830000.0491.17.59313.03315.18611.937……………………………………4915043500265925000.10121.15.75710.95314.96110.55750150440002601830000.06619.02711.98814.44211.8195115054500270920000.0690.94.43611.52714.74310.23552150550002751835000.10150.87.38211.21214.76411.119Experiment scheme and its comprehensive evaluation index (according to Equation (1)) of B6 well group are shown in Table 9. The intuitive analytical table is shown in Table 10.Table 10
Intuitive analysis table of the B6 well group with combined operation.
ParameterSteam injection velocity (t/d)Shut-in time (d)Steam injection quantity in a cycle (t)Steam injection temperature (°C)Cycle time of thermal fluid huff and puff (month)Polymer concentration (mg/L)Slug size (PV)Interval time of polymer injection (month)Production-injection ratioMean value 111.15111.15711.47211.02510.61011.12211.26611.17610.658Mean value 211.15111.27811.23211.12210.82511.09011.18211.13810.933Mean value 311.12411.05310.94011.22311.33311.19511.12611.11211.152Mean value 411.16811.10710.95011.22411.82511.18711.02111.16711.098Mean value 511.217Mean value 611.224Mean value 711.391Mean value 811.515Prior level150335002751830000.0461.5Difference of mean value between the maximum and minimum0.0440.2250.5320.1991.2150.1060.2450.0640.857From Table10, we can see that the best level of steam injection velocity, shut-in time, steam injection quantity in a cycle, steam injection temperature, the cycle time of thermal fluid huff and puff, polymer concentration, slug size, interval time of conformance control flooding, and the production-injection ratio is, respectively, 150 t/d, 3d, 3500 t, 275°C, 18 months, 3000 mg/L, 0.04 PV, 6 months, and 1.5. After numerical simulation calculation with the value of the best level, the accumulative oil increment is by 5.26×1043, the production-injection ratio by 6.29, recovery efficiency increment by 7.36%, and comprehensive evaluation index by 6.30. From the difference of the mean value between maximum and minimum in Table 10, the primary and secondary order of injection parameters to development effect is the cycle time of thermal fluid huff and puff (month) > production − injection ratio > cycle time of the steam injection quantity (t) > slug size (PV) > shut-in time (d) > steam injection temperature (°C) > polymer concentration (mg/L) > interval time of polymer injection (month) > steam injection velocity (t/d).
(5)
The effect contrast of three production patterns: numerical simulation of the B6 well group was carried out with three production patterns, i.e., conformance control flooding, thermal recovery, and combined operation (conformance control flooding and thermal recovery). The result is shown in Table11 and Figure 5.Table 11
The effect contrast of three production patterns of the B6 well group.
Well groupProduction patternAccumulative oil increment (104 m3)Production-injection ratioRecovery efficiency increment (%)Comprehensive evaluation indexB6 well groupConformance control flooding1.412.481.881.92Thermal recovery2.193.063.562.94Combined operation5.266.297.366.30Figure 5
The comprehensive evaluation index of three production patters of the B6 well group.As shown in Table11 and Figure 5, in the three production patterns, i.e., profile control flooding, thermal recovery, and combined operation, the comprehensive evaluation index of the combined operation is the highest and has the best oil increment. It indicates in the process of conformance control flooding that the conformance control flooding agent first entered into the high permeable layer and blocked off the high permeability stripe. At the same time in the thermal recovery process, the thermal fluid huff and puff can heat the reservoir, increase the formation temperature, reduce the oil viscosity, and decrease flow resistance. Because there is a synergistic effect in the combined operation, its oil production increment is much better than the total of both thermal recovery and conformance control flooding.


## 3.3. The Effect Analysis of the Field Test

As an example of the B6 well group, polymer weak gel flooding was carried out in B6 injection well on July 13, 2016. Its injection allocation is 120 m3/d, the mass injection concentration of polymer at wellhead is 2800 mg/L, the wellhead viscosity is 64.0 Pa·s, and the wellhead pressure is from 3.9 MPa to 10.39 MPa. On October 1, 2017, the protection slug was injected, with the concentration of 40,000 mg/L, the viscosity of 150 mPa·s, and injection allocation of 80m3/d. Then, the wellhead pressure rose from 7.15 MPa to 9.9Mpa (as shown in Figure 6). This indicated that after the polymer gel entered into the reservoir, it first entered into the high permeability layer and had retention. This can lead to reduce overcurrent section, increase flow resistance, enhance wellhead injection pressure, and enlarge suction hydraulic difference between medium and low permeability layers. So the suction quantity increased and made a valid use of them. That achieved the purpose of conformance control flooding.Figure 6
Production profiles of the B6 well.Take B31h well for example, after conformance control flooding in B6 well on July 1, 2016, the daily oil production of B31h has a distinct rise, with the water cut greatly decreasing. After the shut-in time in the second cycle of thermal fluid huff and puff of in March 2017, the daily oil production rose by a great margin, with the water cut rapidly decreasing (as shown in Figure7). In cut-off by August 2019, the accumulative oil production of combined operation (conformance control flooding and thermal recovery) reached 4.18×104 m3. Compared with water flooding development (the accumulative oil production by numerical simulation being 1.19×104 m3), the accumulative oil increment reached 2.09×104 m3. The accumulative oil production with conformance control flooding can reach 2.21×104 m3. Its accumulative oil increment is 1.02×104 m3 compared with water flooding development. The accumulative oil production with thermal recovery is 1.93×104 m3. Its accumulative oil increment is 0.74×104 m3 compared with water flooding development, as shown in Figure 8. Thus, it can be seen that the accumulative oil increment by combined operation is much higher than the sum of oil increment by conformance control flooding and thermal recovery. It is illustrated that after thermal fluid huff and puff of B31h well, the reservoir nearby the well bottom was heated, with the viscosity of crude oil declining and the seepage resistance decreasing. Together with the effect of conformance control flooding of B6 well, the synergistic effect of both of them can achieve a better productive result.Figure 7
Production profiles the B31 well.Figure 8
Comparison of accumulative oil increment (104 m3).


## 3.4. Mechanism Analysis

From the experimental and numerical results and field test, the combined operation (“conformance control flooding and thermal recovery”) obtained a good oil recovery. The mechanism diagram is shown in Figure9. Compared with original reservoir (Figure 9(a)), after the water flooding (Figure 9(b)), only the crude oil in the near-well zone and the straight area between the injection well and production wells are produced, especially forming an obvious channel between the injection well and its diagonal O2 oil well. Due to the high viscosity of the crude oil, the mobility ratio of the oil and water is relatively high, which greatly reduced the sweep coefficient of the injected water, resulting in poor water flooding effect. If thermal recovery (Figure 9(c)) was carried out in the diagonal O2 oil well of injection well after water flooding, it is obvious that the crude oil around the O2 oil well is produced largely due to the injected thermal fluid decreasing the viscosity of the crude oil near it result in lower flow resistance. If conformance control (Figure 9(d)) was carried out in injection well after water flooding, compared with water flooding (Figure 9(b)), more oil was produced due to the increased sweep coefficient of oil displacing agent and the main produced area was the same as water flooding (Figure 9(b)) but with a larger scope. And the crude oil located on the main line between the injection well and its diagonal well is mostly produced forming a thicker channel. If combined operation (Figure 9(e)) was carried out with conformance control of injection well and thermal recovery of the diagonal O2 oil well of injection well, a better recovery result was obtained when more oil was produced. In particular, a good development effect was obtained around the thermal recovery well due to the low viscosity of the crude oil in this area and the oil displacing agent swept more area, which was called synergistic effect achieving better development results.Figure 9
Mechanism diagram. (a) Crude oil distribution in the original reservoir. (b) Crude oil distribution after water flooding. (c) Crude oil distribution after thermal recovery. (d) Crude oil distribution after conformance control. (e) Crude oil distribution after combined operation (“conformance control flooding and thermal recovery”).
(a)(b)(c)(d)(e)


## 4. Conclusions

In this paper, through the comparison results of physical simulation and numerical simulation of three development methods (conformance control, Pattern 1; thermal recovery method, Pattern 2; and conformance control and thermal recovery, Pattern 3), it is proved that Pattern 3 yielded the highest oil recovery and it recovered more oil than the sum of Pattern 1 and Pattern 2 used separately. Through the mechanism analysis, the synergistic effect was considered to achieve the better development results. So the development method of Pattern 3 (conformance control and thermal recovery) can be used as an effective development mode for heavy oil reservoir. This work provides theoretical guidance for its further application. At the same time, the optimal injection parameters of three different development modes are obtained by numerical simulation, which can guide the phased development of the target reservoir to a certain extent. The details are as follows:(1)
In the production pattern with conformance control flooding, the value of the best level of polymer concentration, slug size, and interval time of the conformance control flooding is 3000 mg/L, 0.08 PV, and 12 months, respectively. The primary and secondary order of injection parameters to development effect isslugsizePV>polymerconcentrationmg/L>intervalspacepolymerinjectionmonth(2)
In the development pattern of B31h well with thermal recovery, the value of the best level of steam injection velocity, shut-in time, steam injection temperature, cycle time of thermal fluid huff and puff, and the steam injection quantity in a cycle is, respectively, 150 t/d, 4 d, 260°C, 18 months, and 3500 t. The primary and secondary order of injection parameters to development effect is the cycle time ofthermalfluidhuffandpuffmonth>thesteaminjectionquantityinacyclet>steaminjectionvelocityt/d>shut‐intimed>steaminjectiontemperature°C(3)
In the development pattern of combined operation (conformance control flooding and thermal recovery), the value of the best level of steam injection velocity, shut-in time, steam injection quantity in a cycle, steam injection temperature, cycle time of thermal fluid huff and puff, polymer concentration, slug size, interval time of profile control flooding, and production-injection ratio is, respectively, 150 t/d, 3 d, 3500 t, 275°C, 18 months, 3000 mg/L, 0.04 PV, 6 months, and 1.5. The primary and secondary order of injection parameters to development effect is cycle time ofthermalfluidhuffandpuffmonth>production−injectionratio>cycletimeofthesteaminjectionquantityt>slugsizePV > shut-in time (d) > steam injection temperature (°C) > polymer concentration (mg/L) > interval time of polymer injection (month) > steam injection velocity (t/d)(4)
Through the research by both physical and numerical simulation, the synergistic effect exists in the combined operation. Its oil production increment effect is much better than the sum of the conformance control flooding and thermal recovery



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