Study on Fracturing Parameters Optimization of Horizontal Wells in Low-Permeability Reservoirs in South China Sea

Abstract

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m³ of the sands and 700 m³ of the fluids. This research provides a new model for offshore low-permeability oilfield development.

1. Introduction

With the continuous deepening of offshore oil and gas exploration and development, there is a major strategic demand for increasing offshore oil and gas storage and production to improve the utilization degree of low-permeability reserves and improve the development effect of low-permeability reservoirs [1,2]. Due to factors such as the special environment of offshore platforms, working space, and development costs, the development effect of low-permeability oil fields is not ideal [3,4]. At present, the main measures for increasing production in offshore oil fields include small-scale stimulation technologies such as acidizing, deflagration fracturing, and microfracturing. However, these measures create small-scale fractures near the wellbore, making it difficult to form effective support for the fractures, and the effective time is short, resulting in the inability to achieve the economic development of low-permeability offshore oil fields [5,6,7,8,9].

Currently, hydraulic fracturing in low-permeability reservoirs in onshore oilfields primarily involves vertical-well multilayer fracturing and horizontal-well staged fracturing. In contrast, offshore oilfields face limitations due to factors like offshore operational environments, load capacities, safety concerns, and transportation conditions. Consequently, offshore hydraulic fracturing tends to have smaller scales and less operational continuity. Typically, it involves single-well, single-layer fracturing, with fewer instances of multilayer fracturing and horizontal-well staged fracturing. Multistage fracturing in a horizontal well is mainly used in onshore oil and gas fields, and a reasonable frac design is a prerequisite to ensure the effectiveness of the reservoir stimulation. The optimized parameters include the sweet spot, number of fracturing sections, fracture length, conductivity, etc. [10,11,12]. The conventional method is to use a numerical reservoir simulation to determine the number of fracturing stages, with production as the target, and then divide the fracturing positions based on the comprehensive interpretation results of logging and mud logging. Lei et al. proposed an optimization design method for fracture-controlled fracturing. By optimizing parameters such as the fracture orientation, geometry, and spacing within the pay unit controlled by the horizontal well and optimizing the treatment parameters, a horizontal well can achieve the maximum production, the highest recovery rate, and the best economic benefits [13,14]. Based on the simplified 3D displacement discontinuity method, Olson et al. compiled a fracture propagation simulator, compared the influence of different cluster spacings on the modified volume of a single well, and carried out cluster spacing optimization, with the modified volume as the objective function [15]. Li et al. combined the fracture propagation, a productivity simulation, and automatic search algorithms to establish a complete intelligent optimization workflow of the high-dimensional hydraulic fracturing parameters to obtain the best-matched set of fracturing parameters in the global scope and maximize the value of economic indicators as the objective function [16]. Xu et al. used an embedded discrete crack model to comprehensively compare the optimization results of GPS, GA, the multistage coordinate search (MCS), and the covariance matrix adaptive evolutionary strategy (CMA-ES). The results show that differential evolution (DE) has obvious advantages in the field of fracturing optimization due to its strong global convergence and robustness [17]. Rahmanifard et al. adopted three random gradient-free optimization methods such as GA, DE, and particle swarm optimization (PSO) to optimize four fracturing parameters of a single well, including the number of fracturing stages, fracture spacing, fracture half-length, and segment spacing [18].

However, unlike onshore oilfields, due to platform space limitations, there is no room for fracturing equipment such as frac pumps, blenders, sand and fluid tanks, etc., to be placed, and offshore low-permeability oilfields have short well spacings, complex well types, and significant differences in completion methods compared to onshore oilfields. Conventional optimization methods are difficult to match with offshore fracturing techniques [19,20,21,22]. In order to efficiently fracture low-permeability reservoirs from an economic standpoint, starting from the perspective of optimizing fracturing parameters, numerical simulations are applied to optimize key parameters such as the number of fracturing stages and the half-fracture length. This research provides guidance and a reference for designing subsequent fracturing development plans for offshore oil and gas reservoirs.

2. Evaluation of Compressibility of H Field

2.1. Geological Background

The H oilfield is located on the north slope of the Dongsha Massif, south of the Huizhou Depression in the Pearl River Mouth Basin, South China Sea. The fault block structure is controlled by two NWW northward-dipping faults and one NE west-dipping depression-controlling fault. According to the reservoir-forming intervals, it can be divided into four tectonic units from bottom to top: the Buried Hill Formation, the Wenchang Formation, the Enping Formation, and the Zhuhai Formation. The target zone is the Buried Hill Formation. The lithology of the Buried Hill Formation is complex, and it can be divided into three categories, which are mainly intrusive rock, extrusive rock, and dynamic metamorphic rock. The characteristics of the cap rock in oil and gas reservoirs include its dense and predominantly pure nature, low sand content, and its position in the middle to late stages of diagenesis, which grants it good sealing capabilities. The lithology of the Buried Hill Formation is mainly medium coarse sand, partly sand conglomerate. According to the core, wall core and cuttings analysis, the zone is divided into two small layers, which are BH1 and BH2, respectively. As shown in Figure 1, the BH1 sand group is mainly consist of light gray gravelly coarse sandstone with a small amount of gravelly coarse sandstone and gravel conglomerate, while the BH2 sand group is dominated by gravelly coarse sandstone, gravel conglomerate and gravel medium sandstone.

2.2. Geological Characteristics of H Oilfields

The H oilfield is located in the composite fault zone in the south of the Huizhou depression in the Pearl River Mouth Basin. The main target zones are the Wenchang Formation and Buried Hill. The depth of the Buried Hill reservoir is 3450~4321 m, the upper part of the reservoir is thick diorite, the middle part is tectonic schist and basaltic andesite, and the bottom is granite. As shown in Figure 2, the average porosity of the Buried Hill is 4.6%, and the average permeability is 2.0 mD, which classifies it as a typical low-permeability reservoir. The geothermal gradient of the oilfield is 3.56 °C/100 m, and the pressure coefficient is 1.027~1.076, which falls within the normal temperature and pressure system.

Tectonic fractures, dissolution fractures, and caves are developed in the Buried Hill reservoir, including network fractures, medium-angle fractures, low-angle fractures, and induced fractures. According to the interpretation of imaging logging (see Figure 3), it is found that network fractures are characterized by the coexistence of medium- and high-angle fractures and low-angle fractures. The fracture angles are mainly concentrated in the range from 30° to 80°, and those fractures have good connectivity. The low-angle fractures are mainly lower than 30°, and the development cracks have high fracture density. The induced fractures are arranged neatly with strong regularity, and the shape of the surface is relatively regular with a minimal variation in fracture width. At a macroscopic level, the predominant fractures are primarily characterized by unfilled or partially filled open fractures, which are filled with materials such as calcite and quartz. It is the reason that the main reservoir spaces are porous and fractured reservoirs. Therefore, the development of natural fractures in the Buried Hill Formation of the H oilfield requires consideration of the impact of natural fractures on reservoir stimulation.

2.3. Rock Mechanics Characteristics

In the Middle Jurassic, four wells were drilled in the Buried Hill Formation in the H oil field. Based on the observation of core samples, sidewall cores, and cuttings, as well as the results of thin section identification and elemental analysis from these four wells, it was found that the lithology of the Buried Hill Formation is complex and can be categorized into three major groups and multiple subgroups. The three major categories primarily include intrusive rocks, volcanic rocks, and dynamically metamorphosed rocks. In order to evaluate the mechanical properties and strength characteristics of reservoir rocks, the linear elasticity parameters of Buried Hill Formation cores were tested by a triaxial compression test. The experimental results are shown in

Table 1. Experimental results of triaxial compression of core rocks in Buried Hill reservoirs in oil fields.

Well	Well Depth	Confining Pressure MPa	Density g/cm3	Elastic Modulus GPa	Poisson Ratio	Compressive Strength MPa	Internal Friction Angle °	Cohesion MPa
H-7	4156.5	40	2.38	9.19	0.30	95.45	26.38	16.51
		50	2.38	11.00	0.23	106.29
		60	2.38	12.09	0.32	116.88

.

Based on the experimental results, the heterogeneity of the Buried Hill reservoir is strong. The triaxial compressive strength of the H-7 well core ranges from 95.45 to 116.88 MPa, with an average of 106.20 MPa, the elastic modulus ranges from 9.19 to 12.09 GPa, with an average of 10.76 GPa, and the Poisson’s ratio ranges from 0.23 to 0.32, with an average of 0.28. According to the characteristics of rock mechanics, the strength of the formation is not that strong.

2.4. Rock Mineral Characteristics

The distribution of minerals in the Buried Hill Formation is uneven, and the content of each mineral varies greatly. The main mineral compositions are quartz and feldspar. Those brittle minerals have a great impact on rock brittleness. Drawing on fundamental principles of rock mechanics and field experience, rock brittleness is widely regarded as the key factor affecting hydraulic fractability. Rocks with a higher clay content tend to experience plastic deformation during hydraulic fracturing, leading to the simple fracture patterns, while rocks with a higher content of brittle minerals like quartz are more prone to the development of complex fracture networks during fracturing. The brittleness index is one of the most crucial quantitative parameters for evaluating rock properties and selecting a sweet spot. At present, the evaluation of rock brittleness mainly characterizes the brittle characteristics of rock masses through mineral brittleness and mechanical brittleness [23,24,25,26]. Due to the lack of data of sufficient samples, mineral composition analysis was conducted for seven rock samples in the study area. The brittleness index based on rock mineral composition [27] can be obtained from Formula (1). See

Table 2. Analysis results of rock and mineral composition in Buried Hill Formation of H oilfield.

Number	Ingredients (%)
	Quartz	Potassium Feldspar	Plagioclase	Calcite	Pyrite	Dolomite	Laumontite	Clay	BI
1	58.1	12.7	5.9	4.8	0.3	0	0	18.2	63.2
2	55.6	13.4	4.7	3.9	0.3	0	0	22.1	59.8
3	61.2	10.3	5.8	4.2	0.2	0	0	18.3	65.6
4	47.0	17.0	5.0	0	0	7.0	0	24.0	54.0
5	37.5	21.4	30.0	2.2	0.3	3.4	4.5	0.7	43.4
6	44.0	17.0	33.0	0	0	4.0	0	2.0	48.0
7	32.0	16.0	29.0	5.0	0	4.0	0	14.0	41.0

for the experimental results.

$$BI=\frac{W_q+W_c}{W_T}\times 100$$

(1)

In the formula, W_q and W_c are, respectively, the content of quartz and carbonate rock in the rock.

It can be seen from Table 2 that the content of brittle minerals such as quartz in the Buried Hill Formation is high, and the brittleness index ranges from 41.0% to 65.6%. Considering the development of natural fractures in this area, it is able to form complex fractures after fracturing.

Based on the DST test results of adjacent well areas, the reservoir thickness of the Buried Hill Formation is about 150 m with volatile oil in the lower part and condensate gas cap in the higher part. It is a blocky oil reservoir with a gas cap. According to the field experience of low-permeability reservoirs, fracturing treatment can effectively improve oil and gas production. H-11 in the H oilfield was selected as the target well, with a horizontal section length of 656 m. It is necessary to take the geological characteristics into full consideration. In addition, optimized fracturing parameters will increase the stimulation volume of the reservoir (SRV).

2.5. Testing of Exploration

Taking the well H-11 as an example, the total thickness is 340.75 m (from 3830.00 to 4170.75 m) with an effective thickness of 102.2 m. Under a working regime with a 6.35 mm nozzle and an average flow pressure difference of 24.95 MPa, the daily average oil production is about 23.5 m³ and the daily gas production is 18,207 m³ under the condition of a 6.35 mm nozzle and flow pressure of 24.95 MPa. If the nozzle and flow pressure increase to 7.94 mm and 26.922 MPa, respectively, the daily average oil production will go up to 35.9 m³, and the daily gas production is 22,568 m³. When using a 9.53 mm nozzle with an average flow pressure of 29.618 MPa, the daily average oil production decreases to 25.2 m³, and the daily gas production is 22,296 m³. Increasing the flow pressure actually results in decreased producing energy, indicating insufficient reservoir fluid supply. The calculated oil recovery index is approximately 0.0085 m³/(d· MPa· m), indicating low productivity.

In summary, the formation has an average reservoir thickness of 112.4 m with porosity ranging from 0.5% to 17.1% and permeability ranging from 0.019 to 64.3 mD. Various data sources, including imaging logs, core analysis, and thin sections, consistently reveal the presence of dissolution pores and network fractures. The fracture density falls within the range of 4.6 to 6.2 fractures per meter, which is primarily characterized by fracture angles between 30° and 80°, with a prevalence of medium- to high-angle oblique fractures. These fractures are predominantly unfilled or partially filled open fractures often containing materials like calcite and quartz. Overall, the reservoir exhibits low porosity and very low permeability with the main storage spaces being porous and fracture–porous reservoirs, which warrants further production testing and enhancement.

3. Research on Optimization of Fracturing Parameters

The H-11 well has a vertical depth of 4000 m and a horizontal section length of 656 m; the casing structure consists of an open hole that is 24 inches + 13.375 inches + 9.625 inches + 8.5 inches. In the beginning, in order to improve production efficiency, the 3.5-inch oil pipe was embedded in the casing for direct production. Then, the 4.5-inch blind pipe was inserted into the horizontal open hole section for fracturing. Considering the special offshore operating condition, the fracturing treatment adopts the platform operation mode, and the operation equipment needs to be placed in the space of the modular drilling rig yard. Considering the wellbore condition and the limited space, the multistage fracturing technique with open-hole packer + sliding sleeves was adopted. The schematic diagram of a fracturing pipe string can be seen in Figure 4. In order to communicate hydraulic fractures and natural fractures efficiency, the concept of creating a complex fracture network by a “high pump rate + slickwater fluid system” was introduced.

Based on the characteristics of offshore oilfield development, taking into account the cost of well construction, fracturing investment, and direct production costs in the later stage, and based on the crude oil price and economic evaluation parameters, it is estimated that the economic cumulative production of a single offshore well must reach 10 × 10⁴ m³, while the cumulative production of a single well development in a low-permeability onshore oilfield is only 1 × 10⁴ m³. Therefore, the post-fracturing production puts forward higher requirements for the optimization of key parameters for the staged fracturing of offshore horizontal wells.

3.1. Fracture Parameter Optimization

The first step consists of the optimization of the number of frac stages. In order to meet the requirements of production, the well type, well spacing and number of frac stages was optimized by using numerical simulation methods [28]. The initial production and cumulative production were set as the objective functions. The results, as shown in Figure 5, indicate that the higher the number of fracturing stages, the higher the initial production. However, the production decline rate is also higher. There exists an optimal value for the number of fracturing stages that contributes to production. Beyond this optimal number of fractures, the rate of production increase becomes less significant. After 3 years, there is no significant difference in daily production under different fracturing stages. Based on the actual drilling conditions and production requirements of the H-11 well, the optimal number of fractures was six. Under this condition, the expected daily production after fracturing was 296 m³/d, and the cumulative production in 1 year after fracturing was 6.95 × 10⁴ m³, which can ensure the implementation of reservoir stimulation while meeting production needs.

Second, we consider fracture length optimization. For hydraulic fractures, the longer the fracture length is, the higher the production will be. This is because the increase in fracture length will lead to an increase in SRV. Meanwhile, it will also increase the resistance of airflow inside the fracture. Under the given fracture spacing condition, the interference among fractures will be severe with the fracture length increase, which results in the decline of the production. Aiming to obtain a long length, a higher pump rate is needed, and more cost should be paid. Therefore, there is an optimal value for the production rate. If the fracture length exceeds the optimal value, the increase in production will slow down.

The simulation results show that as the length of the fracture increases, the production also increases, but the required rate and fracturing scale also increase with the increase in the fracture length. The optimal supporting fracture length should be around 120 m, and the simulation results are shown in Figure 6.

3.2. Optimization of Treatment Parameters

Next, we optimize the fracturing string and slurry rate. Different from onshore oilfields, fracturing and production integrated strings are normally used in offshore platforms due to the requirements of economic cost and operation safety, aiming to reduce operational risk. The structure of the H-11 well strings were relatively special, with a production string of 3.5 inches in the upper part and a fracturing string of 4.5 inches in the lower part. The wellhead pressure limit was 85 MPa. According to adjacent well data, the extension pressure gradient of the target zone was 1.9 g/cm³, and the fracture pressure gradient was 2.0 g/cm³. Based on the conditions of the pipe string, the treatment pressure under different slurry rates was calculated, as shown in

Table 3. Pressure prediction under different slurry rates of the H-11 well.

Slurry Rate (m3/min)	Head of Liquid (MPa)	Pipe Friction under Guar (MPa)	Predicting Pressure under Guar (MPa)	Pipe Friction under Slickwater (MPa)	Predicting Pressure under Slickwater (MPa)
4	41.5	23.70	63.64	18.20	58.14
6	41.5	38.50	78.44	31.63	67.01
8	41.5	55.86	95.79	47.05	82.43
10	41.5	75.76	115.70	64.00	99.38
12	41.5	98.28	138.22	82.27	117.65

.

Increasing the slurry rate can increase the net pressure inside the fracture, which helps to form a complex fracture network, improve liquid efficiency, and thus increase the volume of the stimulation. According to Table 3, when using a guar fluid system and increasing the pump rate to 6 m³/min, the wellhead pressure reached 78.4 MPa, which is close to the limit pressure. If using a slickwater system, the rate can be increased to 8 m³/min.

Natural fractures were developed in the Buried Hill reservoir of well H-11, and the close cluster spacing and high rate fracture network fracturing concept was adopted. Therefore, slickwater was used as the working fluid in this well, which was able to communicate natural fractures on one hand and lower the treatment pressure on the other hand. Take the wellhead pressure limit into consideration, a rate of 6.0 m³/min was set to carry the proppants into the formation, and the pressure was about 67.01 MPa. In the slurry stage, the rate was timely increased according to the requirement of wellhead pressure resistance.

The strength of the 3.5-inch tubing used in the well was checked under the designed pressure and rate. Based on the 3.5 inches 10.2 lb/ft + 4.5 inches 9.2 lb/ft-P110 steel string combination, the pipe string was checked, as shown in Figure 7. The checked results show that the tensile safety factor was 1.62, the internal pressure safety factor was 1.56, the anti-extruding safety factor was 1.64, and the triaxial safety factor was 1.41. The safety requirements were met under the frac treatment conditions.

Another aspect to consider is fracturing scale optimization. With the increase in fracturing scale, the fracture height increases from 38.5 to 39.5 m. The stimulated area also increased, which ranged from 2.9 × 10⁴ m² to 3.4 × 10⁴ m². As can be seen from Figure 8, SRV tends to increase with the increase in fracturing scale. When the SRV reaches a certain extent, it is difficult to achieve more, and the fracture height and stimulated area have a very small increase with the increase in the scale. Considering the safety and cost comprehensively, the fracturing scale with 50 m³ sands + 700 m³ liquids was adopted, which can meet the treatment requirements.

4. Comparison of Optimization Results and On-Site Application

According to the optimization design results, the final multistage fracturing parameters of horizontal well H-11 are shown in

Table 4. Fracturing parameters of H-11 well.

Fracturing String	Length of Horizontal Section (m)	Stage Number	Rate (m3/min)	Sands (m3)	Fluids (m3)
31/2″ + 41/2″	656	6	6.0~8.0	50	700

. The pre-frac production of well H-11 is 100 m³/d, and the cumulative production after 1 year of exploitation is 3.07 × 10⁴ m³. By comparing the simulation results with the real field production, including more frac stages, a higher rate and more volume of proppants can help to increase the production of a single well in the H oilfield in the South China Sea. After fracturing and reconstruction, the production is 343 m³/d, and the yield increase ratio is about 3.4 times. After 1 year of cumulative exploitation, the predicted production is 7.66 × 10⁴ m³. The simulation results are shown in Figure 9 and Figure 10.

5. Conclusions

The key to the reservoir stimulation of the low-permeability reservoir is to form fractures with high conductivity. Based on the background of the H oilfield, this paper developed a study on the optimization of fracturing parameters. Experimental research and theoretical analysis were carried out on the basic geological characteristics and treatment parameters. The following conclusions are drawn:

• The Buried Hill Formation is a typical tight formation with low permeability and low porosity. The lithology of the formation is complex, which results in an uneven distribution of reservoir minerals. The content of brittle minerals such as quartz is high, and the brittleness index ranges from 41.0% to 65.6%. Considering the development of natural fractures in this area, it has the conditions to form complex fractures after fracturing.
• In the development process of the H oilfield in the South China Sea, it is recommended to adopt the network fracturing technique with a “high slurry rate + slickwater” concept, aiming to maximize the communication between artificial fractures and natural fractures.
• There is a reasonable match relationship between the number of fracturing stages and fracture half-length. The recommended number of frac stages is 6, the fracture length is 120 m, the pump rate is 6–8 m³/min, the sands scale of a single stage is about 50 m³, and the liquid volume is about 700 m³.
• According to the reservoir characteristics of the H oilfield in the South China Sea and the special type of offshore pipe column, it is recommended to use slickwater to increase the rate as well as simulated optimization of the liquid strength and sand strength for different fracturing stages.