Collaboration between Oil Development and Water/Power Consumption in High-Water-Cut Oilfields

Abstract

Waterflooding is the main development technique used in the vast majority of oilfields in the world. However, as the waterflood oilfields enter the stages with (ultra-)high water cut, the water/power consumption per ton of oil remains unabatedly high. This paper presents a systematic analysis of the development stages and strategies of some typical waterflood oilfields in the world and proposes the necessity to establish a mode and technical system of collaboration between oil development and water/power consumption in mature oilfields with (ultra-)high water cut. Then, taking a pilot test area of an ultra-high-water-cut oilfield in northeastern China as an example, this paper investigates its development mode and water/power consumption; optimizes the technical strategies from the aspects of fine reservoir analysis, artificial lift system and surface gathering system; and predicts the application results. It is found that the optimizations of fine reservoir analysis and development plans effectively reduce the water consumption per ton of oil and have a certain but not remarkable contribution to the power consumption per ton of oil. Moreover, the optimizations of the artificial lift system and surface gathering system significantly reduce the power consumption per ton of oil. Under conditions of low production and low efficiency, the optimization of the artificial lift system greatly improves the energy-saving effect, which will be a focus of future research. Finally, this paper recommends measures for collaboration between oil development and water/power consumption in high-water-cut oilfields.

1. Introduction

In 1965, the world oil consumption exceeded coal consumption for the first time, marking the onset of the “era of oil and gas”. Since then, oil has stayed in the world’s primary energy mix as a critical component. As the most primitive energy source and an important raw material, oil becomes the blood and pillar of the modern industry and plays an irreplaceable role in national defense, the military industry, aerospace, new materials and other sectors. According to the prediction of international authorities, oil will share 27% or more of the world’s primary energy consumption by 2040 or even in the longer term [1,2], as shown in Figure 1.

According to the World and China Energy Outlook 2060 (2022 edition) [2,3,4,5] issued by the CNPC Economics and Technology Research Institute, China’s primary energy demand is expected to reach the peak plateau in 2035–2040, and the primary energy mix will present a tripartite confrontation among non-fossil energy, coal and petroleum [6,7]. Under this context, China’s oil demand is predicted to peak at 780 million tons (MMt), or 0.53 ton per capita, before 2030, mainly driven by the growth of gasoline and kerosene, and decline gradually—to 590 MMt by 2050 (Figure 2). After the peak, the transport sector will see a decreased proportion but still remain above 50% in oil consumption, making it the major oil consumer. Meanwhile, oil will be increasingly promoted as a raw material for making carbon-fiber composite in high-end fields such as aircraft, rockets, satellites and missiles, and replace metallic high molecular synthetic materials. In traditional sectors such as the light industry, textile industry and agriculture (nitrogen fertilizer made from petrochemicals accounts for 80% of the total amount of fertilizers), the proportion of chemical oil will increase from 12.5% in 2018 to 66% by 2060. Therefore, oil will remain an important strategic resource for a long period of time to come.

There are three broad categories of oil recovery techniques: primary oil recovery, secondary oil recovery and tertiary oil recovery for conventional reservoirs [8,9]. For primary oil recovery, oil is produced or flows out of the wellbore chiefly due to the natural formation pressure of the reservoir, also known as depletion exploitation; this category of techniques can recover 10–15% of oil initially in place (OIIP) [10]. For secondary oil recovery, water or immiscible gas is artificially injected into the reservoir to increase the reservoir pressure and thus displace more oil from the reservoir; this category of techniques can recover 30–50% of OIIP. For tertiary oil recovery, chemical agents, thermal media or fluids that can be mixed with crude oil are injected into the reservoir to modify the physical properties of crude oil in the reservoir and increase the reservoir pressure, thus improving the ultimate recovery, also known as enhanced oil recovery; this category of techniques can recover 50–70% of OIIP. In the 1920s, waterflooding was started in oilfields. In the late 1940s, the Soviet Union attempted to extensively inject water at the very beginning of field development when constructing the Ural oil province, which is known as backup flooding. Later, in 1956, the Soviet Union first adopted internal cutting flooding to develop the Romashkino Field, which was a pioneering move in the history of oilfield development and achieved good results. From then on, this development method was adopted by numerous oilfields in the world [11].

The waterflood recovery of an oilfield depends on the oil displacement efficiency and swept volume of injected water. For an oilfield with a homogeneous pore structure, fluid properties and rock properties of the reservoir, if the physical and chemical properties of the injected water are not changed, the oil displacement efficiency basically will not change remarkably at a certain injection pore volume [12]. Therefore, the key to improving waterflood recovery is to expand the swept volume of injected water. Since oilfields are universally characterized by heterogeneity, varying physical properties of target horizons, prominent challenges in planar and interformation development and imbalanced recovery of reserves from pay zones, separate-layer injection is preferred for stable oil production and water control and performed to further tap the potential of poor thin oil zones and thick oil zones through interformation and intraformation structural adjustments [13,14]. The interformation structural adjustment enables a balanced production from various oil zones by means of fine water injection of the injector and fine oil production of the producer. The intraformation structural adjustment refers to the subdivision of the existing water injection interval by the relatively stable structural interface into oil zones with different permeabilities, to which water is injected at different rates.

Waterflood oilfields generally experience four development stages: production increase, production plateau, production decline and production at a low rate. Currently, most of the waterflood oilfields are in the last two stages; that is, they are being developed with high water cut (

Table 1. Statistics of Typical High-Water-Cut Oilfields in the World.

Country	Oilfield	Water Cut (%)	Annual Oil Production (106 bbl)	Cumulative Oil Production (106 bbl)	Recovery Percent of OIIP (%)	Recovery Rate (%)	Remaining Recoverable Reserves (106 bbl)	Cut-Off Year
Russia	Romashkino	87.5	120.3	18,348.58	47.3	0.31	4946.4	2018
Russia	Samotlor	98.0	143.76	20,927.5	38.1	0.26	5272.5	2018
USA	Kern River	93.2	17.74	2348.81	58.7	0.44	285.19	2019
Indonesia	Minas	98.7	30.74	4495.26	51.7	0.35	294.74	2008
China	Daqing	95.7	242.5	18250	43.5	0.5	1406	2022

) [15]. These oilfields are characterized by a high recovery percent of OIIP, low average recovery rate and high water cut. Nonetheless, they are still the main oil production bases and strategically irreplaceable now and even for a long time to come, regardless of some challenges in production, return and environment.

The Romashkino Field in West Siberia of Russia has a total of 421 oil pools, involving 22 oil-bearing formation systems (incl. 7 systems of clastic reservoirs and 11 systems of carbonate reservoirs). This typical multi-formation thin oilfield, with an area of about 4300 ${\mathrm{k}\mathrm{m}}^2$, has booked an OIIP of 38,820 million barrels (MMb), recoverable reserves of 23,290 MMb and calibrated recovery efficiency of 59.9% [16]. It was put into production in 1951 and reached its peak output in 1973, with an annual oil production of 673 MMb and an average production rate of 1.746 MMb/d. As of 2018, the field was registered with an annual oil production of 120 MMb, a cumulative oil production of 18,350 MMb, a water cut of 87.5%, a recovery percent of OIIP of 47.3% and a recovery percent of recoverable reserves of 78.8%. The development stages and strategies of the Romashkino Field are shown in

Table 2. Development Stages and Strategies of Romashkino Field.

Stage		Duration	Strategies
I	Production increase	1952–1969	Line cutting flooding: establish and maintain the bottom pressure
II	Production plateau	1970–1975	Pattern flooding: drill reserve wells to expand the development formations
III	Production decline	1976–1994	Cyclic flooding: adjust the well production regime, optimize the injection pressure and flowing pressure and strengthen the development system
IV	Production at low rate	1995–today	Extensive flooding and tertiary oil recovery: promote enhanced oil recovery (EOR) techniques and drill horizontal wells, lateral wells and multilateral wells to tap the potential of non-effective zones

. Early waterflooding was carried out to maintain the reservoir pressure. Initially, following the concept of line cutting flooding, the field was divided into blocks by structural highs, with the injectors employed at structural lows. Under this well pattern with line cutting flooding, only the row of producers closest to the injectors benefited, but the other producers were not swept and featured a sharp pressure drop. The reservoir heterogeneity led to a highly irregular flooding front height, impeding the full penetration of injected water into the lenticular sandstone. In 1968, the number of injectors was increased, the injector–producer spacing was shortened, and the line cutting flooding was converted to pattern flooding. In 1976, the injector–producer ratio was increased to 3:1 by well infilling. For the avoidance of excessive water production, cyclic flooding was adopted; that is, water injection was suspended for 10–30 days to 6–12 months in some well groups or rows, while water injection in other well groups was increased, together with fluid flow diversion to recover the reserves of water-flooded zones as much as possible. This technique enabled the field to achieve an annual oil production of about 40% of the total, with a stable water cut for more than 20 years (except in 1995 when the water production was 75% less than the expectation).

In the development stage with high water cut, various measures could not stop the trend of production decline in the Romashkino Field. The main oil zones were depleted, with the water cut over 90%. The poorly permeable zones had been not or just partially swept by water, suggesting a huge potential for further flooding. Thus, the concept of “secondary development” emerged. It was tested in the Devonian reservoirs in Pavlov to verify its feasibility. The test results show that secondary development can not only increase production and recovery but also achieve good economic benefits. Subsequently, the practice in Pavlov was extended to the entire field. The successful application of secondary development in the Romashkino Field provides five valuable insights [17,18]: (1) a fine geologic reservoir model is built to depict the size and distribution of remaining reserves and describe the variation of oil saturation with time; (2) the well pattern is densified and the production interval is subdivided to optimize the well density and employ more injectors; (3) dynamic waterflooding is performed to periodically change the flow direction of underground fluids; (4) high-water-cut wells with no economic benefits are shut down and water-flooded zones are blocked to restrict the water cut; and (5) new technologies are used to improve the capability of the water processing system so as to improve the quality and volume of injected water.

The Samotlor Field in the Tyumen region, central Siberian Basin of Russia, is one of the supergiant fields in the world. It is a typical uncompartmentalized thin oil accumulation with a gas cap, corresponding to a buried depth of 1500–2500 m, a gas cap height of 78 m and an oil column height of 75 m. The field mainly produces oil from delta sandstone reservoirs (porosity of 21–28% and permeability of 34–1421 mD), where the thin oil is 29–37 °API, the oil-bearing area is 1575 ${\mathrm{k}\mathrm{m}}^2$, the OIIP is 55,000 MMb, the recoverable reserves are 26,200 MMb and the calibrated recovery efficiency is 47.64%. The development stages and strategies of the Samotlor Field are shown in

Table 3. Development Stages and Strategies of Samotlor Field.

Stage		Duration	Strategies
I	Production increase	1969–1977	Line cutting flooding at 800 m and 650 m well spacings
II	Production plateau	1978–1983	Peripheral flooding + line cutting flooding
III	Production decline	1984–1994	Well pattern thickening and other processes
IV	Production at low rate	1995–today	Horizontal well drilling, sidetracking, extended reach drilling (ERD), hydraulic fracturing and improved 3D seismic image acquisition

. The field was put into production in 1969 and reached its peak output in 1980, with a production rate of 3.248 MMb/d and an annual oil production of 1189 MMb. As of 2018, there were a total of 19,000 wells in the field, including 10,000 active producers and 4000 active injectors, with an annual oil production of 143 MMb, a cumulative oil production of 20,930 MMb, a water cut of 98%, a recovery percent of OIIP of 39.8%, a recovery percent of recoverable reserves of 80.8%, a gas production rate of 0.58 billion cubic meters per day (Bcf/d) and a cumulative gas production of 11,585 Bcf. In order to improve the recovery, many solutions were taken in the field, including well infilling, hydraulic fracturing, horizontal well drilling, waterflooding, and CO₂-miscible flooding [19,20].

In order to accelerate the recovery of thick oil zones, and considering the low connectivity between thick and thin sand layers, the well pattern thickening and perforating strategy was implemented in the Samotlor Field in the mid-1980s. The well spacing was reduced to 400–500 m. When the infill wells became low in production and low in efficiency, thin zones were reperforated for production. The implementation effect was significant. In 1992, hydraulic fracturing was started in the field. By 1994, the hydraulic fracturing wells had contributed 6% of the annual production. In the early 21st century, large-scale horizontal well drilling was conducted in the field, which improved the production rate. In 2005, the production rate of each horizontal well was 6250–8100 bbl/d, which was four times that of a conventional vertical well. In the early stage of waterflooding, a row of injectors was arranged between every 3–5 producers and spaced at about 700–800 m. In the 1980s, the rows of injectors were intersected to separate the producers into square blocks, and the flood pattern in the area with poor-quality reservoirs was changed into a seven-spot flood pattern. For reservoirs with gas caps, the “isolated injection” technique was used; that is, peripheral water injection was conducted at the external rim of the gas cap and the anterior limb of the oil ring to prevent oil and gas from lateral migration, which was replaced by later horizontal drilling. In that period, in order to greatly improve the recovery, the injected water volume was much greater than the voided liquid volume, and the reservoir pressure climbed to a level much higher than the saturation pressure. High-intensity exploitation led to low sweep efficiency; highly permeable oil was displaced, while lowly permeable zones and isolated lenses were basically not swept. Injected water also tended to preferentially pass through high-water-saturation formations, bypass high-remaining-oil-saturation formations and break through at producers, thus forming an inefficient and ineffective water circulation, which provided valuable lessons for later waterflooding. In the later stage, CO₂-miscible flooding was tested with satisfactory results: the oil production increased, and the water production remained stable or low. However, there was no natural CO₂ supply in the region, and also due to economic limitations, this technique was not extensively promoted in the Samotlor Field.

The Kern River Field in southern San Joaquin Basin, CA, USA, is dominated by mosaic layer cake sandstone reservoirs, with an average permeability of 2000 mD, which are typical braided river heavy (10–15 °API) oil reservoirs with high viscosity (4000 cp) [21,22]. The OIIP is 40.00 MMb, the recoverable reserves are 2630 MMb and the calibrated recovery efficiency is 65.85%. The field was put into production in 1900 and reached its peak output in 1985, with a production rate of 0.142 MMb/d and an annual oil production of 52 MMb. As of 2019, there were 33,072 wells in the field, including 15,713 producers (9689 active) and 17,359 injectors (8325 active), with an annual oil production of 18 MMb, a cumulative oil production of 2348 MMb, a water cut of 93.6%, a recovery percent of OIIP of 58.7% and a recovery percent of recoverable reserves of 89.2%.

As shown in Figure 3, the Kern River Field has experienced two major development stages. In the first stage (1900–1954), cold recovery was performed, with a calibrated recovery efficiency of 10%. This stage can be subdivided into the production increment period (1900–1902), production plateau period (1903–1911) and production decline period (1912–1954). In the second stage (after 1954), thermal recovery was adopted, and the production rate rapidly increased. At present, thermal recovery contributes 94% of the total production. The Kern River Field is a typical success of heavy oil reservoir development. Due to high oil viscosity and low primary recovery, thermal recovery techniques, such as bottomhole thermal recovery, hot water injection, cyclic steam injection and continuous steam injection (flooding), have promoted the high-yield and efficient development of the field.

Steam flooding, as the most effective EOR technique for low-dip heavy oil reservoirs, began in the Kern River Field in 1964. As of 2008, this technique accounted for 86% of the cumulative steam injection volume. As the steam was injected, the reservoir temperature increased to 212 °F, forming a “steam chamber” (Figure 4) [23]. As the steam chamber expanded, the oil viscosity was reduced, and the oil was forced to the producer. The producer operated continuously until steam breakthrough occurred. Previously, it was believed that the downdip low-temperature part of the reservoir could not be developed through thermal recovery due to the high pressure maintained by the water body, which hindered economic steam injection. An effective solution for this field is to drill water production wells at the downdip part of the producer to reduce the reservoir pressure, thus allowing for new steam injection. This solution has increased oil production by 4000 bbl/d.

The Minas Field in the Minas Highland in central Sumatra Basin, Indonesia, is a wide, NW-trending doubly plunging anticline and includes four isolated oil pools. The oil is light (35 °API), with a high wax content and a low gas–oil ratio (7–100 standard cubic feet/standard tank barrels (SCF/STB). The OIIP is 8700 MMb, the recoverable reserves are about 4790 MMb, and the calibrated recovery efficiency is 55%. The field was put into development in 1952 and reached its peak output in 1971, with a production rate of 0.401 MMb/d and an annual oil production of 146 MMb. As of 2008, there were a total of 1600 wells, including 1300 producers (950 active) and 300 injectors (all active), with an annual oil production of 30 MMb, a cumulative production of 4500 MMb, a water cut of 98.7% and a recovery percent of recoverable reserves of 93.8%. The development stages and strategies of the Minas Field are shown in

Table 4. Development Stages and Strategies of Minas Field.

Stage		Year	Strategies
I	Rapid production increase	1952–1969	Triangular well pattern, local water injection
II	Production plateau	1970–1981	Well infilling, peripheral water injection
III	Production decline	1982–2005	Inverted seven-spot well pattern, waterflooding
IV	Production at low rate	2006–today	Optimized waterflooding process, pilot test of tertiary oil recovery with surfactant and polymer

[24].

Three EOR practices in the Minas Field are worth considering [25]. The first is a fine description of the reservoir and an analysis of the remaining oil characteristics. Since 1993, 3D seismic data have been used to study microstructures, the geostatistical method has been used to draw contour maps of porosity and water saturation, and reservoir simulation technology has been used to optimize well locations. In 2002, high-resolution seismic technology and infill drilling technology were used to achieve more accurate local structural highs, identify remaining oil and gas enriched due to faults and sedimentary facies and define the geometric shape of flow units through fine identification of single sand bodies. The results show that the reservoir has strong heterogeneity; the injected water first passes through the high permeability (1000–4000 mD) unit at the bottom, while the remaining oil stays in the low permeability (20–300 mD) unit at the structural high. The second is the continuous optimization of the waterflooding technique. The initial 24-acre inverted seven-spot well pattern was optimized gradually to the later thirteen-spot well pattern, which effectively ensured the injection–production allocation of pattern flooding in four areas. The third is pilot test of surfactant–polymer flooding. From 1999 to 2002, field tests were conducted on complex surfactant formula and several polymers, which laid a critical foundation for tertiary oil recovery.

The Daqing Oilfield in China is a supergiant multilayer heterogeneous sandstone oilfield, with a length of 145 km from north to south, a width of 10–30 km from east to west, a closed area of about 2800 ${\mathrm{k}\mathrm{m}}^2$, an oil-bearing area of 1489.24 ${\mathrm{k}\mathrm{m}}^2$ and a uniform hydrodynamic system. As shown in Figure 5, since the initiation of development in 1960, the Daqing Oilfield has gone through stages of development test, rapid production increase, production plateau and production decline. Currently, it is in the late development stage with ultra-high water cut. The recovery has improved from 40–45% by secondary oil recovery (e.g., early waterflooding, separate zone production and infill adjustment) to 60–65% by tertiary development (e.g., polymer flooding and ASP flooding) [26,27,28].

Three EOR practices in the Daqing Oilfield are worth considering. First, continuous efforts were made to further understand the oil and water flow behaviors and waterflooding laws in the late development stage with ultra-high water cut, including the research on the micro-filtration mechanism of digital cores, quantitative characterization of microscopic remaining oil and research on actuation mechanism research, and a series of optimization and engineering technologies for waterflooding were developed, including intelligent separate-layer injection equipment, strata-based well pattern optimization and adjustment, efficient treatment of ineffective water circulation and injection optimization. Second, the chemical flooding technique was vigorously developed; low-cost and efficient polymers (incl. novel salt-resisting polymer products) and the supporting technologies suitable for various oil zones were formed; and innovative and efficient ASP flooding technologies, including efficient ASP flooding system and processes and intelligent nano-flooding technology, were developed. Third, research was conducted on multidisciplinary geology–engineering integration, and intelligent reservoir characterization was proposed by integrating reservoir engineering and information technology so that geological engineering can collaborate with closed-loop intelligent reservoir management to improve the production efficiency and development effect.

To sum up, the majority of waterflood oilfields worldwide have successively entered the development stages with (ultra-)high water cut, when the water/power consumption per ton of oil remains unabatedly high. Therefore, it is necessary to establish a mode and technical system of collaboration between oil development and water/power consumption in mature oilfields with (ultra-)high water cut. Here, the oil development and current water/power consumption in a pilot test area of an ultra-high-water-cut oilfield in northeastern China are analyzed; then, the strategies and measures for the collaboration between oil development and water/power consumption are proposed.

2. Oil Development and Water/Power Consumption in a Typical Pilot Test Area

In a waterflood oilfield, as the water cut rises, the recovery percent of oil in place increases, and the recovery rate drops. Although the production declines year by year, the scale of development (number of injectors and producers and surface system) expands continuously. With large-scale water injection, liquid production increases, and accordingly, the water/power consumption grows, mainly in the surface system, injection system and artificial lift system. Currently, the complex surface system has the characteristics of multiple points, wide coverage and long lines.

2.1. Oil Development

Area A, a typical pilot test area of a high-water-cut oilfield in northeastern China, was put into production in 1968, with the basic well pattern constructed. As of 2019, three rounds of well infilling were completed. The current information on Area A is shown in

Table 5. Basic Information on Area A.

Item	Recoverable Reserves (104 t)	Cumulative Oil Production (104 t)	Recovery Percent of Reserves (%)	Annual Oil Production (104 t)	Recovery Rate (%)	Number of Wells	Water Cut (%)
Data	2406.8	1076.4	44.7	22.18	0.37	795	95.55

. The water cut is high. According to liquid production and water cut under different well patterns, 87.28% of injectors show water cut ˃95%, and only 23.70% of producers demonstrate the liquid production ˃40 t. The challenges in development are low and variable producing degrees of reservoirs. According to the water injection profiles, the cumulative producing degree of reservoirs after three rounds of well infilling is only 75.44%; that is, 24.56% of the reservoirs have not been produced. The producing degree of untabulated reservoirs is 68.25% (

Table 6. Producing Status of Class III Reservoirs in Area A.

Development Type		Produced (%)			Unproduced (%)
		Number of Layers	Sandstone	Effective	Number of Layers	Sandstone	Effective
Tabulated reservoirs	≥2 m	84.62	87.11	85.23	15.38	12.89	14.77
	1 m ≤ h < 2 m	86.08	82.6	85.62	13.92	17.4	14.38
	0.5 m ≤ h < 1 m	80.38	80.89	80.28	19.62	19.11	19.72
	0.2 m ≤ h < 0.5 m	75.78	78.21	75.77	24.22	21.79	24.23
Untabulated reservoir		66.56	68.25	/	33.44	31.75	/
Total		72.02	75.44	79.35	27.98	24.56	20.65

). For the purpose of efficient development, it is urgent to carry out accurate geologic research, construct an accurate injection–production model, clarify the potential distribution, optimize water injection and liquid production structures and control the ineffective circulation of injected water.

2.2. Water/Power Consumption

The injection–production and surface processes depend on the factors such as reservoir type, hydrocarbon property, geographic environment and exploitation mode. These facilities are fixed in form, and the combination of process and equipment and the connection of systems are diverse and complex. In high-water-cut oilfields, although the production declines year by year, the scale of production and development expands; water injection volume and liquid production increase with the increase in water cut, and accordingly, the water/power consumption grows continuously. Figure 6 shows the oil production process in Area A, which mainly involves the producer, injector, water source well, metering station, transfer station, dehydrating plant, water disposal plant, water injection plant, crude storage and sewage discharge station. The main products are crude oil and light hydrocarbons, and water and power systems are equipped.

Table 7. Basic Data of Injector, Producer and Surface System in Area A.

Item	Number of Stations/Plants	Number of Producers	Number of Injectors	Annual Fluid Production (104 t)	Annual Oil Production (104 t)	Annual Water Injection (104 t)	Number of Water Pump Set, Average Driving Power (KW), Efficiency (%)
Data	19	487	308	498.62	22.18	553.94	5, 1860, 50.3

shows the basic data of Area A. It can be seen that the annual fluid production is 498.62 $\times {10}^4$ t, and the annual water injection volume is 553.94 $\times {10}^4$ t. All producers and injectors are vertical wells. The producers use conventional beam pumping units. Pipes with a total length of more than 36 km are adopted to cover the oil-bearing area (11.62 ${\mathrm{k}\mathrm{m}}^2$). In the water injection process, the multistage (10–11 stages) centrifugal pump is used for water injection, which works at a 50 Hz frequency and a maximum motor power of 2240 kW. At the time of adjusting the water output flow, a bypass return mode is adopted; that is, a bypass valve is installed at the outlet of the water pump to reduce the outlet flow by opening the bypass valve to return water to the pump suction or water storage tank. Adjusting the pressure mainly relies on adjusting the opening size of the throttle valve in the outlet pipe, as shown in Figure 7. Although this method can finely adjust the output parameters of the water pump, it greatly reduces the overall efficiency of the water pump and consumes excessive electricity. As shown in Figure 8, the total annual power consumption in Area A is 62.62 million kWh—the surface gathering, injection and artificial lift power consumptions are 10.56, 20.84 and 21.51 million kWh, respectively, and the power consumption of the pipe network and other facilities is 9.71 million kWh. Obviously, Area A is an intensive water/power consumer.

3. Technological Strategy and Application Prediction

3.1. Fine Reservoir Analysis and Optimization

In the stage with ultra-high water cut, the highly scattered remaining oil and ineffective water circulation result in huge water/power consumption. Fine reservoir analysis is critical for cost reduction and benefit improvement. Cable-controlled separate-layer injection technology has been implemented in Area A, which realizes real-time monitoring of flow and pressure and real-time adjustment of injection volume of each interval. On the basis of this engineering, combined with real-time separate-layer injection and static reservoir data, fine reservoir analysis and optimization research have been carried out. By means of adjusting the injection volume of a single well or each interval of the well, the injection–production system of the block is optimized to achieve the objective of controlling water, stabilizing oil production and slowing down production decline. The optimization objectives include increasing the oil production and reducing the water cut of the block.

3.1.1. Identify the Stratified Flow between Injector and Producer

Firstly, a geologic model of the block is built, with the permeability field geologic model shown in Figure 9. Then, the automatic identification method of separate-layer injection–production flow relation [28,29] is used to calculate the interwell flow relation of separate-layer injection and production in the block over the years. This method uses data such as reservoir property, distribution and shape of a single sand body, shape and sealing ability of a fault, production performance, water injection and fluid-producing profiles, perforation and stimulation layers of producers and injectors, relative position of producers and injectors and tracer monitoring to conduct automatic identification, with identification principles as follows. (1) There is a connection and flow relation between the injector and producer in the same sand body with appropriate well spacing and well pattern. (2) The injector and producer distributed in different sand bodies are not connected. (3) The injectors or producers drilled in the mudstone area are not connected. (4) The injector and producer shielded by a closed fault or mudstone area are not connected. (5) If the flow path between the injector and producer is too long due to the shape of the sand body, there will be no or weak flow between the injector and producer. (6) Injected water can bypass the barrier to flow under appropriate conditions. (7) A second-line producer in the same direction has difficulty responding. (8) A producer can respond in multiple directions. (9) Under an appropriate angle and well spacing conditions, one injector can allow multiple producers to respond. (10) The injector and producer do not flow when a layer is not in a perforated state at the same time. (11) Streamlines cannot cross. Accordingly, the injection–production flow relation of a layer in Area A is determined (Figure 10).

3.1.2. Quantify Water Injection Response Index of Well Group

The multilayer and multidirectional production splitting technique [30] is used to calculate the liquid production and oil production of a producer in separate zones and different directions. This method strives to accurately use all kinds of production data accumulated in the mature oilfield; fully considers factors such as well pattern distribution characteristics, static reservoir property, reperforating and layer modification measures, fracturing stimulation, injection–production behavior, water injection profile, water-flooded zone logging, pressure build-up/fall, injection–production response and pressure distribution, combined with the calculation results of flow relation between separate-layer injection and production wells; and uses the seepage mechanics theory, reservoir engineering method and reservoir production data to create separate zones and different directions of splitting on the water injection volume of the injector and the liquid production and water cut of the producer.

Based on the production splitting results, taking the injector as the center, the water injection response indices such as the number of response producers around the injector, the volume of liquid and oil expelled by the injector, the injector–producer ratio, water consumption rate, net injection percent, water drive index, instantaneous water injection volume and cumulative water injection volume are quantified. The water consumption rate is taken, for example, to explain the calculation method of the water injection response index, as shown in Equation (1).

$$WC{R}_T=\frac{W_T}{\frac{{{\displaystyle \sum }}_{k=1}^{N_{o,}{}_T}{Q}_{\mathrm{o}}{{}_{,}}_{T,k}}{\rho }{B}_{\mathrm{o}}+{{\displaystyle \sum }}_{k=1}^{N_{\mathrm{o}}{{}_{,}}_T}{Q}_{\mathrm{g},}{}_{T,k}{B}_{\mathrm{g}}}$$

(1)

where WCR is the water consumption rate; W is the cumulative water injection volume, ${\mathrm{m}}^3$; T is 3 grades or the whole wellbore, section and layer; N_O is the total number of oil wells with fluid flow; Q_O is the cumulative oil production driven from the corresponding interval in the kth oil well by water injection in the whole wellbore/section/layer in the injection well, t; $\rho$ is the oil density, $t/{\mathrm{m}}^3$; B_O is the oil volume factor; Q_g is the cumulative volume of dissolved gas driven from the corresponding interval in the kth oil well by water injection in the whole wellbore/section/layer in the injection well, ${\mathrm{m}}^3$; B_g is the gas volume factor; and k is the oil well no.

3.1.3. Evaluate Water Injection Response and Qualitatively Analyze Water Injection Adjustment Direction

The K-means clustering algorithm of machine learning is used to cluster all indices of each injector group, which are classified into 5 categories: very high (very large), high (large), moderate, low (small) and very low (very small). Based on the evaluation results of all indices, a decision tree for the qualitative analysis of water injection adjustment direction is constructed [31] to determine the injectors or intervals for which the injection volume will be increased, decreased or maintained, and the water injection response evaluation for Area A is shown in

Table 8. Water Injection Response Evaluation for Area A.

Well No.	Interval No.	Monthly Water Injection	Monthly Oil Production	Monthly Liquid Production	Water Cut	Injector Thickness	Producer Thickness	Oil Production Intensity	Liquid Production Intensity	Water Consumption Rate	Injection/Production Ratio	Evaluation Results	Injection Decreased/Increased
11	4	High	Very high	Very high	Very low	Moderate	Moderate	Very high	Very high	Moderate	Low	Good	Increased
14	1	Moderate	Very high	Very high	Very high	Moderate	Large	High	High	High	Moderate	Very good	Increased
15	3	Moderate	Moderate	Low	Very low	Small	Small	Very high	High	Moderate	Very high	Good	Increased
17	5	Very low	Low	Very low	Very low	Moderate	Moderate	Very low	Very low	Very high	High	Good	Increased
13	1	High	Moderate	Very high	High	Moderate	Moderate	Low	High	Very high	High	Poor	Decreased
1	6	Very high	Very low	Very high	Very high	Moderate	Moderate	Very high	High	Very low	Low	Poor	Decreased
16	2	High	Moderate	Very high	High	Moderate	Small	Very high	Very high	Very high	Moderate	Poor	Decreased
10	1	Moderate	Low	High	High	Small	Small	Low	Very high	Very high	Very high	Poor	Decreased
6	2	Moderate	Low	Moderate	Very high	Small	Small	Very low	Very high	Very high	Very high	Very poor	Decreased
4	4	High	Low	Moderate	High	Small	Very small	High	Very high	Very low	Very low	Poor	Decreased

.

3.1.4. Optimize Water Injection Plan and Predict Production

The multi-objective particle swarm optimization algorithm is used to conduct intelligent optimization of the injection volume of a single well or each interval [32,33]. On the basis of determining the total injection volume of the block, the water injection adjustment direction of the well group and the adjustment range of the injection volume, aiming at the two optimization objectives such as oil production and water cut of the block, the multi-objective particle swarm optimization algorithm and the niche algorithm are used to optimize the injection volume of a single well or interval with increased or decreased injection; that is, based on indices such as oil production and water cut, the increased injection volume of an increased injection injector or interval and the decreased injection volume of a decreased injection injector or interval are quantitatively optimized, as shown in

Table 9. Data of Increased/Decreased Injection in Area A.

Well No.	Interval No. for Separate-Layer Injection	Injection Decreased/Increased	Volume Increased/Decreased (m3/d)	Proportion Increased/Decreased (%)
11	4	Increased	10.47	49.79
14	1	Increased	9.71	48.95
15	3	Increased	9.38	41.37
17	5	Increased	9.17	47.96
13	1	Decreased	−8.14	−34.85
1	6	Decreased	−8.23	−28.83
16	2	Decreased	−8.82	−37.46
10	1	Decreased	−8.91	−40.23
6	2	Decreased	−9.29	−39.28
4	4	Decreased	−11.52	−34.44

. Based on the optimized injection proration plan, the reservoir simulator is used to predict the oil production and water cut indices of the block, as shown in Figure 11. By means of optimization, it is predicted that under the condition of unchanged injection volume, the annual liquid production is 498.01 $\times {10}^4$ t, and the annual oil production is 24.031 $\times {10}^4$ t.

3.2. Optimization of Artificial Lift System

There are a total of 308 injectors and 392 producers in Area A. Specifically, 24 producers (about 6.12%) exhibit a system efficiency <20%; 42 producers (10.71%) exhibit a daily liquid production <10 t; and the distribution range of dynamic fluid level is relatively wide. As shown in Figure 12, about 43.1% of producers have a dynamic fluid level between 800 m and 1000 m, while about 90% of producers show a pump setting depth between 800 m and 1000 m. The ratio of dynamic fluid level to pump setting depth W is determined as follows:

$$W=\frac{h_{dynamic fluid level}}{h_{pump setting depth}}$$

(2)

In Figure 12, when the producer is at the optimal dynamic fluid level, when the producer is in a state of insufficient feed flow and when W is lower than 40%, the pumping parameter of the producer is low. According to statistics, 98 producers have the optimal W value, accounting for about 25.0%; 260 producers have a W value larger than 70%, accounting for about 63.0%.

In Figure 13, the system efficiency of 14 producers is lower than 20%, belonging to low-efficiency producers; the daily liquid production of 34 producers is lower than 10 t, belonging to low-production wells; and the system efficiency of 6 producers is lower than 20% and their daily liquid production is lower than 10 t, belonging to low-production and low-efficiency producers. Therefore, the low-production and low-efficiency producers have the characteristics of insufficient feed flow, low efficiency and insufficient liquid production.

For 34 low-yield producers with a daily liquid production <10 t in the producers with insufficient feed flow, the intermittent pumping system is proposed for improvement. On the premise of having a minimum influence on production, energy consumption is minimized. According to the relationship among system efficiency, dynamic fluid level and liquid production, a mathematical model for calculating the power-saving rate is built; the unit power consumption, i.e., the relation between the power consumption per ton of liquid and the system efficiency, is shown in Equation (3):

$$W_t=0.272\frac{P_{power}}{P_{effective}}$$

(3)

where W_t is the power consumption of lifting 1t of well fluid 100 m, kWh; P_effective is the effective power of the pumping unit, kW; and P_power is the input power, kW.

The effective power of the pumping unit can be calculated based on the liquid production and dynamic fluid level:

$$N_{effective}=QH\rho g\times 10^3$$

(4)

where Q is the liquid production, m³/d; H is the effective head, m; and ρ is the oil well fluid density, t/m³.

Based on the polished rod indicator diagram, the crank shaft torque can be calculated, and then the consumed work of the motor can be calculated:

$$M=\frac{\left(P-B\right)\times \overline{TF}}{{\eta }_4}-Q_{e}R\mathit{sin}\theta$$

(5)

where P is the motor power; B is the unbalanced value of the pumping unit structure; $\overline{TF}$ is a torque factor or torque factor; η is the system efficiency; and θ is the rotation angle in degrees.

Furthermore, the average daily power consumption during an intermittent pumping cycle can be calculated:

$$P_d=\frac{24}{T_s+T_p}M\left(t\right)$$

(6)

where T_p denotes flowing time, h, and T_s denotes shutdown time, h.

After the producer has been produced using the intermittent pumping system, the power-saving rate can be expressed as:

$${\eta }_{power}=\frac{P_0-P_d}{P_0}\times 100\%$$

(7)

where P₀ denotes the daily power consumption of continuous oil pumping, kWh.

The above mathematical model is used to obtain the power consumption or power-saving rate under the intermittent pumping system, which is then corrected using the field test data to figure out the optimal intermittent pumping system, as shown in Figure 14.

The relational expression between daily power consumption and intermittent pumping time shows that the longer the flowing time and shutdown time, the smaller the daily power consumption; the energy consumption mainly occurs during the flowing time. Therefore, the shorter the flowing time within a cycle, the better the energy savings. In one cycle, it is figured out that the energy-saving effect is better when the ratio of oil pumping time to shutdown time of a single producer is 1:1 and 2:1. Then, the field data are used to compare their power-saving rate, as shown in

Table 10. Comparison of Optimized Power Consumption Data of Low-yield producers.

Time Ratio	Daily Power Consumption of Continuous Pumping (kWh)	Daily Power Consumption of Intermittent Pumping (kWh)	Power-Saving Rate (%)
1:1	81.80	38.74	52.6%
2:1	81.80	25.83	68.4%

.

Table 10 shows that during a cycle of producer pumping, when the ratio of oil pumping time to shutdown time is 2:1, the energy consumption is the smallest, and the power-saving rate can reach 68.4%; meanwhile, the higher the proportion of oil pumping time, the higher the liquid production. Therefore, compared with the ratio of oil pumping time to shutdown time of 1:1, when the ratio of oil pumping time to continuous oil pumping time is 2:1, the impact of the intermittent pumping system on production is smaller. For 87 high-yield producers with a daily liquid production of more than 30 t, this phenomenon of significantly insufficient feed flow but high production is caused by the unreasonable setting of pumping unit parameters, such as excessive stroke or stroke of pumping unit, which not only leads to a serious waste of power energy but also shortens the service life of equipment, resulting in low system efficiency and high energy consumption and ultimately damaging the economic benefits of the enterprise. Therefore, this paper proposes a plan to improve the parameters such as stroke and the number of strokes per minute of the pumping unit. By means of reducing the stroke or number of strokes per minute of the pumping unit, this plan achieves the objective of reducing producer liquid production and controlling appropriate fluid level depth, allows the submergence depth to be kept within a reasonable range, ensures a certain pump efficiency and prolongs the service life of the pumping equipment.

Based on the relationship among system efficiency, lift height, power consumption per ton of liquid per hundred meters, daily liquid production and theoretical displacement, the following mathematical model is established to adjust the stroke and number of strokes per minute of the pumping unit. The relationship between unit power consumption, i.e., power consumption per ton of liquid, and system efficiency is shown in Equation (8).

$$W_t=0.272\frac{P_{power}}{P_{effective}}$$

(8)

where W_t is the power consumption of lifting 1 t of well fluid 100 m, kWh; P_effective is the effective power of the pumping unit, kW; and P_power is the input power, kW.

The average power consumption per ton of liquid per hundred meters is obtained from the average system efficiency, and then the expression for the total input power of the pumping well is:

$$N_{\lambda total}=\frac{Q{H}_{average}{W}_t}{24\times 100}$$

(9)

where $N_{\lambda total}$ denotes total input power, kW; Q denotes liquid production, t/d; $H_{average}$ denotes the weighted average lifting height of liquid production, m; and $W_t$ denotes the average power consumption per ton of liquid per hundred meters, kWh.

The equation for calculating the total power consumption is:

$$W_{total}=Q{H}_{average}{W}_t$$

(10)

The pump efficiency of the pumping well is:

$${\eta }_{efficiency}=\frac{Q_{actual}}{Q_{theoritical}}$$

(11)

$$Q_{theoritical}=1.1304\times 10^{-3}\times S\times N\times D^2$$

(12)

where Q_actual is the actual liquid production, m³/d; Q_theoretical is the theoretical liquid production, m³/d; S denotes stroke, m; N is the number of strokes per minute, times/minute; and D denotes pump diameter, mm.

The stroke and number of strokes per minute of the pumping unit are adjusted under the condition of unchanged pump efficiency. Based on reasoning, when the theoretical displacement decreases, the pump efficiency remains unchanged, the actual liquid production decreases, and the input power of the pumping well also decreases accordingly. The optimized power consumption data of the high-yield producers are figured out, as shown in

Table 11. Power Consumption of High-Yield Producers before and after Optimization.

	Stroke	Number of Strokes per Minute	Daily Liquid Production (t)	Daily Power Consumption of Continuous Pumping (kWh)
Before optimization	3.43	5.51	45.36	216.71
After optimization	3.00	4.2	29.10	208.50

.

Table 11 shows that after having reduced the stroke and number of strokes per minute of the pumping unit, the daily liquid production of the producers is reduced, and the daily power consumption of continuous pumping is reduced, with a power-saving rate of 3.79%. Reducing the daily liquid production to a reasonable range can prolong the service life of the pumping equipment and improve the economic benefit.

Based on the basic data of optimization analysis of reservoirs in the block, the annual liquid production is expected to be 439.3 $\times {10}^4$ t, the power consumption of artificial lift is expected to be 0.2222 $\times {10}^8$ kWh, and this is optimized by taking the highest power-saving rate as the objective. The basic idea of the intermittent pumping system proposed for low-yield producers is to transform the production regime of the pumping unit from a continuous production regime to a discontinuous oil pumping system that reasonably allocates oil pumping time and shutdown time within a cycle. This method minimizes the impact on liquid production. The optimization method for adjusting parameters downwards proposed for high-production wells with insufficient feed flow aims to reduce the liquid production to meet the requirements of the well with insufficient feed flow while ensuring minimum impact on pump efficiency. Therefore, the intermittent pumping system can be used to conduct optimization on the whole of Area A. When the annual liquid production is not changed, the ratio of oil pumping time to shutdown time of 2:1 within a cycle is selected as the optimization method, and the power consumption of artificial lift is expected to be 0.1469 $\times {10}^8$ kWh, as shown in

Table 12. Power Consumption of Artificial Lift System before and after Optimization.

	Annual Liquid Production (104 t)	Power Consumption (108 kWh)
Before optimization	439.3	0.2222
After optimization	439.3	0.1469

.

3.3. Optimization of Surface Gathering System

The surface gathering system undertakes the transportation of surface fluids and is also the core link of energy consumption. The energy consumption loss in this link includes efficiency loss of the electric water pump, pressure difference loss of the pump pipe, pressure drop loss of the pipe network and pressure difference loss of pipe casing. Under normal conditions, the efficiency loss of the electric water pump and the pressure drop loss of the pipe network are necessary idle work, while the pressure difference loss of the pump pipe and the pressure difference loss of pipe casing are wasteful idle work. The energy saving of the water injection system must start with reducing the pressure difference of the pump pipe and the pressure difference of the pipe casing. The main technological strategies are as follows: one is to optimize the system’s pumping and parameter adjustment, and the other is to conduct transformation on hardware facilities such as the pump and pipe network. The practices of many years show that the first strategy is suitable for reducing the pressure difference of the pump pipe, and the unit power consumption of the pump can generally be reduced by about 0.05–0.15 $\mathrm{k}\mathrm{W}\mathrm{h}/{\mathrm{m}}^3$; the second strategy is suitable for improving the distribution of the pressure difference of pipe casing, and the unit power consumption of the pump can generally be reduced by about 0.2–0.5 $\mathrm{k}\mathrm{W}\mathrm{h}/{\mathrm{m}}^3$.

In the water injection system of Area A, the efficiency loss of the electric water pump and the pressure drop loss of the pipe network account for 22.8% of the energy loss, while the pressure difference loss of the pump pipe and pipe casing account for 19.9% of the energy loss; the available work of injected water volume and pressure at the wellhead only accounts for 57.3% of the total energy, and nearly half of the energy has been wasted. The distribution of injection proration pressure of injectors in Area A is shown in Figure 15. In the water injection system, the pressure of injectors is high only in a portion of the upper right corner and on the left and right edges (pink in color), basically between 12.0 MPa and 13.5 MPa, and between 13.5 MPa and 15.0 MPa in a few wells, while the pressure of injectors is below 12.0 MPa in other areas, or even below 10 MPa, indicating that the distribution of the injection proration pressure of injectors in the block is extremely uneven. The average pump pressure of the whole system is 16.6 MPa, the average pressure difference of pump pipe is 0.5 MPa, and the average pressure difference of pipe casing comes to 3.6 MPa.

An analysis shows that in order to meet the demand of a few injectors with high injection proration pressure, the overall working pressure of the system must be improved, and the severe throttling loss of the wellhead is the main reason for the high energy consumption of the water injection system. The energy-saving potential is not large only by the optimization of the operating plan, and how to reduce the throttling loss of the wellhead is the main issue that needs to be considered. Based on the pressure distribution of the water injection system, the second technological strategy is used to conduct differential pressure and depressurizing adjustment. As shown in Figure 16, after optimization calculation and analysis, the whole pipe network is divided into two parts: high-pressure area and low-pressure area. The larger part on the left is the low-pressure area, and the smaller part in the upper right corner is the high-pressure area. In the low-pressure area, the water pump is downgraded to achieve overall pressure reduction, thus reducing the pressure difference of pipe casing; in the high-pressure area, measures such as pre-variable frequency transformation are taken to reduce the pressure difference of the pump pipe. After implementation of the measures, the average pump pressure is reduced by 0.69 MPa, the average pipe pressure is reduced by 0.79 MPa, and the unit power consumption of the pump is reduced by 0.27 $\mathrm{k}\mathrm{W}\mathrm{h}/{\mathrm{m}}^3$, having a good energy-saving effect.

In summary, for Area A where the water cut is up to 95.55%, by means of fine reservoir analysis, development plan optimization, parameter adjustment optimization of the artificial lift system and reasonable matching optimization of the surface pipe network, the production indices are improved to some extent. As shown in

Table 13. Development Indices of Area A before and after Optimization.

Item	Conventional Production	Optimization of Development Plan	Optimization of Development Plan + Artificial Lift System	Optimization of Development Plan + Artificial Lift System + Surface System	Difference
Annual liquid production (104 t)	498.62	498.01	498.01	498.01	0.61
Annual oil production (104 t)	22.17	24.03	24.03	24.03	+1.86
Annual water injection (104 t)	553.94	553.94	553.94	553.94	0
Annual power consumption (108 kWh)	0.6262	0.6259	0.558	0.543	832
Water consumption per ton of oil	24.98	23.05	23.05	23.05	1.93
Power consumption per ton of oil (kWh)	282.5	260.4	232.2	226	56.5

, the water consumption per ton of oil is reduced from 24.98 t to 23.05 t, reduced by 1.93 t, and the power consumption per ton of oil is reduced from 282.5 kWh to 226 kWh, reduced by 56.5 kWh. The fine reservoir analysis and development plan optimization effectively improve the water consumption index per ton of oil, contributing to the power consumption per ton of oil but not significantly; the artificial lift optimization and surface gathering system optimization significantly improve the power consumption per ton of oil; and under the conditions of low production and low-efficiency development, the artificial lift optimization significantly improves the energy-saving effect and is the main direction of the research.

4. Measures for Collaboration

Water/power consumption occurs in all oilfield operations, including drilling exploration, wellbore cleaning, hydraulic fracturing, waterflooding and petrochemical processing; thus, oil development and utilization are closely related to water/power consumption. This paper mainly focuses on the consumption of water/power consumption in the development of high-water-cut oilfields. The increase in water cut leads to the increase in water injection volume, liquid production and the exponential increase in the cost of water circulation. In order to achieve the friendly and collaboration of crude oil resources and water/power consumption of waterflooding high-water-cut oilfields, full-chain innovative research needs to be carried out from the aspects of development mode, key water-saving production technology, development scale and new energy utilization. The specific suggestions are as follows:

• When an oilfield is in the late stage of “high recovery percent of reserves and high water cut” as a whole, the problem of inefficient and ineffective water circulation is prominent, which is the fundamental cause of high water/power consumption of the oilfield. After the waterflood oilfield has entered the high-water-cut stage, the remaining oil gradually presents a distribution characteristic of overall high dispersion and local relative concentration, which puts forward higher requirements for the accuracy and efficiency of structural research, reservoir description and remaining oil characterization. It is necessary to carry out dynamic optimization technology research of fine intelligent reservoir and engineering integration, quantify separate-layer injection and production, quantify separate zone producing, quantify single-layer remaining oil and microfacies remaining oil and realize the effective tapping of remaining oil by means of real-time injection–production interval adjustment so as to control the ineffective water circulation while ensuring furthest production.
• The energy-saving equipment and technologies, such as variable-frequency speed control technology of the water pump, vector control technology of on-load startup and dynamic fluid-level-based intelligent intermittent pumping technology, should be vigorously developed. The variable-frequency speed control technology of the water pump can meet the requirements of water injection under variable working conditions; the on-load startup vector control technology of the water pump completely eliminates the backflow during the startup of the pump, realizing the pressurized start of the pump; and they all reduce the energy consumption of the water pump. For low-production and low-efficiency wells in China, the intelligent intermittent pumping technology not only improves the pump efficiency and system efficiency but also avoids the power consumption peak, largely reducing the power energy consumption and costs.
• Surface works should be optimized and arranged reasonably. The location optimization of surface systems in high-water-cut oilfields is an important measure to improve system efficiency. The location and scale of the surface system should be optimized and adjusted based on development prediction to minimize the number and scale of new stations to the greatest extent; meanwhile, the oil gathering and surface injection process should be simplified, and the complex oil gathering process and conventional water allocating station should be canceled. Having fewer oil-gathering and water injection branch lines can effectively reduce the operating load and power consumption of the surface system.
• A new mode of intelligent multi-energy complementary exploitation of oilfields should be promoted. The fusion technology of new energy such as wind energy, solar energy and geothermal energy with the traditional oil business should be actively developed; that is, combined with the power generation characteristics of photovoltaic cells and wind turbines, taking grid power as the basic guarantee, the key technologies and supporting equipment such as intelligent dispatching of integrated energy, multi-energy fusion intelligent production and flexible control and the dynamic prediction and collaborative production of energy supply/consumption under the dynamic loads of oil and gas production should be tackled, the interactive response and complementation of a variety of energy resources should be realized, the consumption of new energy in high proportion should be promoted, and a new mode of comprehensive development and application of new energy should be formed.
• An advanced intelligent oilfield production management system should be established. The oil reservoir, water injection, surface gathering, wastewater treatment and power system models should be built. Then, the simulated development environment can be used to integrate the oilfield production models into one. Finally, in the virtual oilfield production system, functions such as statistics, predictive analysis and process optimization scheduling of water/power consumption should be realized so as to reduce production failures at the same time of scientifically utilizing water/power consumption.

5. Conclusions

Taking a pilot test area of an ultra-high-water-cut oilfield in northeastern China as an example, a mode and technical system for the collaboration between oil development and water/power consumption in (ultra-)high-water-cut oilfields are investigated and established. The development status of the pilot test area is that the remaining oil is highly scattered, ineffective water circulation is severe, and the power consumption of artificial lift and water injection is huge, which seriously affect economic benefits. Optimization is conducted from the following three aspects.

Accurate reservoir analysis and optimization: The automatic identification method of the separate-layer injection–production flow relation is used to calculate the flow relation between separate-layer injection and production wells in the block over the years; the multilayer and multidirectional production splitting technology is used to calculate the liquid production and oil production of separate zones in different directions; the K-means clustering algorithm of machine learning is used to conduct clustering qualitative analysis on all water injection response indices of each injector group, thus discriminating which injectors or intervals need to increase, decrease or maintain the water injection volume and obtaining a water injection response evaluation table of single intervals in single wells; and, finally, the multi-objective particle swarm optimization algorithm is used to conduct intelligent optimization of the injection volume of a single well or each interval. Diverse and plentiful data are necessary to ensure the accuracy of the algorithm. The timeliness of the swarm optimization algorithm, which takes a certain time for iterative optimization search, can be affected by computing hardware.

Optimization of artificial lift system: The intermittent pumping system proposed for low-yield producers is to transform the production regime of the pumping unit from a continuous production regime to a discontinuous oil pumping system that reasonably allocates oil pumping time and shutdown time within a cycle, which minimizes the impact on liquid production; the optimization method for adjusting parameters downwards proposed for high-production wells with insufficient feed flow aims to reduce the liquid production to meet the requirements of a well with insufficient feed flow while ensuring minimum impact on pump efficiency. The intermittent pumping system is used to conduct optimization on the whole test area. When the annual liquid production is not changed, the ratio of oil pumping time to shutdown time of 2:1 within a cycle is selected as the optimization method, and the power consumption of artificial lift is expected to be 0.1469 $\times {10}^8$ kWh, with a power-saving ratio of 31%. It is essential to consider the impact of simultaneous start/stop pumping wells on the power grid and the life of the motor.

The optimization of the surface gathering system: The energy saving of the water injection system must start by reducing the pressure difference of the pump pipe and the pressure difference of pipe casing, with two technological strategies mainly as follows. One is to optimize the system’s pumping and parameter adjustment, and the other is to conduct transformation on hardware facilities such as the pump and pipe network. In order to meet the demand of a few injectors with high injection pressure, the overall working pressure of the system must be improved, and the severe throttling loss of wellhead is the main reason for the high energy consumption of the water injection system. Based on the pressure distribution of the water injection system, the second technological strategy is used to conduct differential pressure and depressurizing adjustment. The whole pipe network is divided into two parts: low-pressure area and high-pressure area. In the low-pressure area, the water pump is downgraded to achieve overall pressure reduction, thus reducing the pressure difference of pipe casing; in the high-pressure area, measures such as pre-variable frequency transformation are taken to reduce the pressure difference of the pump pipe. After implementation of the measures, the average pump pressure is reduced by 0.69 MPa, the average pipe pressure is reduced by 0.79 MPa, and the unit power consumption of the pump is reduced by 0.27 $\mathrm{k}\mathrm{W}\mathrm{h}/{\mathrm{m}}^3$, having a good energy-saving effect.

By means of fine reservoir analysis, optimization of the development plan, optimization of the artificial lift system and optimization of the surface gathering system, the production indices are improved to some extent: the water consumption per ton of oil is reduced from 24.98 t to 23.05 t, reduced by 1.93 t, and the power consumption per ton of oil is reduced from 282.5 kWh to 226 kWh, reduced by 56.5 kWh. The fine reservoir analysis and development plan optimization effectively improve the water consumption index per ton of oil, contributing to the power consumption per ton of oil but not significantly; the artificial lift optimization and surface gathering system optimization significantly improve the power consumption per ton of oil; under the conditions of low production and low-efficiency development, the artificial lift optimization significantly improves the energy-saving effect and is the main direction of the research.

Measures for collaboration are put forward: it is necessary to (1) carry out dynamic optimization technology research of fine intelligent reservoir and engineering integration; (2) vigorously develop energy-saving equipment and technologies; (3) optimize and reasonably arrange surface works; (4) promote a new mode of intelligent multi-energy complementary exploitation of oilfields; and (5) establish an advanced intelligent oilfield production management system.