The Chang 6 and Chang 8 members in the ultra-low permeability reservoirs of the Ordos Basin are characterized by tight lithology, fine pore throats, poor physical properties, and relatively developed micro-fractures^[1,2,3,4,5]. It's difficult to obtain good production stimulation effect by conventional vertical well fracturing. Experiences in China and abroad and related research prove that the multi-cluster staged-fracturing in horizontal well can form a complex fracture network with main and branch fractures intertwined^[6], and thus significantly increase reservoir drainage volume and single-well production^[7,8,9,10]. The initial output of a horizontal well can reach 8 to 10 t/d, which is 4 to 5 times that of a vertical well^[11]. However, with the production going on, the development with horizontal wells has also exposed some problems: (1) Some reservoirs are developed by five-point water injection horizontal well pattern (with water injected in vertical wells, oil produced from horizontal wells), and the space between injection and production wells is about 150 m (the vertical distance from the water injection vertical well to the heel or toe of the horizontal well), but fine description of single sand bodies shows that most sand bodies are 50 to 110 m across and the primary well pattern is not suitable in some reservoirs, making it impossible to establish effective displacement systems. (2) Due to the particularity of horizontal wells, the area between the middle fractures in the horizontal section of the production well is difficult to have water injected because of the shielding effect of adjacent fractures, and is mainly driven by elastic dissolved gas. (3) Some horizontal wells produced under natural energy, without effective energy replenishment, and thus had fast production decline. Through the production fluid profile test, it is found that not all fractures contribute to production capacity. According to statistics, perforation clusters that do not contribute to production capacity account for about 30% on average^[12,13].

How to effectively supplement formation energy and achieve effective water flooding in the area controlled by horizontal wells has become a major problem in the development of ultra-low permeability sandstone reservoirs. Literature review and field experience show that technologies to keep horizontal well production stable include conventional “point injection line production” stable water injection, cyclic horizontal well water injection, unstable water injection, horizontal well repeated fracturing, horizontal well temporary blocking and diverted re-fracturing. "Point injection line production" stable water injection is currently a conventional water injection mode, but its displacement distance is long, and it is difficult for fractures in the middle of the horizontal section to have response. Cyclic water injection in horizontal well and instable water injection can form instable pressure field to enhance sweeping coefficient and oil displacement efficiency, but the effect gradually deteriorates after multiple cycles. Repeated fracturing of horizontal wells can increase the stimulated volume and supplement formation energy to make it increase by 10% to 30%, but the validity period is short (6-9 months).

Injection and production in the same well was first applied to high water cut oil wells in offshore oilfields^[14,15,16]. So far, there is no report on simultaneous injection and production tests in horizontal wells in ultra-low permeability reservoirs. Cheng et al.^[17], Yu et al.^[18] studied the feasibility of injection and production in the multi-fractured horizontal well in tight reservoir, and studied the development effects of different displacement media and development mode through numerical simulation, and suggested that injection and production in the same well has the advantages of high production, long stable production period, and high recovery degree.

In light of the problems in the development of ultra-low permeability reservoirs and the shortcomings of the current technologies to keep stable production of horizontal wells, simultaneous injection-production to supplement energy in horizontal well in ultra-low permeability reservoir was proposed. In this study, its advantages and feasibility were analyzed, its injection and production parameters were optimized and it was used in the field.

In simultaneous injection and production in horizontal well, packers, sealing cannula and other tools are used to realize water injection in some fractures and oil production from other fractures in the same horizontal well. Its working principle is to select one or several fractures as fluid injection channels; by combining the tubing and casing separate injection technology and sectioned isolation technology, the injection fractures are separated from the adjacent oil production fractures in the horizontal section of a horizontal well; the injected fluid enters the designated fractures from the annulus between the tubing and casing to drive oil, while crude oil flows into the production fractures behind the packer and then the tubing for production. This way, a sectioned simultaneous injection and production system is built in the same horizontal well (Fig. 1). Simultaneous injection and production in the same horizontal well comes in several forms, including single-section injection and multi-section production, and multi-section injection and multi-section production, etc. In single-section injection and multi-section production (injection section by section in the same well), water is injected through the perforations at the heel and oil is produced from the perforations towards the toe of the horizontal section; after the oil production section is water flooded, the sealing point would be moved towards the toe step by step until all perforation sections are completely water flooded. In multi-section injection and multi-section production, water injection sections and oil production sections alternate with each other, and multiple sections are displaced simultaneously. This mode features large sweeping range of water and quick response.

Theoretically, the simultaneous injection and production can change the past point water injection to linear water injection, and the traditional cross-well flooding to the intersegment displacement in horizontal wells. Under the same water injection volume, the water injection pressure would be lower, which is good for preventing secondary opening of natural cracks during water injection and reducing the risk of fracture water out. At the same time, the technique can turn the area between the artificial cracks from elastic dissolved gas drive to water drive.

In this study, ECLIPSE numerical simulation software was used to build a model based on the actual block data. The model geometry was 700 m×1300 m×10 m, and had a plane grid step of 10 m and a longitudinal grid step of 1 m, a reservoir porosity of 16%, horizontal permeability of 0.79×10^-3 μm², vertical permeability of 0.07×10^-3 μm², original oil saturation of 57%, and initial formation pressure of 19 MPa. The model had a five-point horizontal well injection pattern with row spacing of 130 m. The horizontal wells have horizontal section of 900 m long. Spindle-shaped fractures were distributed along the horizontal section of the wells. The fractures at two ends of the horizontal section were 75 m in half length and the fractures in the middle are 200 m in half length with 10 fracturing sections at the spacing of 90 m. The width of the fracture network took the step size of the plane grid (10 m), and the permeability of 200×10^-3 μm². In line with the actual production conditions, the production was controlled by liquid production (30 m³/d) and bottom hole flowing pressure (10 MPa). The flowing pressure was controlled above the bubble point pressure (8 MPa). The pressure gradients (Fig. 2) and pressure field distribution (Fig. 3) at the end of 2 years of production under the development mode of five-point horizontal well pattern injection and production and odd numbered section injection and even numbered section production in the same horizontal well were simulated. The results show that the formation pressure gradient is negatively correlated with the distance from the water injection well (fracture). The longer the distance, the smaller the pressure gradient, the smaller the difference between the pressure gradient and the starting pressure gradient, and the weaker the drive capacity of the injected water is. When vertical water injection well is adopted, local high pressure is likely to occur around the water injection well, while the pressure around the oil production well maintains a relatively low level. In contrast, the injection and production between sections is linear injection and production, the injection fluid seepage cross-sectional area is large, the injection and production distance is small, and higher pressure gradient can be created between the injection fractures and oil production fractures, which is conducive to improving the driving capacity of the injected water and achieving effective displacement.

The above model was used to simulate the cumulative oil production under different development modes. Fig. 4 shows the changes in cumulative oil production for 20 years under four development modes: (1) depletion development (vertical well shut-in, horizontal well production); (2) five-point well pattern water injection (vertical well water injection, horizontal well production); (3) horizontal well odd numbered section injection and even numbered section production (vertical well shut-in, horizontal well injection-production); (4) stage-by- stage injection and production in the same well (vertical well shut-in, horizontal well injection-production). It can be seen that depletion development has the worst development effect because there is no energy supplement. Horizontal well simultaneous injection and production mode has timely energy replenishment and better development results. Among them, the odd numbered section injection and even numbered section production mode has better effect than the stage-by-stage injection-production. Fig. 5 shows the distributions of oil saturation at the end of 20 years of production under the development modes of five-point well pattern and odd numbered section injection and even numbered section production. It can be seen from the figure that in the development by five-point well pattern, the injected water slowly and radially advanced from the injection well, the injected water didn’t reach the horizontal production well at the end of 20 years, and the displacement scope and swept area are limited around the injection well. In contrast, in the odd numbered section injection and even numbered section production mode, the injected water first entered the injection fractures, and advanced from the injection fractures linearly to the production fractures, to realize linear displacement between the fractures.

In the section-by-section injection and production mode, the injection water couldn’t effectively displace the crude oil in the remote fractures, and the effective displacement range is small, so the cumulative oil production by this mode at the end of 20 years was lower than that by the odd numbered section injection and even numbered section production mode.

The micro-seismic interpretation results of volume fracturing and conventional fracturing show that artificial fractures are basically in the same direction as the main in-situ stress, and the fracture networks are basically distributed in strip shape (with different length and width). Micro-seismic monitoring was done two times in Well A239-24 of Jiyuan Chang 7 reservoir. The interpretation results are shown in Table 1. It can be seen that the artificial fracture networks are 64-85 m, and the fractures extend northeast 82°-84°. But the numerical simulation inversion results of artificial fractured reservoir show that artificial fracture network is no more than 10 m in effective width^[19], which has a large error from the actual data measured on site. Well AP inspection 239-24 is a horizontal inspection well, located about 80 m east of Well A239-24, and has a designed horizontal section of 85 m striking 7° northwest (Fig. 6). During the drilling process, conventional coring was performed on the entire horizontal section (with core length of 85 m). Only three suspected artificial fractures were observed in the core section, which were distributed in a core section of 1 m long (located near the intersection of the horizontal section and the A239-24 artificial fracture), but no obvious fracturing proppant was seen, and the width of the fracturing network was limited, which is in agreement with the numerical simulation inversion results that the fracturing network width is no more than 10 m. Therefore, the effective width of the fracturing network is smaller than the space between multiple fracturing sections of horizontal well, and the channeling risk in simultaneous injection and production is basically controllable.

The horizontal section of Well AP122 in the Chang 7 Formation of Jiyuan reservoir is 800 m long. In June 2017, a repeated fracturing test of odd numbered section injection and even numbered section production was made to supplement energy. The fracturing had 10 sections and a space between two segments of 70 to 80 m. A total of 6000 m³ of fracturing fluid was injected, with 1200 m³ for each odd numbered section. The pressure of the reservoir near the fracture zone increased by 2 to 4 MPa through re-fracturing without proppant, the formation energy was effectively replenished, and no channeling occurred in non-fractured sections of the well.

Coring in horizontal wells and repeated fracturing results show that the width of artificial fracture network is limited, so in the process of simultaneous injection and production, the channeling risk between fractures, and risk between fractures and adjacent wells is small.

The main stress direction of the Changqing ultra-low permeability reservoir is about 75° north by east, which is consistent with the direction of sand body distribution. The horizontal section of wells in the main reservoir is perpendicular to the long axis direction of the sand body. Geological studies and fine characterization of sand bodies indicate that most sand bodies in the reservoirs developed with horizontal wells are small in scale and have a width of 50 to 110 m (Fig. 7). The field data statistics show that the row space of five-point water injection horizontal well pattern in ultra-low permeability reservoirs is basically 100-180 m (Fig. 8), indicating that the well patterns are not suitable in some ultra-low permeability reservoirs and can hardly control the geological reserves and establish an effective displacement system.

A natural fracture (with a permeability of 200×10^-3 μm²) was added between the water injection fracture and oil recovery fracture in the above geological model to simulate the effect of natural fracture on the simultaneous injection and production in horizontal wells (Fig. 9). It can be seen that when there is a natural open crack between the water injection section and the oil production section, the crack would be- come a water channeling path, and cause water-out of the oil production segment in a short time.

According to the distribution scale of single sand body and the influence of natural fracture, the water injection section of the horizontal well should choose the oil layer with natural fracture consistent with artificial fracture in direction or the oil layer with no natural fracture. Meanwhile, based on the results of repeated fracturing test and micro seismic interpretation of horizontal well AP122, the reasonable space between simultaneous injection and production sections should be 60-80 m.

Ultra-low-permeability sandstone reservoirs have abundant micro-fractures. Fractures are the main flowing channels for oil and gas in low-permeability reservoirs, and they play "dual" roles in water flooding^[20]: (1) The existence of fractures improves the flow capacity of low-permeability reservoirs; (2) the existence of natural fractures exacerbates the heterogeneity of low-permeability reservoirs, especially when the water injection pressure exceeds the fracture opening pressure, the natural fractures would open and grow, consequently, injection water would flow quickly along the fractures, causing premature water breakthrough or water-out of oil well^[21]. Therefore, the biggest difficulty of simultaneous injection and production in horizontal well is to determine the reasonable water injection pressure to avoid large-scale opening of natural fractures due to high water injection pressure.

3.2.1. Reasonable injection pressure

A number of theoretical formulas are available to calculate the crack opening pressure, but they need many parameters, and some parameters are difficult to obtain. There is a large amount of continuous production data such as output and pressure, as well as dynamic and static monitoring data available, so judging whether the crack is open from field data has some advantages. The injection pressure corresponding to the inflection point of the water injection indication curve of the injection well is the natural fracture opening pressure or formation breakdown pressure. The formation breakdown pressure can also be determined based on the highest pressure on the fracturing operation curve when the horizontal well is put into production. The injection pressure for simultaneous injection and production can be determined comprehensively by using the water absorption indication curve, the fracturing operation curve and dynamic data of the horizontal well.

3.2.2. Reasonable daily water injection

When there is abundant production data, reasonable daily water injection can be worked out based on the dynamic data. Table 2 shows the production data of water injection wells in three ultra-low permeability blocks. These blocks currently have stable production and good development effect. For example, the reservoir in Well GP8 of Block Z211 has a permeability of 0.23×10^-3 μm², the average daily water injection rate of the well is 10 m³, and the water injection took effect after 10 months (the average time of water injection response of the block is 15 months). The average daily oil production of the well during the steady production period is more than 6 t, and the well has remained stable production for 5 years. By comparing the main physical property parameters of ultra-low permeability reservoirs with developed and effective blocks, the reasonable daily water injection volume of undeveloped blocks can be determined.

In addition, based on the physical properties of the reservoir, and drawing on mature experience in horizontal well injection proration in developed blocks, by using reservoir numerical simulation methods, a single-well model can be established to optimize water injection parameters and work out daily water injection rate of the simultaneous injection and production in horizontal well in ultra-low permeability sandstone reservoir.

3.2.3. Rational proration

Statistical method of field data can be used to determine the reasonable output. Table 3 summarizes the production conditions of the horizontal wells in the Z211, Y284, and M30 blocks of the Changqing ultra-low permeability sandstone reservoir. It can be seen that the average daily oil production per horizontal section of the horizontal wells basically stabilizes at 0.50 to 0.55 t. Proration of horizontal wells in the ultra-low permeability sandstone reservoir can refer to this data, and is converted according to the number of sections of the horizontal well. The proration can be adjusted in real time according to dynamic parameters such as gas production and water cut.

The horizontal well simultaneous injection and production system consists of a down-hole pipe string and a surface intelligent blowout prevention system. The down-hole pipe string consists of Y445 packer, oil pump, tubing anchor, centralizer, and screen plug (Fig. 10). The pipe string has a designed maximum injection-production pressure difference of 50 MPa. It has been proved by lab tests that the packer and sealing cannula can remain in good sealing condition under 120 °C and 50 MPa pressure difference.

The wellhead intelligent blowout preventer is composed of a sucker rod blowout preventer, hydraulic control valve, matching packing box, sampling port, hydraulic control system and control cabinet, which enables wellhead intelligent blowout prevention. In other words, when the wellhead pressure exceeds 4 MPa, the system automatically stop injection, stop pumping, close blowout preventer and send out alarm.

Two wells, MP93 in block M30, and CP14-01 in block Y284 with abundant microfractures, were selected for testing.

Well MP93 with a 930 m long horizontal section was fractured in 12 stages at the stage space of 70 m before put into production. In the initial stage, the block was developed by five-point water injection as shown in Fig. 11. The well basically stopped production because of high water production one year before the test (Fig. 12).

Geological studies show that Well M93 has abundant natural fractures, and the water-out of this well is related to the formation of high permeability channels formed by natural fractures. The liquid production profile test results (Fig. 13) show that most of the liquid production (67.6% of the total) is mainly contributed by the artificial fracture ① at the heel. Combined with analysis of injection-production well pattern, the rapid rise of water cut is largely related to two water injection wells, M110-3 and M110-4 (Fig. 11). In order to ensure the effect of simultaneous injection and production test, chemical profile control and water plugging operation was performed on the artificial fracture ① at the heel of the well before the test.

Before the test, the parameters such as formation breakdown pressure, water injection volume, and daily oil production of the well were collected first. According to the formation breakdown pressure and water absorption curve of the perforation section in this well (Table 4), it can be seen that the inflection point pressure of the water absorption curve is 10.5 MPa, and the wellhead water injection pressure calculated is mainly between 10.0 MPa and 24.0 MPa. Therefore, the wellhead water injection pressure of 10 MPa was taken for this well to avoid the risk of open of natural fractures due to high water injection pressure. The daily water injection rate of 10 m³ was taken for this well according to reservoir numerical simulation. According to statistics on average single-section production after water injection response, the daily oil production of the well was determined at 3.52 t.

On September 27, 2018, the artificial fracture sections ① to ③ in this well were isolated. On October 10, 2018, the simultaneous injection-production test was started section by section. After the water injection, the well witnessed rise of fluid production and oil production, and the effect of inter-section displacement appeared initially (Fig. 12). But 5 d later, the well had an increase of water injection pressure and water cut. The produced water had a salinity of 3200 mg/L. It was inferred through analysis that the water injection pressure was too high and caused the opening of micro-cracks, and there was a risk of water channeling. Then the well was produced under controlled water injection pressure, with production basically stable. The well was flooded at the end of April, 2019. It is concluded from analysis that as the water injection main valve controlled water distribution to multiple injection wells, the water injection pressure fluctuated greatly, which led to the opening of natural fractures in the formation and water channeling in this well. The well had an oil increment of 430 t before water-out.

Well CP14-01 has a horizontal section of 740 m long, and was fractured in 8 sections at the section space of 65 m before put into production. From the formation breakdown pressure and water absorption curve of the perforation section of this well (Table 5), it can be seen that the pressure at the inflection point of the water absorption curve is 12.0 MPa, and the converted wellhead water injection pressure is mainly between 10.0 and 24.0 MPa, so the water injection pressure of 10.0 MPa was taken for this well. Through reservoir numerical simulation, the daily water injection rate of 10 m³ was selected for this well. According to statistics on average single-section production after water injection response, the daily oil production of this well was determined to be 2.55 t.

The artificial fracture ① section at the heel was selected as water injection section to conduct the injection-production test in the same well section by section. In order to avoid the increase of water injection pressure as water injection going on, long exposure of fracture to high water injection pressure, and opening and growth of natural fractures in the formation, cyclic water injection was adopted in the test. The well started simultaneous injection-production test on March 6, 2019.

Before the test, the well had an average daily fluid production of about 3.1 m³, average daily oil production of about 2.1 t, and water cut of about 19.0%. After 5 d, the water injection started to take effect. Then the well remained at a stable daily liquid production of about 5.3 m³ and stable daily oil production of about 4.0 t. Meanwhile, its water cut dropped and stabilized at about 13.0%. By the end of November 2019, it had a cumulative oil increment of 340 t. To date, it has been producing stably (Fig. 14), showing good test results.

The total cost of simultaneous injection and production operation and downhole tools of a well is 846 000 yuan. Calculated at the oil price of 3185 yuan/t, an oil increase of 270 t can recover the cost. Well MP93 has a cumulative oil increment of 430 t, and the calculated input-output ratio is 1.00: 1.78. Well CP14-01 is currently stable in production, and by the end of November in 2019, it has obtained an oil increment of 340 t, that is an input-output ratio of 1.00: 1.26, demonstrating overall good development benefit.

The horizontal well simultaneous injection-production energy supplement method can reduce the distance between injection end and production end, and quickly establish an effective water flooding displacement system, realizing the transformation from cross-well displacement to inter-segment displacement in a horizontal well, and from point water flooding to linear water flooding, greatly increasing the water sweeping volume and shortening the cycle needed for water injection to take effect.

During simultaneous injection-production in horizontal wells of ultra-low permeability sandstone reservoirs, the section with natural fractures consistent with artificial fractures in direction or with no natural fracture should be selected as water injection section, and the space between two sections should be 60-80 m.

In addition to controlling injection pressure, cyclic water injection can be adopted to reduce the risk of natural fracture opening and growth or formation rupture caused by the gradual increase of water injection pressure.

The field test results show that the horizontal well simultaneous injection-production energy supplement method can effectively increase the production of wells and has good economic benefits, so it can be applied to the development of ultra-low permeability sandstone reservoirs on a large scale.