With small pore throats and poor connectivity, the low permeability reservoir is complicated in seepage mechanism, and the fluid flow in the reservoir shows the characteristics of low velocity non-Darcy flow, rather than complying with the typical Darcy’ s law. On one hand the start-up pressure gradient remarkably impacts the seepage; on the other hand, with the constant recovery of the fluid, the distribution of effective stress changes, and the pore configuration changes with the rock skeleton strain, which further impacts the seepage status and enhances the non-linear seepage of low permeability reservoir^{[12, 13, 14, 15, 16, 17]}.

3.1.1. Mechanism of low velocity non-Darcy seepage

Most fluid in the low permeability reservoir pore is close to the solid surface, and the fluid is strongly adsorbed to the rock pore wall during flow, meanwhile the physical-chemical change at the rock surface greatly impacts the fluid flow, what’ s more, the clay mineral expansion with water and particle migration strengthen the rock surface effect on the fluid flow^[14]. Therefore, for ultra-low permeability reservoirs, the impact of rock surface boundary on the fluid cannot be ignored due to strong solid-liquid action, causing the seepage rule to deviate from the Darcy’ s Law. The start-up pressure gradient is the key parameter to characterize the low velocity non-Darcy flow.

The start-up pressure gradient testing system can be adopted to carry out the depletion simulation-based non-linear seepage experiment on the low permeability core samples, and the relationship curve between start-up pressure gradient and permeability can be plotted (Fig. 1).

Fig. 1.

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	Fig. 1. Relationship between the start-up pressure gradient and permeability of the low permeability reservoir.

Taking the low permeability cores from the Ordos Basin as examples, the regression analysis with experimental data reveals that there is a good power function relationship between the start-up pressure gradient and the permeability (equation (1)), namely with the increase of the permeability, the start-up pressure gradient decreases gradually. The smaller the rock permeability is, and the finer the throat is, the larger the proportion of the boundary thickness adhering to the rock throat wall accounting for the throat radius, the smaller the flow area in the pore, the larger the resistance to overcome the displacement fluid, and the larger the start-up pressure gradient will be. There is an obvious inflection point on the start-up pressure gradient curve with the permeability, namely there is a critical value, when the permeability decreases below the critical value, the start-up pressure gradient increases sharply.

$G=0.060\ 8{{K}^{1.152\ 2}}$ (1)

Low permeability gas reservoirs share the same variation rule, but under different water saturations, the power function relationship between the start-up pressure gradient and permeability changes, the flow mechanism is more complicated under low permeability.

When the water saturation is 50%:

$G=0.015\ 9{{K}^{0.569\ 2}}$ (2)

When the water saturation is 30%:

$G=0.002\ 4{{K}^{0.834\ 3}}$ (3)

When the water saturation is 15%:

$G=0.000\ 2{{K}^{1.374\ 4}}$ (4)

3.1.2. Mechanism of pressure-sensitive effect

Prior to the oilfield recovery, the overlying formation stress on the reservoir rock, pore fluid pressure in the reservoir rock and rock skeleton support can basically reach a state of balance. However, with the recovery of the formation fluid, the pore pressure decreases constantly and the net overlying stress exerting on the rock skeleton increases, making the rock pore texture change with the variation of the net overlying stress, which is manifested as the stress sensitivity of the rock.

From the low permeability core stress sensitivity experiment, the variation of permeability with net overlying pressure can be acquired (Fig. 2), and it can be seen that the low permeability reservoir shows strong stress sensitivity, with the increase of net overlying stress, the permeability decreases constantly, but the decreasing amplitude gradually lessens. During the experiment, when the net stress pressure reached a certain value, it was released gradually. It can be seen that the permeability gradually recovered with the decrease of the net overlying pressure, but the recovery degree was low, thus the permeability loss caused by stress sensitivity is irreversible.

Fig. 2.

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	Fig. 2. Permeability variation curves of low permeability sample sensitive to stress.

In order to characterize the stress sensitivity effect, the concept of stress sensitive coefficient is introduced to evaluate the reservoir stress sensitivity and describe the permeability variation rule with the effective stress. The stress sensitive coefficient can be expressed as:

$\alpha =-\frac{\lg \left( {K}/{{{K}_{{{\sigma }_{\text{i}}}}}}\; \right)}{\lg \left( {\sigma }/{{{\sigma }_{\text{i}}}}\; \right)}$ (5)

Taking the low permeability core samples from the Ordos Basin as examples, the stress sensitivity coefficients of samples with different permeabilities were calculated by using the experimental data, and the regression analysis reveals that there is a good power function relationship between the stress sensitivity coefficient and initial permeability (equation (6)), namely the smaller the permeability is, the larger the stress sensitivity coefficient and the stronger the sensitivity will be; when the permeability decreases below the critical value, the stress sensitivity coefficient increases sharply, and the impact of stress sensitivity increases substantially (Fig. 3).

$\alpha =0.153\ 1K_{\text{i}}^{-0.343}$ (6)

Fig. 3.

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	Fig. 3. Relationship between the stress sensitivity coefficient and initial permeability of the low permeability reservoir.

3.1.3. Action mechanism of slippage effect

A lot of experiments demonstrate that if the same core and gas is measured under different average pressures, the measured absolute permeability is different. When the gas flows in small pores and complicated throats under a relatively low pressure, the gas maintains the low velocity seepage state, because molecular force between the gas and solid is far smaller than that between the liquid and solid, the gas molecule cannot be bound to the pore wall as the liquid molecule, and some gas molecules at the pore wall are still at a movement state, meanwhile due to the momentum transfer the gas molecules in the neighboring layer together with the gas molecules at the pore wall moves directionally along the pore wall, where the flow rate is not zero, indicating the slippage effect of the gas.

The gas slippage effect can be characterized with the slippage factor, which is related to the rock pore texture, gas property and average pore pressure, and can be used to describe the intensity of gas slippage effect. The experimental data regression of Kirschner permeability test on low permeability core samples from the Ordos Basin shows that there is a good power function relationship between the slippage factor and Kirschner permeability, namely, the slippage factor decreases with the increase of Kirschner permeability.

$b=0.072K_{\infty }^{^{-0.29}}$ (7)

The impact of slippage effect on the production depends on the permeability and gas reservoir pressure, the smaller the permeability and gas reservoir pressure, the more remarkable the impact of slippage effect will be.

Generally, if the effective permeability of the reservoir is less than 0.5× 10^-3 μ m², the recovery rate mainly depends on the fracture rather than the reservoir pore. But the real production performance demonstrates that reservoir pores also play an extremely important role during the development of low permeability petroleum reservoirs. According to the idea that recovery rate depends on fracture, the recovery rate of the Ansai oilfield estimated is 18% at most, but in fact, the actual recovery rate of the oilfield has reached 30% in 2018, 12% higher than the estimation result, which is enough to show that the effect of pores cannot be ignored during the development of low permeability reservoirs.

During the initial stage of oil (gas) well production, the fracture permeability is far larger than the matrix pore, thus the fracture plays the major role in fluid flow, and the fluid in the fractures rapidly flows into the wellbore. But the fractures are small in total volume, low in storing capacity and strong in stress sensitivity, as the fluid in fracture is produced, the fracture system pressure would decline, and the fractures, gradually closing or half closing, decrease substantially in conductivity, and thus oil (gas) well productivity drops significantly; during the middle and late stage of production, with the reduction of fracture system pressure, pressure difference occurs between the matrix and fracture, causing the fluid in the matrix to flow toward the fracture, hereafter the matrix pore plays the dominant role in seepage and constantly supplies fluid to the fracture and wellbore. The seepage is characterized by dual- medium and mainly controlled by the throat size and capillary force, with pore seepage working principally and fracture seepage as supplement^[6]. The oil (gas) well production performance shows high production and quick decline in the initial stage; and low production, slow decline rate and long stable production period in the middle-late stage.

The lab experiment and actual production demonstrate that the low permeability reservoirs have complex seepage mechanisms; stress sensitivity effect and start-up pressure gradient have strong impact on seepage; and the fluid flow in the matrix complies with the low velocity non-Darcy’ s Law. Assuming the fluid as single phase and slight compressible, considering the mass exchange inside the matrix and between the matrix and fracture, the model of matrix non-linear seepage can be constructed^{[18, 19]}.

$\nabla {{\left( \rho v \right)}_{{{\text{m}}_{1}}}}+q_{{{\text{m}}_{1}}\text{, }{{\text{m}}_{2}}}^{{}}-q_{{{\text{m}}_{1}}\text{, f}}^{{}}=\frac{\partial {{\left( \phi \rho {{S}_{\text{o}}} \right)}_{{{\text{m}}_{1}}}}}{\partial t}$ (8)

For the matrix, the kinetic equation considering the start-up pressure gradient is:

$v={{10}^{9}}\frac{K}{\mu }\left( \nabla p-G \right)$ (9)

The calculation model for the mass exchange between the matrix and fracture is:

$q_{{{\text{m}}_{1}}\text{, f}}^{{}}={{\beta }_{{{\text{m}}_{1}}\text{, f}}}{{\left( \frac{K\rho }{\mu } \right)}_{{{\text{m}}_{1}}}}\left( {{\Phi }_{{{\text{m}}_{1}}}}-{{\Phi }_{\text{f}}} \right)$ (10)

The calculation model for the mass exchange between the matrices is:

$q_{{{\text{m}}_{1}}\text{, }{{\text{m}}_{\text{2}}}}^{{}}={{\beta }_{{{\text{m}}_{\text{1}}}\text{, }{{\text{m}}_{\text{2}}}}}{{\left( \frac{K\rho }{\mu } \right)}_{{{\text{m}}_{\text{2}}}}}\left( {{\Phi }_{{{\text{m}}_{\text{2}}}}}-{{\Phi }_{{{\text{m}}_{\text{1}}}}} \right)$ (11)

where $\Phi =p-{{10}^{6}}\rho gD$

The fracture presents strong stress sensitivity, where the fluid flow complies with the Darcy’ s Law; considering the mass exchange inside the facture and between the fracture and matrix, the seepage model can be constructed.

$\nabla {{\left( \rho v \right)}_{\text{f}}}+q_{{{\text{m}}_{\text{1}}}\text{, f}}^{{}}=\frac{\partial {{\left( \phi \rho {{S}_{\text{o}}} \right)}_{\text{f}}}}{\partial t}$ (12)

where v can be worked out from the Darcy’ s Law:

$v={{10}^{9}}\frac{K}{\mu }\nabla p$ (13)

The low permeability reservoir seepage model can be built by combining the matrix and fracture seepage models and considering start-up pressure gradient and stress sensitivity.

During the development of low and extra-low permeability oil gas fields, heterogeneity is a relative concept, involving absolute heterogeneity in the relative homogeneity and large- area relative homogenous reservoir constituted by countless relatively homogeneous reservoirs. Although low permeability reservoirs have narrow throat and strong heterogeneity generally, they contain local parts with relative homogeneity and good connectivity where the flow complies with the Darcy’ s Law. In actual oilfield development, through reservoir description, the parts with “ relative homogeneity” can be sought out and developed by optimized program, which usually achieves good results.

The major oil pay in the Ansai oilfield is the Chang-6 of Triassic Yanchang Formation, which is the fluvial-control delta sandstone reservoir with good permeability and small permeability variation coefficient in the major part, and poor permeability and great permeability variation coefficient in the edge zone. According to the theory of “ relative homogeneity” , the middle part of Chang-6 oil pay was selected for water injection development test, during which, a large number of oil wells have achieved good effect with an average daily oil production of 4.03 t, reserve producing degree of the primary well pattern was up to 90.7%, and reserve controlling degree by water-flooding was 73.6%; two years after water injection, the water-drive control degree was 80.7% and effective degree of oil wells was 70%, and water-drive recovery rate was predicted at 20%-25%.

The economic limit refers that the capital expenditures (CAPEX) in each period of oilfield development must be based on the maximum or stable output to carry out the economy appraisal and calculate the pay-off period and profit, if the input-output is rational, the development goes on, otherwise the development ceases temporarily. The definition of the development economic limit should: (1) fully understand the enterprise and social benefits to develop this type of oilfield; (2) set the basic target parameters for the economic limit under the pre-condition of demonstration; (3) completely consider the contribution of technical progress; (4) pre-estimate the promotion effect of developing this type of oilfield to the similar reserves^[6].

Along with the gradual enhancement of development scale, the reserves that can be produced in the low/extra-low permeability reservoir are poorer and poorer in quality, in order to effective exploit these reserves and keep the oil production rising, it is necessary to set the investment limit per 10⁴t oil productivity in accordance with the investment return standard according to the current oil price (at present the standard is 3× 10⁸ Yuan/10⁴ t in China). In accordance with this standard, Changqing Oilfield has accomplished the construction of about 1000× 10⁴ t productivity; later in order to develop the oilfield with the productivity of less than 2 t/d, the basic investment standard was re-set as 5× 10⁸ Yuan/10⁴ t, and 600× 10⁴ t productivity was constructed, which was implemented in 2007 and has achieved good results.

Guided by the economic limit theory, while maintaining rapid growth of oil and gas production and investment, Changqing Oilfield has also made good economic profits, with the return-on-investment rate keeping at a high level. In 2016, Changqing Oilfield realized the return-on-investment rate of 6.36%, contributing second only after Daqing Oilfield among all oilfield companies in PetroChina^[6].

In the exploration appraisal period, the reservoir evaluation should be started early, focusing on precise reservoir description. The geologic, seismic, logging and testing data are comprehensively employed by the interdisciplinary research teams to quantitatively describe, characterize and predict the reservoir characteristics and establish the 3D or 4D reservoir geology model. Meanwhile, according to the production performance in the test areas, the water injection characteristics of different flow units should be determined and corresponding adjustment policy be made, providing first hand data for making scientific and detailed oilfield development program.

The early description greatly narrows the gap between the exploration and development, speeds up the exploration rhythm and development pace, promotes the integration of exploration and development, which facilitates the rapid production construction of low permeability petroleum reservoirs. And the description mainly involves comprehensive reservoir evaluation, reserve assessment and productivity appraisal, of which the core is comprehensive reservoir evaluation. By using the physical property evaluation of core samples, oil testing and logging data of appraisal wells, the precise “ four-property” relationship is examined carefully by mathematical statistics and key well verification methods to find out the relationships between the reservoir lithology, physical property, oiliness and electricity; secondly on the basis of knowing the spatial correspondence between the flow units and sedimentary microfacies, the spatial distribution pattern of flow units are determined according to production performance to make injection adjustment and refine injection-production management.

Learning from the development experience of Ansai oilfield, researchers started early reservoir description in Jing’ an oilfield, deploying appraisal wells based on the prediction of prospective regions and then carrying out the precise 3D reservoir description using the exploration, appraisal and development well data. Following the principle of “ finding the best among the poor, finding the high among the medium, and selecting the rich among the lean” and technical route of “ rich earlier than poor, easy earlier than difficult, appraisal earlier than ODP, testing earlier than development” , the oilfield realized the goal of “ simultaneous exploration and production construction, investment and making profit” . Owing to the integration of exploration and development, the annual oil productivity of 100× 10⁴ t has been accomplished rapidly and efficiently.

The well location selection technology is to employ the high precision digital 2D seismic P-wave pre-stack information and conventional seismic post-stack gas-bearing information to predict the effective reservoir in the screened hydrocarbon region and select the well location, in which the precision of gas-bearing prediction is the key to improving the success rate.

In order to improve the precision of reservoir prediction and gas-bearing detection, through seismic survey parameter optimization and field testing etc., the Changqing Oilfield has developed the high precision 2D seismic survey technology centered on digital geophone receiving, small trace space, large offset, many folds and shooting below water level to get high quality data, and the resulted pre-stack data can be directly applied to the gas-bearing detection, enhancing the precision of gas-bearing detection substantially.

In the development of Sulige gasfield of Changqing, adhering to the route of “ fluvial channel combined with gas- bearing prediction, pre-stack combined with post-stack” , a set of complete seismic-geologic well location selection work flow around fluvial channel has been established (Fig. 4), making the proportion of economic and effective wells rise from the early 50% to 80%.

Fig. 4.

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	Fig. 4. Technical flow of well location seclection in the Sulige gasfield.

For low and extra-low permeability tight sandstone reservoirs, the oil (gas) wells present low or none productivity, thus the large scale fracturing is indispensable for the effective production. In light with this issue, volume fracturing technology aiming at expanding the drainage area has been developed, which realized the transformation from the single-fracture fracturing to multi-fracture fracturing and effectively expanding the employment volume.

4.3.1. Directional perforating fracturing technology

The directional perforating fracturing technology is suitable for tight reservoirs with the difference of maximum and minimum principal stress of less than 5 MPa and thickness larger than 10 m. The directional perforation changes the direction of initial fracturing, forcing the fracture to change directions, and thus creating many mutually-independent S-shaped fractures on the plane in the same horizon to expand the drainage volume controlled by the artificial fracture system and improve the single-well production (Fig. 5).

Fig. 5.

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	Fig. 5. Diagram of directional volumetric perforation and fracturing techniqe.

Numerical simulation and physical modeling experiments show that the decrease of horizontal stress difference will cause the increase of fracture extending distance in the minimum crustal stress direction and the enlargement of hydraulic fracture steering radius during the directional perforating fracturing, if the crustal stress difference exceeds 6 MPa, the fracture steering will be difficult; when the perforation azi-muth intersects with the maximum principal stress direction at a certain angle, the fracture initiates first along the perforation hole direction and then turns to the maximum principal stress direction, moreover, if the intersection angle increases, the fracturing steering radius also increases, and at present the intersection angle is optimized at 45° .

In the Changqing Oilfield, this technology has been applied to 246 wells, with initial average oil increment of 0.4-0.8 t/d a well, demonstrating a good overall effect.

4.3.2. Multistage sand fracturing technology

For the oil (gas) wells with thick reservoirs but without interbeds in the reservoirs, proppant would likely precipitate in the lower part of the reservoir in conventional fracturing because the proppant is placed unevenly vertically, thus the upper oil zone is difficult to be effectively reformed, and the reserves cannot be fully employed. In multistage sand fracturing, the total sand is pumped into the reservoir through multiple stages, and after the 1^st stage fracturing the pumping is stopped to wait for the proppant precipitation and fracture closing, then the next stage fracturing is conducted, and step by step. In the 2^nd stage fracturing, with the preflush hindered by the lower paving proppant, the downward extension of the fracture is blocked, which forces the proppant to pave upward, realizing the improvement of vertical proppant sand-paving section to improve the fracture conductivity in the upper oil zone.

In the Changqing Oilfield, this technology has been applied in more than 2000 wells, increasing the average oil production by 0.3-1.0 t/d than adjacent wells.

4.3.3. Multistage temporary plugging fracturing technology

For low permeability reservoirs with natural microfractures, good sealing condition at top and bottom and small difference of maximum and minimum principal stress, the temporary plugging agent is added repetitiously to force fracture steering and produce many secondary fractures, which can effectively expand the drainage area. Owing to the initial fracturing fractures, the oil (gas) recovery will create induced stress and change the initial crustal stress state, which makes the fracture steering possible during the repeated fracturing process.

The temporary plugging technology^{[20, 21, 22, 23]} is to add temporary plugging agent to the formation during fracturing, after the old fractures are opened, the mixture of temporary agent and proppant enters the original fractures, accumulating in the highly permeable zones to produce the filter cake bridge blockage that stops the further extension of the fractures, thus the subsequent fracture fluid cannot enter the fractures and highly permeable zones, which causes the bottom-hole pressure to rise. When the net pressure in the fracture reaches the microfracture opening pressure or the new fracture breaking pressure, the micro or new fractures open and then extend to become new branch fractures along with the addition of subsequent sand-carrying fluid to communicate the unproduced oil gas zone. The temporary plugging agent would dissolve in the formation water or the fracturing fluid after the operation, thus it won’ t cause secondary pollution.

The field application shows the temporary plugging fracturing can cause obvious rise of fracturing pressure, increase of single well production, with stable or slightly drop of water cut, realizing the purpose of water control and oil production increase. From 2014 to 2015, the temporary plugging steering repeated fracturing was implemented 46 well-times in the D1 oil zone in the Changqing Oilfield, with a success rate of 93.4%, an average single well oil production increment of 1.59 t/d, and water cut drop from 47.6% to 39.7%^{[22, 23]}.

4.3.4. Vertical well multi-layer fracturing technology

For the multi-layer low permeability gas reservoirs, increasing producing layers of single well combined with volume fracturing can effectively improve the single well production. For this purpose, new stratified fracturing technologies with coiled tubing with bottom packer and casing cementation sliding sleeve have been developed to realize the vertical multi-layer development of low permeability gas reservoirs.

(1) Stratified fracturing with coiled tubing with bottom packer. This technology integrates the perforation, fracturing and isolating technologies. First, the coiled tubing tool assembly is run to the 1^st fracturing segment and fixed position, the seating anchorage and packer are set, sanding perforation is done through the coiled tubing, and fracturing fluid is injected into the annulus to implement fracturing, meanwhile, base liquid is pumped at low rate in the tubing. After the 1^st-segment fracturing is done, the coiled tubing packer and coiled tubing are pulled upward to the 2^nd fracturing segment to do perforation and fracturing again. This technology features not limited stratified fracturing layers and segments, quick tripping of frac-strings, real time monitoring of bottom hole pressure with coiled tubing during the fracturing, easy workover in later stage, short operation period and high fracturing efficiency.

(2) Casing cementation sliding sleeve stratified fracturing. In this technology, the sliding sleeve and casing are connected and run to the target formation for cementation, then the darts are dropped to open the sliding sleeve and realize the stratified fracturing, and the ball seat is formed by the pressure transfer hole shrinkage of the previous fracturing stage, which avoids the limit of the conventional stratified fracturing ball seat on the fracture stages. This fracturing can conduct direct fracturing without perforation first, realizing the integration of fracturing and production, and shortening the preparation for production.

Since 2010, in the Changqing Oilfield, 8 wells have been treated with this coiled tubing stratified fracturing, with an average 5.1 layers fractured per well and an average testing production of 1.5-2.0 times of the neighboring wells; meanwhile, 74 layers in 15 wells have been fractured by casing cementation sliding sleeve stratified fracturing, realizing stratified fracturing of 9 layers in one well at most, and the gas testing result shows that the technology reaches the goal of producing multi-layers in a well and increasing production.

Most low and extra-low permeability oil reservoirs are developed by water injection to maintain the formation pressure at present. Since low permeability reservoirs have great seepage resistance and strong heterogeneity, it is difficult to supplement the formation energy, and the oil wells have slow response after water injection, resulting in quick decline of the production indices such as formation pressure, oil recovery index, and fluid recovery index. In order to enhance the single well production and maintain stable production, Changqing Oilfield has put forward the innovative theory of “ advanced water injection” and developed matching techniques suitable for water injection in low permeability oil reservoirs.

4.4.1. Water injection technique

The reasons causing difficult energy supplement and unbalanced water injection in ultra-low permeability oil reservoirs include: (1) low reservoir permeability, great fluid seepage resistance; (2) thick oil layer, strong heterogeneity vertically, rich interbeds, and great difference in water adsorption; (3) incompatibility between the injected water and the lithology, and easy scaling and plugging in the formation; (4) incompatibility between the injected water and the formation water, and possible great capillary resistance at the pore throat. In recent years, based on the high pressure under-injection mechanism research, core analysis and single layer water injection capacity test, the scale inhibition and dispersing scaling crystals have been developed to effectively reduce the flow resistance and evenly supply the formation energy, and the low pressure augmented injection and fine stratified water injection technologies have been worked out.

(1) Low pressure augmented-injection technology. It is suitable for low permeability reservoirs with injection difficulty and comprises three modes: overall pressure reduction, local pressurization and shaped stamping plugging removal. The overall pressure reduction aims to selecting the injection agent suitable for the target area, the agent is added at the water injection station and then enters the deep formation along with the injected water to prevent expansion and scaling and remove scale etc, thus reducing the injecting pressure of the injection well. The local pressurization augmented-injection is to use the centrifugal pressurized water injection pump for pressurized water injection; the shaped stamping plugging removal is to use the impact force created by the combustion of shaped stamping bullet in the well to push the liquid in the shaft repeatedly upward, trigger a wide range of water concussion in the casing, and form the strong discharge at the oil zone interval, to take the blockage of the impurity and slurry at the shooting hole and near-well zone out of the well, moreover the combustion of shaped stamping bullet is also accompanied with high temperature high pressure jet flow, which acts on the perforation hole and creates 3-5m radial microfracture around the perforation hole, meanwhile the acid fluid can enter the formation more effectively in a larger range, which could successfully remove the deep polluting blockage near the well and improves the conductivity near the shaft, realizing the purpose of reservoir reformation and low pressure augmented-injection.

(2) Fine stratified water injection technology. It is suitable for low permeability reservoirs with thick oil layer, rich interbeds and strong vertical heterogeneity, it has three stratified water injection modes: small location, small casing well, bridge plugging eccentric multi-segment. In the small location stratified injection, the magnetic positioning test instrument is run in through the tubing to locate the downhole injection matching tools to realize accurate injection. This technology is mature and easy for operation but takes longer time and high testing cost. The small casing stratified injection is developed for commingled water injection wells from 114.3 mm (4.5 in) small casing in ultra-low permeability oil reservoirs. In this process, the downhole tool string (Y341-95 washable well packer and seat sliding sleeve etc.) is run in, after the packer is seated, the seat sliding sleeve is removed when the pressure reaches 20 MPa to realize the tubing casing separate injection, and the washable well packer is simple in structure and can be set reliably. The bridge eccentric multi-segment stratified water injection with composite bridge eccentric technology, matched with unpacking by stage, magnetic positioning and string anchoring technologies, allows stratified water injection in large deviation wells, deep wells and small spacing, meanwhile the matching tools have been developed, including the pressurizing-down gradual unsealing packer, dual-unsealing gradual unsealing packer and nonmetal hydraulic anchor etc.

4.4.2. Optimization of injection-production well pattern

All the low permeability reservoirs have natural fractures to different extents, the injected water is likely to dash along the axial fractures in the sand, “ forming fingering” , and causing imbalance of injection and production horizontally and vertically. Years of practice shows that the rational optimized injection production well pattern can effectively alleviate the imbalance of injection and production.

The diamond inverted 9-spot pattern (Fig. 6a) has good adaptability and flexibility, enabling the optimum matching of fracture system and well pattern. The connecting line of injection well and corner well parallels to the fracture trend in this well-pattern, meanwhile the well space in the fracture direction is amplified, which is favorable for increasing fracturing scale and artificial fracture length, enhancing the single well production and extending stable production, and alleviating the waterflooding rate of corner well; meanwhile the shortened row space can improve the effect of lateral wells. Till the late development stage, when the water cut of the corner well on the fracture line reaches a certain degree, the corner wells can be converted into water injection wells, and the well pattern is then converted into rectangle 5-spot well pattern (Fig. 6b), which can improve the sweeping volume of matrix pore to the utmost.

Fig. 6.

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	Fig. 6. Schematics of injection-production well pattern optimization.

In order to ensure good economic benefit, the rational well pattern density of low permeability petroleum reservoir should be controlled between the limit and optimum economic density. For the oilfields with higher economic risk, the parameter close to the optimum economic well pattern density should be adopted. The rational injector producer space can be determined by considering the reservoir physical property, fracture development, horizontal and vertical heterogeneity and economic benefit etc.

4.4.3. Moderate advanced water injection

The water injection in low and extra-low permeability petroleum reservoirs needs longer time to take effect, which is unfavorable for efficient development. Advanced water injection is often started long before oilfield development to keep the formation pressure at a rational level, which can solve the problem of long taking-effect cycle. If the advanced water injection time is long enough, the effective displacement pressure system can be established between the oil well and water well, which is favorable for increasing the single well production. But if the water injection pressure is too high, the formation pressure near the water injection well will quickly rise, and the resulted stress field variation will likely trigger the originally closed natural fractures to open and create new fractures on the weak plane centered around the water well, thus the injected water would dash along the dynamic fracture belt. In order to avoid the impacts of these negative factors, Changqing Oilfield proposed the small water volume long term moderate advanced water injection, which has two key points in the design of water injection intensity: (1) The maximum injection pressure is less than the fracture open pressure and formation breakdown pressure, which can effectively prevent the original fracture from opening and new fractures and stop the water dashing along the fracture. (2) The minimum injection pressure should effectively overcome the starting pressure gradient to establish the efficient displacement pressure system and ensure the single well production to increase as much as possible. Considering the contradiction between the fracture opening, formation breakdown and starting pressure gradient, this technology can effectively improve the formation pressure, reduce the pressure sensitivity effect, prevent the injected water from dashing along the fracture and maintain the formation pressure balance, which is favorable for keeping long-term stable and high production.

The development of ultra-low permeability oil reservoir faces more and more complicated reservoir geologic conditions, thus the directional well alone cannot meet the requirement of increasing single well production. In 2010, the Changqing Oilfield made the development strategy of enhancing oil layer drilling rate and supplementing energy by volume fracturing. In light of this, horizontal well testing has been carried out vigorously and made some major breakthroughs in practical technologies, including horizontal well pattern optimization and horizontal well fracturing.

4.5.1. Horizontal well pattern optimization

The core of horizontal well pattern optimization is to realize the proper matching between the natural fractures and artificial fractures and between the fracturing layout and well pattern under the water injection condition. The dominant direction of natural fractures in the ultra-low permeability oil reservoir is the principal seepage direction, due to permeability contrast between the principal and lateral seepage directions, there must exist difference of water-drive seepage pattern on the plane, thus in the optimization of horizontal well fracture layout, the impact of natural fracture distribution pattern must be considered.

With the horizontal well production as the major index, the numerical simulation is used to optimize the horizontal well fracture layout pattern by considering energy supplement, pressure maintenance level, initial recovery rate, production decline and well pattern flexibility, to get the well-patterns for different reservoir conditions: (1) For the reservoir with thickness about 10 m and few fractures, the 5-spot well pattern is the optimum (Fig. 7a), which can avoid early water breakthrough and slow down initial production decline. (2) For the reservoirs more than 16 m thick, with superimposed oil layers or relatively stable interbeds and few fractures, the stereoscopic horizontal well pattern is optimum (Fig. 7a), which can enhance the oil recovery rate. (3) For the reservoirs about 10 m thick, with rich fractures and high brittleness index, the long horizontal section volume fracturing well pattern with quasi-natural energy is optimum (Fig. 7c), which not only expands the single well control range but also fully uses the natural energy, avoid the opening of original fractures and creation of new fractures and prevent the injected water from dashing along the fractures.

Fig. 7.

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	Fig. 7. Sketch of optimization of horizontal injection-production well pattern.

4.5.2. Horizontal well fracturing

Ultra-low permeability gas reservoirs have poor physical properties, strong horizontal and vertical heterogeneity and low natural productivity, so oil (gas) wells in these reservoirs must have volume fracturing to get industrial production. On the basis of the existing fracturing technology, the Changqing Oilfield has developed horizontal well volume fracturing technologies for different types of reservoirs, including hydraulic sand-blasting volume fracturing, open-hole packer volume fracturing, hydraulic pumping bridge plug multi-cluster fracturing etc.

(1) Hydraulic sand-blasting volume fracturing. The technology uses multiple ejectors to blast the sand simultaneously and realize the transformation from the single cluster to multi- cluster perforation. In the process, the sand-carrying passage changes from the tubing to the annulus, and the injection way of “ large displacement sanding from casing and small displacement fluid supplement from tubing” is adopted. Assisted with new steel-belt packer and anti-spatter ejector, this technology can solve the problem of high pressure high displacement fracturing; by enhancing sealing validity of the packer, it can meet the demand of long time large scale fracturing. The hydraulic sand-blasting volume fracturing technology has the advantage of lessening nozzle damage, low cost and easy operation. At present, the fracturing of more than 10 segments and 2-4 clusters per segment can be finished in one trip.

The open-hole packer volume fracturing technology can finish segmented positioned fracturing in one trip. With fewer downhole tools, simple work procedure, high operation efficiency, low well control risk and reliable string performance, this technology can be used for the segmented fracturing of shallow, medium and deep horizontal wells. However, it has high requirements on trajectory of the horizontal interval, and thus is complicated in completion procedure and long in operation cycle.

(3) Hydraulic pumping composite bridge plug segmented multi-cluster fracturing. This technology is based on the introduction of “ hydraulic pumping bridge plug segmented multi-cluster fracturing” . Problems of composite bridge plug design and material selection, multistage ignition perforation, safe pumping in of tool string and easy drilling of bridge plug after fracturing have been overcome through research and experiment, realizing the localization of this technology. It adopts the united perforation and bridge plug seating to accomplish the perforation and plugging the lower horizon with one trip string, realizing both segmented fracturing and staged perforation, meanwhile assisted by temporary material, completing the multi-cluster fracturing to improve the single segment fracturing volume. This technology has the advantages of high sealing reliability, high wellbore quality, and unlimited number of fracture segments.

Field application results show the composite bridge plug segmented multi-cluster fracturing technology can enhance production substantially, with the maximum displacement of 15 m³/min and injected liquid of 2× 10⁴ m³ at most, single segment perforation of 3-6 clusters, fracture band width of 110-140 m, which is 75% wider than that of segmented fracturing.

Water flooding development of low permeability oil reservoirs faces problems like low effective displacement pressure, easy fracture water-out, low swept efficiency, quick production decline, and low recovery rate, and now the contradiction is increasingly prominent. CO₂ flooding can greatly make up the deficiency of water flooding and enhance the oil recovery rate, thus it is a replacing technology for the effective development of low permeability gas reservoirs.

Carbon dioxide is less viscous and easy to enter micro pore throats. Its oil driving mechanisms^{[24, 25, 26, 27, 28, 29, 30, 31]} mainly include: (1) Under the formation temperature and pressure conditions, CO₂ is usually in the supercritical state and has the strong ability of dissolution and extraction, along with the constant CO₂ dissolving in the oil, the OWC tension drops, the oil viscosity reduces, and the relative permeability of oil phase increases. (2) CO₂ dissolves in the formation water to make the water carbonization and the water viscosity increase to improve the oil water mobility ratio. (3) The carbonated water resulted from the CO₂ dissolution in the formation water reacts with the carbonate cement, and then the formation permeability improves, leading to the enhancement of injection capacity, moreover it can contain the clay expansion and stabilize the clay. (4) When the CO₂ is injected into the oil reservoir, a small part of gas undissolved in the oil will occupy the formation pores to displace the oil, meanwhile a great majority of CO₂ dissolves in the oil, making the oil volume expand and increase the displacement energy, along with the constant decline of formation pressure during the development, the CO₂ dissolved in the oil will expand and degas, forming dissolved gas drive to improve the oil displacement efficiency.

Compared with water injection, the pressure of gas injection is lower, which is good at avoiding the generation of dynamic fractures, moreover the CO₂ is more easily injected than water to keep formation pressure and injection-production balance, thus the CO₂ flooding is better than water flooding. Field tests and indoor experiments at home and abroad have demonstrated that the CO₂ flooding has big potential to improve recovery of low permeability oil reservoirs and bright application future.

The matching technologies for CO₂ flooding have been quite mature abroad. Usually reservoirs with good sealing, weak heterogeneity, good connectivity and fairly complete injection production well pattern are selected for CO₂ flooding. In China, the low permeability reservoirs have more complicated geologic conditions, and the CO₂ flooding for low permeability oil reservoirs is still at the initial stage, there are still many issues in theory and technology needed to be solved on its way to industrial application, such as miscibility mechanism, storage mechanism, optimization of injection production well pattern, CO₂ injection technique, anti-channeling and plugging, and processing of produced fluid etc.

f— fracture in the tight reservoir;

m₁, m₂— matrix rock 1 and 2 in the tight reservoir.