Productivity Of Horizontal Wells Research Articles

Study on Predicting Liquid Production Profile in Horizontal Wells Considering the Mechanism of Annular Flow Resistance and Water Control

The coated particle ICD water control technology has been widely used in horizontal well completion in offshore oil fields in recent years, but there is a lack of research on the simulation and prediction methods for liquid production profiles. By analyzing the dynamic inflow process of fluid, starting from the laws of momentum conservation and mass conservation, a coupled mathematical model of horizontal well reservoir wellbore pressure drop considering the mechanism of annular flow resistance was established, and solved through programming. Based on the actual well data of a certain block in an offshore oilfield, a horizontal well reservoir production model was established. The calculation results of the example show that the annular flow resistance and water control technology can effectively control the balanced liquid production of horizontal wells, thereby increasing the anhydrous oil recovery period and improving the oil recovery rate of the oilfield; The coupling model simulation and prediction method can fully reflect the mutual influence between the oil reservoir, wellbore annulus, ICD, and horizontal wellbore; The effective diameter of the ICD valve affects the changes in oil production and water content. The placement of the ICD well section has a significant effect on water control, and the compactness of the filled particles has a certain impact on pressure and water content changes.

Efficient optimization of fracturing parameters with consideration of fracture propagation and heterogeneity in tight gas reservoirs

The parameters of fractures, such as fracture geometries, placement, and conductivity, are critical for the production of horizontal wells in tight gas reservoirs. Current studies on fracture parameter optimization, especially those using the optimization algorithms, are often based on the assumptions that the fractures are uniformly placed with equal length and conductivity. However, non-uniform designs of fracture spacing have been proved to be effective in reducing fracture interference as well as increasing the well production, especially with strong rock heterogeneity. In addition, most of the current literature focuses on identifying optimal hydraulic fracture geometries without considering the fracture propagation process, which may oversimplify the evaluation of completion cost and result in fracture geometries that cannot be realized in practice.In this paper, an automatic optimization process, which could efficiently couple the fracture propagation, is proposed to optimize the fracture parameters. The genetic algorithm (GA) with penalty function method is used to optimize the constraint and non-linear problem. A modified PKN fracture propagation model is established to quickly predict the hydraulic fracture geometries. Fracture locations and fluid injection volume are sequentially optimized with consideration of heterogeneous rock properties. Model parameters are taken from typical tight gas horizontal wells in Jinqiu gas field in Sichuan Province, China. The results show the importance of permeability on both fracture length and production in tight gas well. The lower the permeability, the more significant the production increase after fracture location optimization. More fractures tend to be placed in area with small permeability and fewer fractures are required in highly permeable regions. With an increase in rock heterogeneity, the distribution of fractures becomes more uneven. Conversely, increasing the number of fractures can lead to a more even distribution of fractures. More fluid should be injected in low-permeability regions according to the optimization results. The optimization method is applied to a practical tight gas well in Sichuan Basin and the cumulative gas production can be increased by 6.5% to 8% when compared with the initial uniform designs.

A productivity equation of horizontal wells in the bottom water drive reservoir with an interlayer

The interlayer can effectively prevent the ridge of bottom water and has a non-negligible influence on the flow dynamics of oil and gas in the reservoir. In view of the above problems, this paper studies the influence of a bottom water reservoir with an interlayer on the critical productivity of horizontal wells and establishes a coupling model of seepage and wellbore flow in a bottom water reservoir with an interlayer. The critical productivity of horizontal wells in a bottom water reservoir with an interlayer can be evaluated more accurately. Firstly, the three-dimensional seepage field is approximately decomposed into internal and external seepage fields, and the critical productivity formulas of internal and external seepage fields are solved, respectively. Using the equivalent seepage resistance, the critical productivity formula of horizontal wells in interlayer bottom water reservoirs is obtained. The results are compared with the calculation results of the traditional productivity formula and the simulation results of the commercial software ECLIPSE. Second, based on the mass conservation principle and momentum conservation principle, the wellbore-reservoir coupling mathematical model of a horizontal well is established by the discrete method. Finally, the sensitivity analysis of the selected parameters is discussed in detail. The results show that: (1) compared with the traditional productivity algorithm, the algorithm considers the influence of interlayers on productivity and gives a detailed theory, a specific calculation process, and the importance of accurate prediction of wellbore flow. (2) The model is calculated by an example, and the calculation results are compared with the traditional formula and the commercial simulator ECLIPSE. The results show that the horizontal well productivity formula considering the influence of interlayer is closer to the simulation results of commercial software ECLIPSE, and the relative error is 8.56%. (3) The established coupling model considers the influence of interlayer radius length and horizontal well length. The general trend is that productivity gradually increases with an increase in interlayer radius length or horizontal well length, but the growth rate gradually decreases.

Low-permeability reservoirs flooding using horizontal wells

For the first time in the practice of horizontal well flooding the study investigates the influence of horizontal well length, number of stages, and proppant loading on productivity during hydraulic development of low-permeability reservoirs using horizontal wells. To increase the sweep efficiency in systems with horizontal wells, a new development systems configuration is proposed, relying on longitudinal horizontal production wells and transverse horizontal injection wells with respect to the regional stress direction. The use of this configuration will not only increase the efficiency of reservoir pressure maintenance systems, but also reduce capital costs for well construction by reducing the injection wells to production wells ratio per development unit while maintaining system stiffness. Keywords: horizontal injection well; Auto-HF fracture; low-permeability reservoir; reservoir pressure maintenance system; oil recovery ratio increasing

Analysis of the Application of Marked Proppant When Carrying Out Multistage Fracturing of the Object YUV1

The article analyzes the results of using the inflow monitoring technology in GeoSplit horizontal production wells, the essence of which is the use of quantum marker-reporters, which are sources of accurate information about the inflow of water and oil. One of the ways to place markers in a well is to mix them with a proppant base during multi-stage hydraulic fracturing. This technology makes it possible to obtain information about the inflow for each multi-stage hydraulic fracturing interval over a long period of time.

Simple pseudo-steady state productivity index correlations for infinite-conductivity horizontal wells based on a rigorous, semi-analytical model

Simple pseudo-steady state (PSS) productivity index (PI) correlations are developed for horizontal wells producing at a constant rate from a closed, rectangular reservoir based on a rigorous infinite-conductivity model (ICM). The main three correlations are functions of the half-length wellbore segments number (mt) only and mt can be determined by the general correlation, which is a function of dimensionless well length (LD). The correlations are developed by using a nonlinear regression technique (with zero error) based on over thousand semi-analytical runs for a rigorous ICM covering 90 cases of different well and reservoir configurations. The 90 cases are averaged with less than 5% error in the total pressure drop calculation for the most of them to reduce the number of correlations and to remove the slight effect of well penetration ratio (PR). The PSS PI correlations are simply used to calculate mt, average pressure drop at transient-state, average starting time of PSS, and average total pressure drop at the beginning of PSS. At PSS, the reservoir outer boundaries are dominant, and the pressure drop will depend on the temporal and the spatial time-independent functions. The simple PSS PI correlations have been verified, and can be easily implemented in a standard spreadsheet code.The results show that LD is directly proportional to PSS PI and more significant than reservoir thickness (h) on horizontal-well productivity evaluation, which confirms the principle of the economic feasibility for drilling horizontal well in the oil industry. The results also show that the horizontal-well productivity by this study is several times higher than its counterparts by the methods reported in the literature because the method used by this study is based on a rigorous infinite-conductivity solution where no significant pressure drop occurs, while the previous methods are based on approximate infinite-conductivity solutions (AICSs). Therefore, there is a big underestimation in productivity calculation by using the previous methods which crucially reflect on reservoir evaluation. The new correlations give accurate PSS PI for over 3000 cases of diverse well and reservoir configurations, besides giving a rough PSS PI for the other cases.

A Physics-Informed Neural Network Approach for Surrogating a Numerical Simulation of Fractured Horizontal Well Production Prediction

With the popularity of deep learning (DL), more and more studies are focusing on replacing time-consuming numerical simulations with efficient surrogate models to predict the production of multi-stage fractured horizontal wells. Previous studies on constructing surrogate models for the prediction of the production of fractured horizontal wells often relied on directly applying existing deep learning architectures without incorporating physical constraints into the model. When dealing with the large number of variables necessary for characterizing the properties of fractures, the input variables of proxy models are often oversimplified; meanwhile, lots of physical information is lost. Consequently, predictions are sometimes physically inconsistent with the underlying principles of the domain. In this study, by modifying the traditional Seq2Seq (LSTM–LSTM) deep learning architecture, a physics-informed encoder–decoder (PIED) architecture was developed to surrogate the numerical simulation codes for predicting the production of horizontal wells with unequal-length intersecting hydraulic fractures on a 2D plane. The encoder is a LSTM network, and the decoder consists of LSTM and fully connected layers. The attention algorithm is also applied in the Seq2Seq architecture. The PIED model’s encoder is capable of extracting the physical information related to fractures. And the attention module effectively passes on the most relevant physical information related to production to the decoder during the training process. By modifying Seq2Seq architecture, the decoder of the PIED incorporates the intermediate input, which is the constant production time, along with the extracted physical information to predict production values. The PIED model excels in extracting sufficient physical information from high-dimensional inputs while ensuring the integrity of the production time information. By considering the physical constraints, the model predicts production values with improved accuracy and generalization capabilities. In addition, a multi-layer perceptron (MLP) which is broadly used as a proxy model; a regular Seq2Seq model (LSTM–Attention–LSTM); and the PIED were compared via a case study, and their MAE values were shown to be 241.76, 184.07, 168.81, respectively. Therefore, the proposed model has higher accuracy and better generalization ability. In the case study, a comparative experiment was conducted by comparing LSTM–MLP (with an MAE of 221.50) and LSTM–LSTM to demonstrate that using LSTM as the decoder structure is better for predicting production series. Moreover, in the task of predicting production sequences, LSTM outperforms MLP. The Seq2Seq architecture demonstrated excellent performance in this problem, and it achieved a 48.4% reduction in MSE compared to MLP. Meanwhile, the time cost for build datasets was considered, and the proposed model was found to be capable of training in a small dataset (e.g., in the case study, 3 days were used to generate 450 samples for training.); thus, the proposed model has a certain degree of practicality.

MODELING OF THE OPTIMAL INSTALLATION OF HORIZONTAL WELLS IN WEAKLY PERMEABLE ANISOTROPIC GAS-BEARING RESERVOIRS

In order to increase gas production in anisotropic weakly permeable hard reaching reservoirs on the base of combined finite-element-difference method for the non-stationary anisotropic Leibenzon problem of piezoconductivity we have carried out a numerical simulation of the distribution of pressure drop around a horizontal production well in an anisotropic weakly permeable gas-bearing reservoir. We have established that the efficiency of gas recovery around a horizontal production well and, accordingly, its productivity significantly depends on the location of the well in a weakly permeable anisotropic gas-bearing reservoir.
 Based on the obtained results, for effective exploitation of the anisotropic weakly permeable gas reservoirs, it is necessary to place horizontal production wells in areas with relatively low shear anisotropy of the reservoir’s permeability. If it possible, artificially to increase the parameters of permeability around the production well and gas infiltration on the boundaries of the considered reservoir’s area, it will contribute to increasing of the gas yield and prolonging the productivity of the well during reservoir’s exploitation. At the placing of horizontal wells in anisotropic gas reservoirs, the most effective installation is that would ensure all around supply of the gas phase. This is, on the one hand, there was no blocking of gas from the side of reduced permeability, and on another hand, there was no rapid depletion of the reservoir from the side of increased permeability, and it was ensured a free access of gas to the well from all possible directions. We have shown that the location of the horizontal well in the diagonal direction to the main axes of anisotropy is universal relatively different directions of gas flow, therefore, such location is productive and effective as one.

Reservoir Simulation of Cross CAGD (XCAGD) Thermal Enhanced Heavy Oil Recovery using Foam with Steam Injection

Among the most important thermal oil recovery enhancement methods, it is possible to point out In-Situ Combustion (ISC) and Steam Assisted Gravity Drainage (SAGD) processes. The “Combustion Assisted Gravity Drainage (CAGD) process” as an oil recovery enhancement method is a specific combination of two methods: 1-In-Situ Combustion process mostly in terms of the process mechanism and the combustion reactions and also the injected gas type. and 2-Steam Assisted Gravity Drainage process mostly in terms of well configuration. Cross CAGD (XCAGD) is akin to CAGD except that the horizontal injectors are placed perpendicular to the horizontal production wells. By combining both gravity drainage and lateral displacement, XCAGD is able to hasten recovery, diminish steam requirements and promote economic potential compared to CAGD. XCAGD is better suited for several near producers with several perpendicular injectors to achieve a better development. It should be noted that near above kick off point of the vertical injectors with the horizontal producers in XCAGD, slotted liner embedding is pivotal. In this paper, a reservoir simulation of Cross CAGD (XCAGD) thermal enhanced heavy oil recovery using Foam with Steam injection has been precisely scrutinized and studied then some good results have been obtained. These good results encompass more recovery factor of produced oil about %3-5 derived from FOIP curves.

The productivity segmented calculation model of perforated horizontal wells considering whether to penetrate the contaminated zone

Perforation technology is often used to improve the productivity of horizontal wells in oilfield exploitation. During the perforation process, the formation seepage mode and productivity will change accordingly whether the contaminated zone is shot through. If we continue to use the previous productivity formula, it will cause a large calculation error and bring economic loss to the development of oil and gas fields. Firstly, based on the principle of equivalent seepage resistance, the reservoir-hole inflow profile in these two cases is analyzed in detail, and the reservoir-hole seepage model is constructed in different regions. The perforated horizontal well section is divided into N micro-unit sections, and the pressure drop model in the wellbore is constructed using the fluid mechanics theory. A new perforated horizontal well productivity prediction model is then created by coupling the reservoir-hole seepage model with the pressure drop model in the wellbore as a whole to accurately reflect the production performance of the perforated horizontal well. Through comparison and verification, it is concluded that the calculation results of the model are more precise, which can greatly reduce the productivity error. This method is reasonable and practical. When the oilfield’s actual well data is substituted into this model, it is discussed and analyzed that the reservoir’s physical characteristics, contamination level, and perforation completion parameters all have an impact on the productivity of horizontal wells, with the original formation’s permeability and reservoir contamination thickness having the most pronounced effects. These findings may effectively direct the design of technological processes and performance impact prediction.

Factors influencing the productivity of horizontal wells on an example of the karachaganak deposit

This article examines the factors affecting the productivity of horizontal oil wells in the example of the oil reservoir of the Karachaganak field. The paper presents several methods for calculating the productivity of horizontal wells, taking into account the geometry of the drainage zone. The formulas describing the productivity for each of the methods are analyzed, and the results of calculating the flow rates of horizontal wells for various parameters are presented. The authors considered the following methods: Yu. P. Borisov, S. D. Joshi F. M. Method Giger, method G. I. Renard, J. M. Dupug and Z. S. Alieva, V. V. Sheremet. All methods are based on the assumption of a stationary filtration regime, uniformity of the reservoir, and the location of the horizontal wellbore symmetrically or asymmetrically in thickness. Calculations were performed for well No. 918 in the Karachaganak field using various values of reservoir thickness, horizontal wellbore length, permeability, drawdown, and distance to the feed loop.

Proxy Model Forecasts Production of Shale Wells With Complex Fracture Networks

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209635, “A Deep-Learning-Based Approach for Production Forecasting and Reservoir Evaluation for Shale Gas Wells With Complex Fracture Networks,” by Peng Dong, SPE, and Xinwei Liao, China University of Petroleum at Beijing. The paper has not been peer reviewed. _ The complete paper proposes a data-driven proxy model to effectively forecast the production of horizontal wells with complex fracture networks in shales. With a multilayer gated recurrent unit (GRU) cell, the proxy model is coupled with newly developed deep-learning methods, an attention mechanism (Att-GRU), skip connection, and cross-validation to deal with time-series-analysis (TSA) issues of multivariate operating and physical parameters. Results indicate that the Att-GRU method can forecast the production for shale gas wells with complex fracture networks accurately at a given time and with variable bottomhole pressure (BHP) while maintaining high calculation efficiency. Methodology The authors write that their main interest is to develop a physics-based data-driven model to speed up the simulation of complex fracture networks in shale reservoirs. Results show that the deep-learning model can faithfully recapitulate the variable BHP condition in all of its intricacies with multivariate physical input. In this section of the complete paper, the involved physical background and the corresponding governing equations are clarified. Then, the principle behind the Att-GRU for the problem of complex-fracture-network wells in shale reservoirs is explained. Data initialization and preprocessing and model structure are discussed. Because these sections are equation-intensive and are not suitable for this synopsis but are essential to the methodology explained in the paper, the reader is encouraged to review them in the complete text. Results and Discussions In this section of the complete paper, the physical data in the boundary element method (BEM) are used to train and test the Att-GRU model. The training procedure, test results, and parameters analysis are clarified. The computation burden of the data-driven Att-GRU is compared with the physical model.

Fluidic Diode AICD Characteristic Curve Testing and Mathematical Modeling

In order to investigate an efficient water control method suitable for the bottom water occurring during the production process of horizontal wells in bottom water reservoirs, the characteristic curves of a Fluidic Diode AICD (Automatic Inflow Control Device) were tested, and a mathematical modeling method is proposed. First, the working principle of a Fluidic Diode AICD was analyzed; subsequently, a Fluidic Diode AICD test platform was designed and built independently, and pressure test experiments of the Fluidic Diode AICD under different flow conditions were carried out to obtain characteristic curves of the Fluidic Diode AICD. Finally, a mathematical model of the flow–pressure drop characteristic curves of the Fluidic Diode AICD was developed and applied to the simulation of water control production in horizontal wells in bottom water reservoirs. The results of the study showed that the Fluidic Diode AICD produces a more significant pressure drop under high water content conditions, and has a better oil and water stabilization function in production. In this study, the reservoir flow, annulus flow, AICD flow, and horizontal wellbore flow are considered, and an integrated coupling model for horizontal wells in bottom water reservoirs is established. This study provides a basis for using Fluidic Diode AICDs in horizontal wells in bottom water reservoirs.

Investigation of the Oil-Soluble Particulate Temporary Plugging Agent-Assisted Water Huff ‘n’ Puff Enhanced Oil Recovery in Tight Oil Reservoirs

Summary Water huff ‘n’ puff is an effective enhanced oil recovery (EOR) technology for tight oil reservoirs. However, the oil production of horizontal wells declines seriously after several huff ‘n’ puff cycles, and a large amount of oil is still trapped in the reservoir due to the heterogeneity of fracturing sections. The temporary plugging agent had been used for plugging high-permeability areas and thus diverting the following fluid into small permeability areas. It would improve the sweep efficiency of flooding fluid, enhancing oil recovery. However, the use of the oil-soluble particulate temporary plugging agent in the water huff ‘n’ puff application is barely reported. Therefore, the feasibility and influencing factors of oil-soluble particulate temporary plugging agent-assisted water huff ‘n’ puff (TAWHP) in enhancing oil recovery was investigated in this study. First, based on the evaluation of the performance of the oil-soluble particulate temporary plugging agent, the oil recovery of fractured core samples with different apertures for water huff ‘n’ puff and TAWHP was compared via the parallel-core experiment to verify the feasibility of TAWHP in enhancing oil recovery. The temporary plugging agent had good oil solubility, a low residual rate in the formation, and little damage to the formation. The oil recovery yielded by TAWHP was 5.17% higher than the traditional water huff ‘n’ puff process. More oil (i.e., about 1.71%) could be expelled from the fractured core samples with a small aperture. It indicated that the EOR performance yielded by water huff ‘n’ puff after several cycles could be enhanced by adding the oil-soluble particulate temporary plugging agent. After that, a mathematical model of TAWHP was established to investigate the effect of TAWHP parameters on EOR performance. The simulation results showed that the cumulative oil production increased with the increase in injection time of the temporary plugging agent solution, but the trend would level-off after 10 minutes. Moreover, as the diversion index increased, the effect of the injection rate on cumulative oil production gradually enhanced while the effect of the soaking time gradually weakened. Furthermore, the difference in cumulative oil production at different diversion indexes gradually increased as the huff ‘n’ puff cycle increased. This work could provide theoretical guidance for water huff ‘n’ puff enhancing oil recovery after several cycles.

Research on a New Method for Intermittent Production of Horizontal Wells in Low-Permeability Gas Field

With the development of drilling technology in recent years, an increasing number of horizontal wells have been widely used in low-permeability gas fields. Although horizontal wells are much more productive than vertical wells, fluid accumulation can occur when the formation energy drops and the gas flow rate in the wellbore is not sufficient to remove the loaded fluid from the wellbore. Intermittent production is a good method for preventing liquid loading, but thus far, there is no difference between the open and closed working system of horizontal wells and that of vertical wells, and there is a certain misunderstanding here. In this work, experiments were conducted on the opening process and closing process of a horizontal well, and it was found that the loaded fluid in the horizontal wellbore is a large source of water. It enters the vertical section during the opening process, thereby raising the liquid level and storing the fluid loaded in the vertical section during the closing process, which is difficult to unload. Combined with the experimental results, the production dynamics of a horizontal well with intermittent production was analyzed, and the well opening process and well closing process were divided into four stages. On this basis, a new multifrequency well opening method for intermittent production of horizontal wells was proposed to unload the liquid in horizontal wellbore. The field application case shows that this method can effectively eliminate the drawbacks caused by using conventional methods and increase the average gas production in one cycle by 46%.

Optimization of Mathematical Function-Shaped Fracture Distribution Patterns for Multi-Stage Fractured Horizontal Wells

A conventional oil and gas well does not have a natural production capacity, which necessitates a hydraulic fracturing operation. The effectiveness of the fracturing directly impacts the economic benefit of a single well. Among the various parameters, including fracture spacing, fracture width, and conductivity, fracture half-length is one of the main influencing factors on the productivity of horizontal wells. For conventional homogeneous reservoirs, research mainly focuses on fracture patterns with equal fracture lengths. However, in actual production processes, due to mutual interference and the superimposition of drainage areas between fractures, the production distribution of each fracture is non-uniform. Typical fracture distribution patterns mainly include uniform, staggered, dumbbell, and spindle. While many believe that the dumbbell-shaped fracture distribution pattern has the best effect, there has been no quantitative study on the length of each fracture under the dumbbell-shaped pattern. Based on this, this paper proposes a modeling approach for function-shaped fracture distribution that takes advantage of the high production of edge fractures and the low output of middle fractures in horizontal wells. The influence of this approach on production capacity is studied. Constant, linear, and parabolic functions are used to establish the relationship between fracture position and fracture half-length, optimizing the fracture distribution function to achieve the best production effect. This method can guide the horizontal well fracture distribution in the block to maximize productivity. The results show that the parabolic function-shaped model is better than the linear function-shaped model and the constant function-shaped model is the least effective. The research presented in this paper offers a new idea for optimizing on-site fracturing plans. It utilizes mathematical expressions to describe the parameters that affect productivity, which provides valuable guidance for designing multi-stage fractured horizontal wells in the field. In the future, this research will be extended by exploring the optimal fracture distribution function under different formation conditions.

Increasing Gas Production of Continuous Freeze-Thaw Hydrate Deposits Based on Local Reservoir Reconstruction

The fracturing technology for increasing gas production based on hydrate reservoir reconstruction has been proven to have the application prospect of hydrate production. The main content of this work is to study the influence mechanism between multiple production wells after fracturing the reservoirs around horizontal wells. Simulation results indicated that the gas production rates and cumulative volume of released gas by using hydraulic fracturing were both higher than that by using the traditional depressurization method. The average gas-to-water ratio in this work has broken through the technical bottleneck of exploiting hydrate only by the traditional depressurization method. After the rock matrix around the horizontal well was fractured, the permeability of the reservoir in the fracturing area would be increased; thus, the propagation distance of pressure drop would be promoted. In addition, the penetration of the hydrate decomposition area between horizontal production wells was conducive to promoting the flow of decomposed gas and water to production wells. Besides, the hydraulic fracturing method to increase the permeability of the reservoir around the production well is very effective for the gas production of low-permeability natural hydrate deposits. The best distance between production wells was recommended to be 45~60 m, and it was recommended to provide appropriate heat in the area between the two wells to accelerate the decomposition of hydrate.

Depressurization-induced gas production from hydrate reservoirs in the Shenhu sea area using horizontal well: Numerical simulation on horizontal well section deployment for gas production enhancement

In 2020, China successfully conducted the second round of natural gas hydrate pilot production with horizontal wells at W11-W17 deposits in the Shenhu sea area of South China Sea, but the average daily gas production is far from reaching the commercial exploitation. Low productivity has become one of the key factors hindering the commercial exploitation of gas hydrate reservoir. This work taking SHSC-4 well as an example, uses numerical simulation method to analyze the impact of the placement of horizontal well section, length and the production system on productivity of horizontal well in depressurization exploitation. From the analysis of simulation results, it can be seen that the best performance of production capacity can be achieved when horizontal section placed in layer II, which is compared with that placed in layer I and III. More importantly, hydrate in layer I and free gas in layer III can be effectively utilized to improve productivity when layer II is exploited. When the horizontal section is arranged in layer II and produced by depressurization with small pressure difference (1 MPa), the longer the horizontal section length is, the better the productivity will be. However, the average cumulative gas production increment per meter is gradually decreasing. According to the simulation results, 300 m is a reasonable horizontal section length for the exploitation of layer II, and the cumulative gas production reaches 2.55 million cubic meters after 60 days of continuous exploitation. In addition, due to the limitations of convective heat transfer in the low-permeability reservoir in the Shenhu sea area, sensible heat can significantly improve the secondary hydrate generated in the wellbore and the reservoir around the wellbore due to throttling expansion effect, which has a good effect on productivity improvement. Compared with the situation without heating, when the horizontal section is arranged in layer II and the length is 300 m, the production mode of depressurization and combined heating is adopted, and the cumulative gas production of 60 days with different pressure difference (1–5 MPa) is 0.14, 5.55, 14.75, 23.72, and 29.5 times higher than that without heating.

Characteristics of High Flow Zones and a Balanced Development Strategy of a Thick Bioclastic Limestone Reservoir in the Mishrif Formation in X Oilfield, Iraq

The Mishrif Formation in X Oilfield in Iraq is heterogeneous and has prominent development contradictions, and the development plan required urgent adjustment. Based on data regarding the core, cast thin sections, physical property, mercury injection experiments, and development performance, the main geological factors causing the unbalanced development of the Mishrif Formation are identified, and the corresponding development strategy is proposed. The results show that the High Flow Zones (HFZs) are the main geological factors causing unbalanced production in the thick bioclastic limestone reservoir. There are three kinds of HFZs in MA, MB1, and MB2 intervals, namely, the point shoal type, the tidal channel type, and the platform margin shoal type. All HFZs have different scales and distribution patterns. HFZs have ultra-high permeability and large permeability differences with the surrounding reservoir. During development, the oil mainly comes from HFZs, and the considerable reserves in the low permeability reservoir surrounding the HFZs are difficult to develop. The size of the pore throat of the HFZs greatly varies, and permeability is mainly dominated by the mega-pore throat (>10 μm) and the macro-pore throat (2.5~10 μm). In water flood development, the injected water rapidly advances along the mega-pore throat and the macro-pore throat, and the oil in the micro-pore or medium-pore throats are difficult to be displace. It can be concluded that the Mishrif Formation is vertically heterogeneous. The connectivity of HFZs in different intervals greatly varies. As a result, the Mishrif Formation is divided into three development units, MA, MB1, and MB2 + MC, and production wells are deployed in HFZs. The MA adopts a reverse nine-point injection-production pattern, for which the well spacing is 900 m using a vertical well, and the injection well should avoid the HFZs near the faults. The MB1 adopts an irregular five-point injection-production pattern using a vertical well, and the injection wells are deployed at the edge of the tidal channel or in the lagoon. MB2_1 deploys horizontal production wells, for which the well spacing is 900 m. Horizontal production wells, for which the well spacing is 300 m, are deployed in the lower MB2, and the lateral horizontal production wells are converted into injection wells after water breakthrough, and the horizontal wells deployed in the lower part of MC should moderately inject water.

A new method of water control for horizontal wells in heavy oil reservoirs

It is more difficult to control water production in horizontal wells than in vertical wells. It is challenging to predict the water-producing section of a horizontal well and realize staged oil recovery. With water breaking through the oil layer, the water cut of production wells sharply rises. This can even lead to early closure of production wells, which can seriously affect the economic benefits. When researchers explore water control of horizontal wells, they usually use the method of plugging the water-producing section. The success rate is often low due to water flow around the plugged section and pollution of plugging agents in the high-oil saturation area. On the basis of nitrogen for water cresting control, this paper studied the ability of a viscosity reducer (VR) and nitrogen (N2) compound system to inhibit the rise in the water crest. First, a series of two-dimensional quantitative experiments and visualization experiments were conducted to study the influence and mechanism of the VR and N2 system in controlling water cresting. The results show that compared to N2 control of water cresting (recovery improved by 2.70%), the compound system greatly improved the water control and oil increase effects of the horizontal well (recovery improved by 26.38%). The VR enters the area with high oil saturation through osmosis to reduce the viscosity of heavy oil and the water-oil mobility ratio. N2 enhanced the osmosis of the VR in the reservoir. In addition, rheological tests were performed of heavy oil mixtures, and the viscosity reduction mechanism of the VR was analyzed via diffusion-ordered spectroscopy (DOSY) and scanning electron microscopy (SEM). The experiment shows that after addition of the VR, the size of heavy oil deposit was reduced and the asphaltene surface was broken. The VR reduced the viscosity of heavy oil by depolymerizing macromolecular aggregates in heavy oil and preventing them from coming together again. Finally, a field test was conducted in a horizontal well, with a cumulative oil increase of 9286.86 bbl. The research results provide an important guiding significance for water control and oil recovery of horizontal wells.