Study of the horizontal sidetracking efficiency using hydrodynamic modeling (on the example of a Kazakhstani field)

One of the modern approaches for the effective development of small deposits is the construction and operation of wells with a complex architecture: horizontal wells (HW), sidetracks (BS, BGS), multilateral wells (MLW). Sidetracking makes it possible to reanimate an old well that is in an emergency state or inactivity for technological reasons, by opening layers that have not been previously developed, bypassing contamination zones, or watering the formation. This study examines the possibility of using horizontal sidetracks in the operating wells of the field of the Zhetybai group. To select the optimal length of the horizontal sidetrack of the wells, graphs of the dependences of the change in flow rate versus length of the horizontal well were built, taking into account the pressure losses due to friction. It can be seen from the dependence of NPV versus length of the horizontal wellbore that the maximum NPV is achieved with a horizontal wellbore length of 100 m. A further increase in the length of the horizontal wellbore leads to a decrease in NPV. This is due, firstly, to a decrease in oil prices, and secondly, interference of wells, a small number of residual reserves, and a small oil-bearing area. As a result of a comparison of technical and economic criteria, the optimal length of a horizontal wellbore is from 100-300 meters. Comparison of the flow rates of vertical wells and wells with horizontal sidetracks showed a clear advantage over the latter in all respects.

Experimental Study on Diverter Transport Through Perforations in Multicluster Fracturing of Horizontal Well

Summary Temporary plugging and diverting fracturing of the horizontal well is the primary option to promote production for tight reservoirs. Successful entry of diverters into the perforation is the basis and prerequisite for effective plugging. However, the transport behavior of the diverter during multicluster fracturing remains unclear. In this paper, we build a large-scale diverter transport experimental system, capable of conducting experiments with large flow rates and high pressures. The concerned factors include the injection rate, perforation flow ratio (PFRO), fluid viscosity, and perforation angle. The results show that the diverter transport effect is significantly different because of different flow distribution among perforations. Also, the diverter can enter the perforation only when the flow rate of the perforation reaches a certain value. In addition, the minimum critical PFRO has an “oblique L-shaped” relationship with the injection rate. Although it is difficult for the diverter to enter the perforation on the high side of the horizontal wellbore, increasing the viscosity of the carrying fluid or using a multidensity mixed diverter can effectively solve this problem. Furthermore, the field case shows that the experimentally obtained diverter transport pattern can be applied to the field to predict the location of the diverter and improve the temporary plugging effect. The findings of this work lay a theoretical foundation for subsequent temporary plugging and diverting fracturing control.

Features of gas inflow to a horizontal wellbore at various trajectories

This article discusses the effect of wellbore trajectory on the flow performance of a horizontal cased and perforated gas well. We used a coupled well-reservoir flow model, taking into account the nature of the flow, and local hydraulic resistances of the wellbore, and thus determined the pressure and mass flow distribution along the horizontal wellbore for several types of trajectories, including undulated and toe-up trajectories. The simulation results showed the effect of horizontal gas well trajectory type on its flow rate and the importance of considering pressure distribution to optimize well design.

Horizontal wellbore production profile evaluation by distributed fiber-optic temperature surveillance

The main goal of the paper is demonstration of permanent downhole long-term monitoring capabilities for oil and gas production profile along horizontal wellbore in case of natural flow. The informational basis of the results obtained is the data of long-term temperature and acoustic monitoring in the borehole using a distributed fiber-optic sensor (DTS + DAS). Materials and methods. At the same time, flowing bottom-hole pressure and surface rates were monitored at the well for rate transient analysis, as well as acoustic cross-well interference testing [1], based on the results of which “well-reservoir” system properties were evaluated, the cross-well reservoir properties of the were estimated, and the possibility of cross-well testing using downhole DTS-DAS equipment was justified. The research results made it possible to assess reliability of DTS-DAS long-term monitoring analysis results in case of multiphase inflow and multiphase wellbore content. In particular, DTS-DAS results was strongly affected by the phase segregation in the near-wellbore zone of the formation. Conclusions. In the process of study, the tasks of inflow profile for each fluid phase evaluation, as well as its changes during the well production, were solved. The reservoir intervals with dominantly gas production have been reliably revealed, and the distribution of production along the wellbore has been quantified for time periods at the start of production and after production stabilization.

A Machine Learning Approach to Predict the Pressure Gradient of Different Oil-Water Flow Patterns in a Horizontal Wellbore

Fluid pressure gradient in a wellbore plays a significant role to efficiently transport between source and separator facilities. The mixture of two immiscible fluids manifests in various flow patterns such as stratified, dispersed, intermittent, and annular flow, which can significantly influence the fluid’s pressure gradient. However, previous studies have only used limited flow patterns when developing their data-driven model. The aim of this study is to develop a uniform data-driven model using machine-learning (ML) algorithms that can accurately predict the pressure gradient for the oil-water flow with two stratified and seven dispersed flow patterns in a horizontal wellbore. Two different machine-learning algorithms, Artificial Neural Network (ANN) and Random Forest (RF), were employed to predict the pressure gradients. A total of 662 experimental points from nine different flow patterns were extracted from five sources that include twelve variables for different physical properties of oil-water, wellbore’s surface roughness, and input diameter. The variables are entrance length to diameter ratio, oil and water viscosity, density, velocity, and surface tension, between oil and water surface tension, surface roughness, input diameter, and flow pattern. The algorithms’ performance was evaluated using median absolute percentage error (MdAPE) and root mean squared error (RMSE). A repeated train-test split strategy was used where the final MdAPE and RMSE were computed from the average of all repetitions. The MdAPE and RMSE for the prediction of pressure gradients are 13.89% and 0.138 kPa/m using RF and 12.17% and 0.088 kPa/m using ANN, respectively. The ML algorithms’ ability to model the pressure gradient is demonstrated using measured vs. predicted analysis where the experimental data points are mostly located in close proximity of the diagonal line, indicating a suitable generalization of the models. Comparing the performance between RF and ANN shows that the latter algorithm’s prediction accuracy is significantly better (p<0.01).

A Practical Model for Water Injection Evaluation and Optimization in Typical Offshore Reservoirs Considering Formation Heterogeneity Based on Experimental Study

A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a "U" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed "U" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed "U" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.

First Successful Autonomous ICD Pilot for GOR Management Across ADNOC Offshore

The paper discusses the pilot project in ADNOC Offshore to assess the Autonomous Inflow Control Device (AICD) technology as an effective solution for increasing oil production over the life of the field. High rate of water and gas production in horizontal wells is one of the key problems from the commencement of operation due to the high cost of produced water and gas treatment including several other factors. Early Gas breakthrough in wells can result in shut-in to conserve reservoir energy and to meet the set GOR guidelines. The pilot well was shut-in due to high GOR resulted from the gas breakthrough. A pilot project was implemented to evaluate the ability of autonomous inflow control technology to manage gas break through early in the life of the well spanned across horizontal wellbore. And also to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. Each compartment in the pilot well was equipped with AICD Screens and Swell-able Packers across horizontal open hole wellbore to evaluate oil production and defer gas breakthrough. Some AICDs were equipped with treatment valve for the compartments that needed acid simulation to enhance the effectiveness of the zone. The selection factors for installing number of production valves in the pilot well per each AICD was based on reservoir and field data. Pre-modeling of the horizontal wellbore section with AICD was performed using commercial simulation software (NETool). After the first pilot was completed, a detailed technical analysis was conducted and based on the early production results from the pilot well showed that AICD completions effectively managed gas production by delaying the gas break through and restricting gas inflow from the reservoir with significant GOR reduction ±40% compared to baseline production performance data from the open hole without AICD thus increasing oil production. The pilot well performed positively to the AICD completion allowing to produce healthy oil and meeting the guidelines. The early production results are in line with NETool simulation modelling, thereby increasing assurance in the methods employed in designing the AICD completion for the well and candidate selection. This paper discusses the successful AICD completion installation and production operation in pilot well in ADNOC Offshore to manage GOR and produced the well with healthy oil under the set guidelines. This will enable to re-activate wells shut-in due to GOR constraint to help meeting the sustainable field production target.

An Investigation on the Migration and Settlement Law of Temporary Plugging Particles in Horizontal Wellbore

Migration and settlement of temporary plugging particles of different sizes affect the effect of temporary plugging, which in turn affect the effect of reservoir reconstruction. However, the migration and settlement laws of temporary plugging particles in horizontal wellbore are still unclear. In order to study the migration and settlement laws of temporary plugging particles in horizontal wellbore, a set of multicluster perforation physical model experiment device for horizontal wells was built. Based on this experimental device, the effects of mass ratio, pumping rate, and adding sequence on the migration and settlement laws of temporary plugging particles were studied, respectively. The experimental results show that the 3 mm temporary plugging particles move forward in a leaping manner at the bottom of the horizontal wellbore and the 1 mm particles are distributed in layers in the horizontal wellbore, and the particles are less in the upper part of the wellbore and more in the bottom of the wellbore. The migration trajectory of the two mixed particles is similar to the single. Under different mass ratio, the settlement mass of particles in the perforation clusters at the outlet end is greater than that in the entrance end. When the 3 mm particles account for a relatively large amount ( m 3 mm : m 1 mm = 5 : 1 ), the settlement mass of the particles in the two perforation clusters is greater than other mass ratio conditions. For the same perforation, the settlement mass becomes greater as the proportion of 3 mm increases. When only 3 mm particles are considered, with the increasing of displacement, the mass of particles in the perforation clusters at the inlet end increases, and the mass of particles in the clusters at the outlet end decreases. With the increase of displacement, the sedimentation mass of particles in high angle perforations decreases, while the sedimentation mass in other perforations increases. Adding 3 mm first and then 1 mm particles, the particle settlement mass in the perforation cluster at the outlet end is twice the mass of the particles in the perforation cluster at the inlet end. Reversing the sequence, the settlement masses of the particles in the two clusters are almost equal. The particle distribution in the perforation at different angles has obvious gradation. The smaller the angle, the greater the settlement mass of the temporary plugging particles. This research results will provide reference for temporary plugging and fracturing construction.

Operation Features of Wells with an Extended Horizontal Wellbore and Multistage Hydraulic Fracturing Operation in Bazhenov Formation

Wells with extended horizontal wellbore (HW) drilling with multistage hydraulic fracturing (MHF) is necessary for commercial oil production from Bazhenov formation (Vashkevich et al., 2015; Strizhnev, 2019). Today the maximum HW length for Bazhenov formation wells is 1500 m (Strizhnev, 2019, Korobitsyn et al., 2020). In international practice the maximum HW length for shale oil production is around 3000-400 m (Rodionova et al., 2019). Pump Down Perforator (PDP) technology is used for MHF: a liner is run in hole and cemented, then perforation and hydraulic fracturing (HF) are successively performed by stages at equal distances from the end to the beginning of HW to create a branched system of fractures in Bazhenov formation. Performed HF stages are isolated with special packer plugs (insoluble blind, dissolvable blind, insoluble with seat for dissolvable ball or dissolvable with seat for dissolvable ball)) (Mingazov et al., 2020). Consequently, the fluid inflow into the well is occurred along whole HW and the flow rate increases from monotonically from the end to the beginning of HW and has maximum value at last HF stage. The numbers of HF stages are about 24-30 (number of perforating clusters - 100) at one well in Russia and 50 in the world (Alzahabi et al., 2019). One of important parameter during HF is the speed of HF fluid injection into the formation. Tubing outer diameters 114-140 mm. are used in HW to increase the injection rate and reduce friction losses in the well. The flow rate of HF fluid in this case reach to 14-16 m3/min (Ogneva et al., 2020; Astafiev et al., 2015). Monobore wells construction is planned to use with outer diameter 140 mm. A stinger is used as sealing element between tubing and liner to minimizing risk of HF liquids leaks into the annulus (Astafiev et al., 2015). As a result, the inner well diameter from wellhead to bottomhole is around constant in the process of MHF. The pressure in the hydraulic fractures and the collector near fractures after MHF is highly exceeded the initial reservoir pressure. Hence wellhead pressure after MHF in water filled well is about 100-150 bar (Jing Wang et al., 2021). This fact significantly limits downhole well operations because of requires killing (tubing change, let down ESP, etc.). These works are required heavy well killing fluid because of high overpressure. It is undesirable because of it can reduce the fracture conductivity, worse well bottom zone properties and reduce well productivity. Therefore, the well is working at flowing mode in initial period usually until the reservoir pressure in the drainage area is decreased at the hydrostatic level or below (Jing Wang et al., 2021). After that the well can be killing using technical water with a density of 1.01 – 1.07 g/sm3 (the use of well-killing fluid with a density higher than 1.1 g/sm3 is undesirable). The possibility of well flowing working depends on properties of collector and reservoir fluid: High gas-oil ratio (GOR) and reservoir conductivity help well flowing until reservoir pressure drop off hydrostatic pressure.