Injectivity Of Horizontal Wells Research Articles

A Numerical Simulation Approach for Superheated Steam Flow during Multipoint Steam Injection in Horizontal Well

Superheated steam flow during multipoint steam injection technology has a good effect on improving the steam absorption profile of heavy oil thermal recovery wells, enhancing the production degree of horizontal section of thermal recovery wells, and enhancing oil recovery. Based on the structure of multipoint steam injection horizontal string, considering the characteristics of variable mass flow, pressure drop of steam-liquid two-phase flow, and throttling pressure difference of steam injection valve in the process of steam injection, this paper establishes the calculation model of various parameters of multipoint steam injection horizontal wellbore and calculates the distribution of steam injection rate, temperature, pressure gradient, and dryness along the section of multipoint steam injection in horizontal wellbore. The results show that the temperature and pressure decrease gradually from heel to toe, and the steam dryness decreases gradually. Considering the influence of throttle pressure difference of steam injection valve and pressure drop of gas-liquid two-phase flow in the wellbore, the traditional calculation model of steam injection thermodynamic parameters is optimized, and the optimization of wellbore structure and steam injection parameters is an effective method to achieve uniform steam injection in horizontal wells. The steam injection uniformity of horizontal wells can be effectively improved by adjusting the steam injection valve spacing and steam injection parameters. When the steam injection volume is 200 m3/d and the steam injection valve spacing is 20 m, a more stable steam injection effect can be obtained. The findings of this study can help for better understanding of improving the uniformity of steam injection and enhancing the recovery factor.

New Design Method of a Supersonic Steam Injection Nozzle and Its Numerical Simulation Verification.

Steam huff-n-puff in horizontal wells often had limitations, such as uneven steam injection and low reservoir utilization. To improve steam injection efficiency, a new method for designing a supersonic nozzle was proposed based on the principles of aerodynamics and thermodynamics. The nozzle featured a tapering section, a throat, and a diverging section. The best geometric shape of the tapering section was the Witoszynski curve. A set of nozzle size designs were established, and the size parameters were optimized. The results showed that the nozzle could inject steam into the formation at supersonic speed and it had the characteristics of constant flow rate and uniform development of the steam chamber. According to the steam Reynolds number and the good aggregation distribution characteristics of the size design model, three sequential nozzles of 3.0, 5.0, and 6.5 mm were formed based on the throat. When the throat diameter was 5.0 mm, the tapering length was 4.3 mm, the diverging length was 5.5 mm, the throat length was 3.0 mm, the inlet diameter was 9.8 mm, and the outlet diameter was 6.2 mm. Numerical simulations indicated that the pressure drop loss during steam huff-n-puff injection in horizontal wells was within 10%. It was of great significance to establish the nozzle size design model of the steam injection effect of horizontal wells.

Performance of high temperature steam injection in horizontal wells of heavy oil reservoirs

Steam huff and puff and steam flooding are important development methods for heavy oil reservoirs. At present, there are certain deficiencies in the research on the timing and methods of steam stimulation, steam flooding, and subsequent steam flooding. In addition, the research on the mass and heat transfer characteristics of high temperature steam injection in heavy oil reservoirs is still in the initiation stage. This article first studies the high temperature steam flow model in the horizontal wellbore of the SAGD process. On this basis, a horizontal well pattern model was established through numerical simulation software to analyze the heat and mass transfer characteristics of high temperature steam huff and puff and high temperature steam flooding. Results show that: (a) for heavy oil reservoirs with high temperature steam injection huff and puff, the first cycle of steam injection ends (day 22): the temperature near the well pattern of the horizontal well pattern is higher. In the area between the horizontal well patterns, the temperature rise is not obvious; (b) when the high temperature steam injection huff and puff phase of the heavy oil reservoir ends (900 days), most of the heat energy is recovered, and the formation residual heat is less; (c) After the huff and puff transfer, the thermal connectivity between the horizontal well patterns is better.

Experimental research on inter-fracture asynchronous injection-production cycle for a horizontal well in a tight oil reservoir

One of the existing tight oil reservoir development methods is development after hydraulic fracturing of horizontal wells. This type of development method severely limits the recovery rate of tight oil reservoirs. The other conventional enhanced oil recovery methods are not suitable for tight oil reservoirs. The water injection performance of fractured vertical wells is poor, and water breakthrough easily occurs during water injection in horizontal wells. In order to improve the recovery factor of tight oil reservoirs and to achieve sustainable development of tight oil reservoirs, finding a suitable method of enhancing the recovery factor of tight oil reservoirs is the top priority. Based on the concept of periodic asynchronous water flooding to supplement energy between horizontal fractures, in this paper, an effective method of improving the recovery rate of tight oil reservoirs is discussed. Physical simulation experiments were designed to improve the recovery efficiency of horizontal wells with an inter-fracture asynchronous injection-production cycle (IFAIPC). The feasibility of the method was verified. Two different sets of experiments were designed: 1) the experiment that simulates a homogeneous reservoir with a section with two fractures (M1), and 2) an experiment that simulates a heterogeneous reservoir with three sections of four fractures (M2) and the fourth section with five fractures (M3). The results show that during the IFAIPC process, the permeability of the rock sample tends to decrease gradually. In particular, in the first five cycles, the permeability decreases significantly. Water injection becomes difficult as the permeability decreases, and there is a feasible critical value for water injection. In homogeneous reservoirs, water breakthrough is slow. The degree of recovery and the ultimate recovery rate before water breakthrough are high. The use of IFAIPC in heterogeneous reservoirs can effectively increase the swept volume and delay the rise of water saturation. The IFAIPC method can effectively improve the recovery of tight oil reservoirs by more than 10% in the first five injection-production cycles. The experiments confirm the feasibility and effectiveness of using the IFAIPC method in tight oil reservoirs.

An analytical tool to forecast horizontal well injectivity in viscous oil polymer floods

Injection rate is a key factor for successful polymer floods of viscous oil reservoirs. Injectivity during polymer flooding is lower compared to waterflooding due to the viscosity of polymer solution. Accurate estimation of injection rate/pressure build-up due to polymer injection is essential to evaluation and design of polymer flood projects. Typically, a short-term polymer injectivity test is performed on a single well, but it is hard to extrapolate future behavior of polymer injectivity because the tests are often too short. Reservoir simulation can be used to forecast injectivity, but the grid size and radial flow often affect the calculated injectivity. Analytical methods provide simple and quick ways to estimate injectivity using realistic reservoir conditions. The goal of this work is to develop an analytical tool and demonstrate its applicability by comparison with field data. An analytical solution is developed for the injectivity of horizontal wells in polymer floods in viscous oil reservoirs. The analytical solution is validated by comparing it to a numerical field-scale box model simulation. The pressure profiles are calculated using spreadsheets and compared against the data from several fields with increasing degrees of complexity. In each case, the analytical-spreadsheet method provides close matches of injection pressure data. This analytical tool can be used for preliminary design of polymer floods before getting into more complex and time-consuming reservoir simulations. • Developed an analytical solution for injectivity in viscous oil polymer floods. • Compared the analytical solution to numerical simulation with grid refinement. • Compared analytical solution to field data from 5 wells. • Novel tool to design and optimize polymer floods in viscous oil reservoirs.

Polymerflood Field Pilot Enhances Recovery of Heavy Oils on the Alaska North Slope

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201279, “First-Ever Polymerflood Field Pilot To Enhance the Recovery of Heavy Oils on the Alaska North Slope: Producer Responses and Operational Lessons Learned,” by Samson Ning, SPE, Reservoir Experts and Hilcorp Alaska, and John Barnes, SPE, and Reid Edwards, SPE, Hilcorp Alaska, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5-7 October. The paper has not been peer reviewed. The complete paper describes a field pilot project to perform an experiment to validate the use of an advanced polymerflooding technology on the Alaska North Slope. Polymer injectivity of horizontal wells is found to be sufficient to replace reservoir production voidage, although some declines occurred as high-viscosity polymer swept the near-wellbore region. Production data show significant reduction in water cut and increase in oil production rate. No polymer production has been confirmed from the two horizontal producers after 23 months of polymer injection into the two supporting horizontal injectors. Introduction The pilot involves two horizontal injectors (J-23A and J-24A) and two horizontal producers (J-27 and J-28) drilled into the Schrader Bluff NB sand in an isolated fault block of the Schrader Bluff heavy-oil reservoir in the Milne Point field. The lengths of the horizontal wellbores range from 4,200 to 5,500 ft, and the interwell distance is approximately 1,100 ft. Hydrolyzed polyacrylamide (HPAM) polymer injection began on 28 August 2018 using a custom polymer mixing and pumping unit. Polymer-solution quality control is discussed in detail in the complete paper. Injector Performance Since the start of polymer injection, a few shutdown events have occurred that lasted longer than 2 weeks. The first major shutdown took place in September 2018, when a more-than-expected amount of hydrocarbon gas was detected from the source water used to make the polymer solution. The polymer-injection facility was shut down for 3 weeks to modify the pressure-letdown module for operation safety. The second major shutdown occurred in November 2018 for pump and auger repairs. The third major shutdown happened from mid-June through late August of 2019 because of polymer-solution-quality issues. After 2 months of diligent work, the polymer-hydration problem was resolved and improvements made in polymer facilities, operational procedures, and the onsite quality-control process. Polymer-injection operations have been smooth since August 2019 except for a few short shutdowns for equipment maintenance. As of late May 2020, total cumulative polymer injected was 708,000 lbm into the two injectors, and the total amount of polymer solution injected was 1.4 million bbl, approximately 8.8% of the total pore volume in the two flood patterns. Since polymer injection began, injected polymer concentration was mostly between 1,500 and 2,000 ppm to achieve a target viscosity initially set at 45 cp and then reduced to 40 cp.

A model for nitrogen injection in horizontal wells of tight oil reservoirs

ABSTRACT In the petroleum industry, nitrogen is often used to improve the recovery of unconventional oil and gas resources such as heavy oil, tight oil, and shale oil. When nitrogen is injected into the oil and gas layers along the horizontal section of the wellbore, its pressure and temperature and other physical parameters all change with coordinates and time. These changes of pressure and temperature will have certain impact on the recovery efficiency. Therefore, it is necessary to simulate the non-isothermal variable mass pipe flow process of nitrogen in the horizontal wellbore. Based on the principles of conservation of energy and momentum, this paper establishes a nitrogen flow model in the horizontal wellbore by coupling sub-models such as the reservoir suction model. Results show that: (a) when the number of grids reaches 100, the degree of agreement between the predicted pressure value and the measured value of the model has met the requirements of engineering calculation accuracy. (b) when the injection pressure is lower than 2.7 MPa, the temperature gradient at the heel end and toe end of the wellbore is similar, while when the injection pressure is high (equal to 2.9 MPa), the temperature gradient at the toe end of the wellbore is significantly higher than that at the heel end.

A visualized investigation on the mechanisms of anti-water coning process using nitrogen injection in horizontal wells

Horizontal wells have been widely used in oil reservoirs with bottom aquifer. As bottom water coning occurs, water cut of the production well rises sharply and the output declines rapidly. In this paper, an experimental study on the mechanism of anti-water coning and oil production increment by injecting nitrogen in horizontal wells was carried out. A theory of bubbling behaviors induced by gas permeating through a porous medium is skillfully applied to analyze the mechanisms of anti-water coning by injecting nitrogen. A series of visual experiments and a one-dimensional displacement experiment are conducted to intuitively study bubble characteristics and blocking mechanisms in porous media, as well as the microscopic mechanisms of the improvement of well performance by injecting nitrogen. The results show that there are three forms of nitrogen in the water channeling path: tiny bubble, elongated bubble, and gas channeling, which are related to water saturation and gas injection volume in the water channel. Elongated bubble, the main mechanism of anti-water coning by injecting nitrogen, can block high-permeable water channeling path to a certain extent. As the viscosity of crude oil increases, the negative effect of anti-water coning and the increment of bottom water sweeping range show up. It is suitable for non-homogeneous reservoirs, which is conducive to the exploitation of oil on the top layer in low permeability oil region. It can also largely increase the sweeping area of bottom water in low permeability reservoirs. But for high permeability formation, water suppression effect is poor. The earlier the injection of nitrogen gas, the better the effect of inhibiting water encroachment which can even reduce the water cut to zero. However, the effect of oil production increment will be not that good. This paper provides reference for the study in anti-water coning and increasing oil production by injecting nitrogen through the horizontal wells.

Water-out performance and pattern of horizontal wells for marine sandstone reservoirs in Tarim Basin, NW China

Abstract Based on geological analysis, reservoir numerical simulation and production performance analysis, water-out performance and pattern of horizontal wells in Tarim marine sandstone reservoir were studied. Compared with continental sandstone reservoirs, the marine sandstone reservoirs in Tarim Basin were characterized by low oil viscosity, good reservoir continuity, and development of interbeds, which together with the large amount of horizontal wells, resulted in fast production rate and high recovery degree of the reservoirs. The main controlling factors of uneven water-out in horizontal wells were reservoir seepage barrier, injection-production well pattern, and dominant seepage channel. Thus 9 types in 4 categories of typical water-out pattern of horizontal wells in Tarim marine sandstone reservoirs were identified, and water-out management measures were proposed for them respectively according to their water-out mechanism and remaining oil distribution characteristics. Finally, the water-out pattern can be identified based on the inflection characteristics of derivative curve of water-oil ratio. This study of the water-out pattern can provide guidance for the adjustment policy of water injection in horizontal wells in marine sandstone reservoirs of Tarim Oilfield.

Numerical Simulation of Steam Injection for Heavy Oil Thermal Recovery

The steam injection technology is widely used in heavy oil production. The higher the steam injection rate is, the more beneficial the exploitation of heavy oil is. In this paper, we choose the twodimensional rotation axis symmetry model, using VOF model of steam injection wells, wet steam phase change, transient analysis of influence of different injection pipe string structure in vertical well section during the process of steam injection on steam injection parameters and changes of single and dual steam injection steam injection well bore in steam parameters during the process of steam injection in horizontal wells. The analysis results show that the vertical well steam injection by high vacuum insulated tubing make minimize the dryness of the steam; Toe end dry degree is higher than that of single tube steam injection when horizontal pipe steam injection, which is conducive to the balanced development of heavy oil.

Thermophysical properties estimation and performance analysis of superheated-steam injection in horizontal wells considering phase change

The objectives of this work are to establish a comprehensive mathematical model for estimating thermophysical properties and to analyze the performance of superheated-steam injection in horizontal wells. In this paper, governing equations for mass flow rate and pressure drop are firstly established according to mass and momentum balance principles. More importantly, phase change behavior of superheated steam is taken into account. Then, implicit equations for both the degree of superheat and steam quality are further derived based on energy balance in the wellbore. Next, the mathematical model is solved using an iterative technique and a calculation flowchart is provided. Finally, after the proposed model is validated by comparison with measured field data, the effects of some important factors on the profiles of thermophysical properties are analyzed in detail. The results indicate that for a given degree of superheat, the mass flow rate drops faster after superheated steam is cooled to wet steam. Secondly, to ensure that the toe section of horizontal well can also be heated effectively, the injection rate should not be too slow. Thirdly, the mass flow rate and the degree of superheat in the same position of horizontal wellbore decrease with injection pressure. Finally, it is found that when reservoir permeability is high or oil viscosity is low, the mass flow rate and the degree of superheat decline rapidly.