Monitoring Polymer Flooding Performance Using Inflow Tracer Technology in Horizontal Injection and Production Wells

2021 ◽  
pp. 1-18
Author(s):  
Alyssia Janczak ◽  
Gaute Oftedal ◽  
Ehsan Nikjoo ◽  
Michaela Hoy ◽  
Christoph Puls ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Produced Water ◽  
Spatial Information ◽  
Numerical Models ◽  
Horizontal Wells ◽  
Injection Well ◽  
Efficient Production ◽  
Injection Wells ◽  
Polymer Injection ◽  
Production Wells

Summary Horizontal wells are frequently used to increase injectivity and for cost-efficient production of mobilized oil in polymer-augmented waterfloods. Usually, only fluid and polymer production data at the wellhead of the production well are available. We used inflow tracer technology to determine changes in hydrocarbon influx owing to polymer injection and to determine the connection from various zones of the horizontal injector to the horizontal producer. Inflow tracer technology was introduced in horizontal polymer injection and production wells. In the production wells, tracers are released when they are contacted by water and oil. Oil and water tracer systems were used in the horizontal production wells. The changes in the observed tracer concentration were used to quantify changes in influx from various sections of the horizontal producers owing to polymer injection. The inflow tracer technology applied in the horizontal injection wells demonstrates connectivity between different sections of the injection wells and two surrounding vertical and horizontal production wells and opens the usage of this technology for interwell water tracer applications. Inflow tracer technology enables one to elucidate the inflow from various sections of the horizontal wells and the changes thereof, even quantifying changes in influx of various fluids (oil and water). The information shows which sections are contributing and the substantial changes in the influx of oil from the various zones due to polymer solution injection. The overall incremental oil could be allocated to the various horizontal well sections based on the tracer results. Even zones that almost exclusively produced water before polymer injection showed a significant increase in oil influx. The inflow tracer technology installed in the injection well allowed us to analyze the connectivity of the injector to producer not only globally but spatially along the horizontal well. These data are used for reservoir characterization, to condition numerical models, and for reservoir management. Conventional interwell tracer technology allows one to determine the connectivity and connected volumes of horizontal well polymer field developments. However, it reveals neither information about influx of the sections nor the connectivity of various sections of the horizontal wells. Inflow tracer technology closes this gap; it allows one to quantify changes in influx of the fluids. Furthermore, the newly developed installed injection well tracer technology gives spatial information about the connectivity of the horizontal well sections.

Successful Development and Deployment of a Novel Chemical Package for Stimulation of Injection wells, Offshore UK

2021 ◽  
Author(s):  
Dennis Alexis ◽  
Gayani Pinnawala ◽  
Do Hoon Kim ◽  
Varadarajan Dwarakanath ◽  
Ruth Hahn ◽  
...  
Keyword(s):  
Product Quality ◽  
Injection Well ◽  
Concentrated Solutions ◽  
Successful Development ◽  
Injection Wells ◽  
Polymer Injection ◽  
Remediation Process ◽  
Field Location ◽  
Stimulation Of ◽  
Injection Rates

Abstract The work described in this paper details the development of a single stimulation package that was successfully used for treating an offshore horizontal polymer injection well to improve near wellbore injectivity in the Captain field, offshore UK. The practice was to pump these concentrated surfactant streams using multiple pumps from a stimulation vessel which is diluted with the polymer injection stream in the platform to be injected downhole. The operational challenges were maintaining steady injection rates of the different liquid streams which was exacerbated by the viscous nature of the concentrated surfactants that would require pre-dilution using cosolvent or heating the concentrated solutions before pumping to make them flowable. We have developed a single, concentrated liquid blend of surfactant, polymer and cosolvent that was used in near-wellbore remediation. This approach significantly simplifies the chemical remediation process in the field while also ensuring consistent product quality and efficiency. The developed single package is multiphase, multicomponent in nature that can be readily pumped. This blend was formulated based on the previous stimulation experience where concentrated surfactant packages were confirmed to work. Commercial blending of the single package was carried out based on lab scale to yard scale blending and dilution studies. About 420 MT of the blend was manufactured, stored, and transported by rail, road and offshore stimulation vessel to the field location and successfully injected.

Simulating Carbon Dioxide Sequestration/ECBM Production in Coal Seams: Effects of Permeability Anisotropies and Other Coal Properties

2005 ◽  
Vol 8 (02) ◽  
pp. 156-163 ◽  
Author(s):  
Duane H. Smith ◽  
Grant Bromhal ◽  
W. Neal Sams ◽  
Sinisha Jikich ◽  
Turgay Ertekin
Keyword(s):  
Carbon Dioxide ◽  
Methane Production ◽  
Coalbed Methane ◽  
Co2 Sequestration ◽  
Horizontal Wells ◽  
Coal Seams ◽  
Injection Wells ◽  
Sequestration Potential ◽  
Production Wells ◽  
The Face

Summary Coalbed methane now accounts for a significant fraction of domestic natural-gas production. Injection of carbon dioxide (CO2) into coal seams is a promising technology for reducing anthropogenic greenhouse-gas emissions and increasing ultimate production of coalbed methane. Reservoir simulations are an inexpensive method for designing field projects and predicting optimal tradeoffs between maximum sequestration and maximum methane production. Optimum project design and operation are expected to depend on the anisotropy of the permeability along the face-cleat and butt-cleat directions, the spacing between cleats, and the sorption isotherms for methane and CO2. In this work, a dual-porosity coalbed-methane simulator is used to model primary and secondary production of methane from coal for a variety of coal properties and operational parameters. It is assumed that the face and butt cleats are perpendicular to each other, with horizontal wells parallel to one type of cleat and perpendicular to the other. The well pattern consists of four horizontal production wells that form a rectangle, with four shorter horizontal wells centered within the rectangle. In the limiting case of no permeability anisotropy, the central wells form a "plus" sign within the square of production wells. All wells are operated as producers of methane and water until a specified reservoir pressure is reached, after which the central wells are operated as injectors for CO2. Production of methane continues until the CO2 concentration in the produced gas is too high. The simulation results predict the optimum lengths of the injection wells along the face- and butt-cleat directions and show how these optimum lengths depend on the permeabilities in the two directions. If the cleat spacing is sufficiently small, and diffusion of the gas through the pores to the cleats is sufficiently rapid, instantaneous sorption may be assumed. Otherwise, the field performance depends on the diffusion-time constant that characterizes the rate of transfer between the cleats and the coal matrix. The pressures at which the injection wells are operated also affect the amounts of CO2 sequestered through the pressures and volumes of the sorption isotherms. Introduction and Background Increasing concentrations of greenhouse gases may be leading to changes in the Earth's climate. A rise in the globe's average temperature is expected, among other consequences. The main anthropogenic greenhouse gas is CO2. The concentration of CO2 in the atmosphere is increasing continuously; therefore, many countries have pledged to reduce, by 2010, the emissions of greenhouse gases up to 8% relative to levels pertaining to 1990. Consequently, CO2 must be captured and stored. Among storage options, the underground storage in depleted oil and gas reservoirs and unmineable coals is considered to have the most favorable economics. This option is also expected to have a low environmental impact. Several federal agencies have major programs for CO2sequestration. Unmineable coal seams are a very attractive potential storage medium forCO2. The injection of CO2 in coalbeds may be the most efficient option of all storage possibilities if, while CO2 is stored, the recovery of coalbed methane is improved. The process of displacing the remaining methane by CO2 after the primary production of methane is referred to as enhanced coalbed methane(ECBM). Carbon dioxide/ECBM technology and implementation were inspired by CO2solvent flooding, one of the most successful enhanced-oil-recovery methods in the U.S. and worldwide. The worldwide CO2-sequestration potential by use of ECBM has been estimated at 150 Gt of CO2. A relatively small but significant sequestration potential of 5 to 15 Gt may be profitable, generating net profits estimated at U.S. $15/t for the most favorable cases. A joint U.S. Dept. of Energy (DOE) and industry project has been initiated to study the reservoir mechanisms and field performance of CO2 sequestration in the world's first experimental (pure) CO2/ECBM recovery pilot, the Allison unit field, operated by Burlington Resources. Initially, the pilot was intended to test CO2/ECBM, but in time it evolved into a CO2-sequestration project. The pilot consists of four CO2-injection wells and nine methane-production wells, drilled on 320-acre spacing. The Allison unit CO2/ECBM shows that methane production has been enhanced by CO2 injection and that CO2 has been sequestered. In this project, vertical wells are used for both production and injection. However, it has been shown that horizontal wells can increaseCO2-injection rate and improve aerial sweep, which can lead to more-favorable flood economics. The sweep advantage is greatest in thin formations with wide well spacing, such as coal seams in the eastern United States. Consequently, the U.S. Dept. of Energy is cofunding a 7-year CO2-sequestration/ECBM project that uses horizontal injectors and producers. The well pattern used in the present study was suggested by the pattern chosen for that project.

Enhanced Geothermal System Model for Flow through a Stimulated Rock Volume

2021 ◽  
Author(s):  
Leila Zeinali ◽  
Christine Ehlig-Economides ◽  
Michael Nikolaou
Keyword(s):  
Heat Transfer ◽  
High Temperature ◽  
Power Plant ◽  
Horizontal Well ◽  
Numerical Models ◽  
Horizontal Wells ◽  
Geothermal System ◽  
Enhanced Geothermal System ◽  
Well Pattern ◽  
Flow Through

Abstract An Enhanced Geothermal System (EGS) uses flow through fractures in an effectively impermeable high-temperature rock formation to provide sustainable and affordable heat extraction that can be employed virtually anywhere with no need for a geothermal reservoir. The problem is that there is no commercial application of this technology. The three-well pattern introduced in this paper employs a multiple transverse fractured horizontal well (MTFHW) drilled and fractured in an effectively impermeable high-temperature formation. Two parallel horizontal wells drilled above and below or on opposing sides of the MTFHW have trajectories that intersect its created fractures. Fluid injected in the MTFHW flows through the fractures and horizontal wells, thus extracting heat from the surrounding high-temperature rock. This study aims to find the most cost-effective well and fracture spacing for this pattern to supply hot fluid to a 20-megawatt power plant. Analytical and numerical models compare heat transfer behavior for a single fracture unit in an MTFHW that is then replicated along with the horizontal well pattern(s). The Computer Modeling Group (CMG) STARS simulator is used to model the circulation of cold water injected into the center of a radial transverse hydraulic fracture and produced from two horizontal wells. Key factors to the design include formation temperature, the flow rate in fractures, the fractured radius, spacing, heat transfer, and pressure loss along the wells. The Aspen HYSYS software is used to model the geothermal power plant, and heat transfer and pressure loss in wells and fractures. The comparison between analytical and numerical models showed the simplified analytical model provides overly optimistic results and indicates the need for a numerical model. Sensitivity studies using the numerical model vary the key design factors and reveal how many fractures the plant requires. The economic performance of several scenarios was investigated to minimize well drilling and completion pattern costs. This study illustrates the viability of applying known and widely used well technologies in an enhanced geothermal system.

The Use of Tracer Data To Determine Polymer-Flooding Effects in a Heterogeneous Reservoir, 8 Torton Horizon Reservoir, Matzen Field, Austria

2016 ◽  
Vol 19 (04) ◽  
pp. 655-663 ◽  
Author(s):  
Torsten Clemens ◽  
Markus Lüftenegger ◽  
Ajana Laoroongroj ◽  
Rainer Kadnar ◽  
Christoph Puls
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Flow Path ◽  
Injection Well ◽  
Critical Parameters ◽  
Pilot Projects ◽  
Sweep Efficiency ◽  
Full Field ◽  
Polymer Injection ◽  
Production Wells

Summary Polymer-injection pilot projects aim at reducing the uncertainty and risk of full-field polymer-flood implementation. The interpretation of polymer-pilot projects is challenging because of the complexity of the process and fluids moving out of the polymer-pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir. In the polymer pilot performed in the 8 Torton Horizon (TH) reservoir of the Matzen field in Austria, a polymer-injection well surrounded by a number of production wells was selected. A tracer was injected 1 week before polymer injection. The tracer showed that the flow field in the reservoir was dramatically modified with increasing amounts of polymer injected. Despite short breakthrough times of 4 to 10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates were not substantially changed. The tracer signal indicated that the reservoir is heterogeneous, with high flow velocities occurring along a number of flow paths with a limited volume that are strongly connecting the injection and production wells. By injecting polymers, the mobility of the polymer-augmented water was reduced compared with water injection, and led to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymer injected. This response was used to assess the changes of the amount of water flowing from the injection well to production wells. After a match for the tracer curve was obtained, adsorption, residual resistance factor (RRF), and dispersivity were calculated. The results showed that, even for heterogeneous reservoirs without good conformance of the pilot, the critical parameters for polymer-injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive. Along the flow path that is connecting injection and production well, as shown by the tracer response, an incremental recovery of approximately 8% was achieved. The polymer retention and inaccessible pore volume (IPV) in the reservoir were in the same range as in corefloods. Incremental oil recovery caused by acceleration along the flow path was estimated at approximately 20% of the overall incremental oil production caused by polymer injection and 80% was attributed to improved sweep efficiency.

scholarly journals Production Data Analysis and Sonolog for Determining Artificial Lift Design and Well Characteristic

2020 ◽  
Vol 1 (1) ◽  
pp. 28
Author(s):  
Bambang Bintarto ◽  
Rizky Rahmat Auliya ◽  
Riza Andhika Mahendra Putra ◽  
Afif Surya Pradipta ◽  
Rafli Arie Kurnia
Keyword(s):  
Produced Water ◽  
Submersible Pump ◽  
Water Control ◽  
Injection Wells ◽  
Diagnostic Plot ◽  
Artificial Lift ◽  
Production Wells ◽  
Production History ◽  
Electric Submersible Pump

Tarakan Field, North Kalimantan is a part of PT. Pertamina EP Asset 5. The Tarakan Field has 5 structures in the form of Pamusian, Juata, Sesanip, Mangatal, and Sembakung. The Tarakan Field has 57 production wells and 6 injection wells. The wells at Tarakan field are produced with artificial lifts in the form of Sucker Rod Pump (SRP) totaling 25, Hydraulic Pumping Unit (HPU) totaling 11, Electric Submersible Pump (ESP) totaling 19 and Progressive Cavity Pump (PCP) totaling 2. The determination of artificial lifts is carried out by the design of well characteristics and production history. The design at Tarakan Field was carried out with an artificial lift in the form of ESP (Electric Submersible Pump). ESP is used according to reservoir and formation characteristics in Tarakan Field. Water Control Diagnostic Plot is a method used to analyze the effect of control on produced water. Water Control Diagnostic plot is plot between WOR and WOR derivative vs time. The plot was carried out on a log-log scale. The plot on the Water Control Diagnostic Plot is then analyzed against the graph created by the KS Chan. So from the analyzed plot, it is found whether or not there is a problem in the well at Tarakan Field. The results of the graph analysis on the well at Tarakan Field on the chart show that the field does not indicate a problem. Keywords: chan plot; design; esp; production

The Technology Limits for Stratified Injection of Polymer Flooding

2015 ◽  
Vol 1094 ◽  
pp. 433-436
Author(s):  
Qi Sun ◽  
Jing Yang ◽  
Li Yan Sun ◽  
Xiu Long Dong
Keyword(s):  
Class Ii ◽  
Scientific Basis ◽  
Polymer Flooding ◽  
Injection Well ◽  
Injection Wells ◽  
Development Zone ◽  
Polymer Injection ◽  
Geological Conditions ◽  
Injection Technology ◽  
Separate Injection

At present the development of Daqing Oilfield has entered the water pick-up period, and the polymer separate injection technology for the injection well is urgent needed. However, the difficulty of selecting well and lever for the separate injection of the injection well is relatively large due to the complexity of the Class II reservoir of geological conditions. So for The limits of technology of the geological features, the limits of technology injection of stratified polymer injection for the Class II reservoir provides a scientific basis for the development of oil fields.In this paper, taking Daqing Oilfield Sabei Development Zone as example, establish the mathematical model of polymer flooding. Determine the well and layer selection principles of layered polymer injection wells in the ClassIIreservoir timing. According to the current development situation, give the decrease in water content and the improvement value in recovery under a given measure.Through this paper, we have got production effect of layered polymer injection in the Class II reservoir of Sabei area and given quantified layered polymer injection technology limits.

scholarly journals The shift of microbial population composition accompanying the injected water flowing in the water-flooding petroleum reservoirs

2014 ◽  
Vol 11 (12) ◽  
pp. 16773-16797 ◽  
Author(s):  
P. K. Gao ◽  
G. Q. Li ◽  
H. M. Tian ◽  
Y. S. Wang ◽  
H. W. Sun ◽  
...  
Keyword(s):  
Dissolved Oxygen ◽  
Produced Water ◽  
Water Flooding ◽  
Microbial Populations ◽  
Petroleum Reservoir ◽  
Injection Wells ◽  
Production Wells ◽  
Sieve Effect ◽  
Pass Through ◽  
A Minor

Abstract. In water-flooding petroleum reservoir, microbial populations in injected water are expected to migrate into oil-bearing strata and reach production wells. To demonstrate this, we firstly investigated microbial compositions in a homogeneous sandstone reservoir. The results indicated that the injected water harbored more microbial cells than produced water, and the shared populations and their abundance accounted for a minor fraction in injected water, while dominated in produced water, suggesting that most populations in injected water did hardly reach production wells in this reservoir. We further investigated microbial communities in water samples collected from wellhead and downhole of injection wells and production wells in a heterogeneous conglomerate reservoir. The results indicated that, except for the community reconstruction mainly resulted from dissolved oxygen, most populations were simultaneously detected in the wellhead and downhole of injection wells and production wells, suggesting that most microbial populations in injected water reached the production wells. This study suggest that microbial populations in injected water can pass through reservoir strata and reach production wells, but the reservoir heterogeneity, interwell spacing, sieve effect of strata and dissolved oxygen exert significant influence on microbial migration and distribution in reservoirs.

scholarly journals Geothermal Boreholes in Poland—Overview of the Current State of Knowledge

Energies ◽  
2021 ◽  
Vol 14 (11) ◽  
pp. 3251
Author(s):  
Tomasz Sliwa ◽  
Aneta Sapińska-Śliwa ◽  
Andrzej Gonet ◽  
Tomasz Kowalski ◽  
Anna Sojczyńska
Keyword(s):  
Heat Exchangers ◽  
Oil And Gas ◽  
Produced Water ◽  
Geothermal Water ◽  
Laboratory System ◽  
Water Production ◽  
Injection Wells ◽  
Geological Conditions ◽  
Geothermal Wells ◽  
Borehole Heat Exchangers

Geothermal energy can be useful after extraction from geothermal wells, borehole heat exchangers and/or natural sources. Types of geothermal boreholes are geothermal wells (for geothermal water production and injection) and borehole heat exchangers (for heat exchange with the ground without mass transfer). The purpose of geothermal production wells is to harvest the geothermal water present in the aquifer. They often involve a pumping chamber. Geothermal injection wells are used for injecting back the produced geothermal water into the aquifer, having harvested the energy contained within. The paper presents the parameters of geothermal boreholes in Poland (geothermal wells and borehole heat exchangers). The definitions of geothermal boreholes, geothermal wells and borehole heat exchangers were ordered. The dates of construction, depth, purposes, spatial orientation, materials used in the construction of geothermal boreholes for casing pipes, method of water production and type of closure for the boreholes are presented. Additionally, production boreholes are presented along with their efficiency and the temperature of produced water measured at the head. Borehole heat exchangers of different designs are presented in the paper. Only 19 boreholes were created at the Laboratory of Geoenergetics at the Faculty of Drilling, Oil and Gas, AGH University of Science and Technology in Krakow; however, it is a globally unique collection of borehole heat exchangers, each of which has a different design for identical geological conditions: heat exchanger pipe configuration, seal/filling and shank spacing are variable. Using these boreholes, the operating parameters for different designs are tested. The laboratory system is also used to provide heat and cold for two university buildings. Two coefficients, which separately characterize geothermal boreholes (wells and borehole heat exchangers) are described in the paper.

A New Method of Fall-Off Test in Water Injection Well in Tahe Oilfield

2013 ◽  
Vol 807-809 ◽  
pp. 2508-2513
Author(s):  
Qiang Wang ◽  
Wan Long Huang ◽  
Hai Min Xu
Keyword(s):  
Water Injection ◽  
Injection Well ◽  
Well Test ◽  
Well Bore ◽  
Residual Oil ◽  
Injection Wells ◽  
Oil Saturation ◽  
Tahe Oilfield ◽  
Fitting Method ◽  
Front Radius

In pressure drop well test of the clasolite water injection well of Tahe oilfield, through nonlinear automatic fitting method in the multi-complex reservoir mode for water injection wells, we got layer permeability, skin factor, well bore storage coefficient and flood front radius, and then we calculated the residual oil saturation distribution. Through the examples of the four wells of Tahe oilfield analyzed by our software, we found that the method is one of the most powerful analysis tools.

The Interpretation Technique of Rate Transient Analysis Data in Fractured Horizontal Wells

2021 ◽  
Author(s):  
Ruslan Rubikovich Urazov ◽  
Alfred Yadgarovich Davletbaev ◽  
Alexey Igorevich Sinitskiy ◽  
Ilnur Anifovich Zarafutdinov ◽  
Artur Khamitovich Nuriev ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Transient Analysis ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Data Interpretation ◽  
Analysis Data ◽  
Well Logging ◽  
Rate Transient Analysis ◽  
Fractured Horizontal Well ◽  
Fractured Horizontal Wells

Abstract This research presents a modified approach to the data interpretation of Rate Transient Analysis (RTA) in hydraulically fractured horizontal well. The results of testing of data interpretation technique taking account of the flow allocation in the borehole according to the well logging and to the injection tests outcomes while carrying out hydraulic fracturing are given. In the course of the interpretation of the field data the parameters of each fracture of hydraulic fracturing were selected with control for results of well logging (WL) by defining the fluid influx in the borehole.

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