Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

SPE Journal ◽  
2022 ◽  
pp. 1-18
Author(s):  
Marat Sagyndikov ◽  
Randall Seright ◽  
Sarkyt Kudaibergenov ◽  
Evgeni Ogay
Keyword(s):  
Polymer Solutions ◽  
Mechanical Stability ◽  
Field Operator ◽  
Oil Field ◽  
Low Flow ◽  
Mechanical Degradation ◽  
Injection Wells ◽  
Polymer Injection ◽  
Step Rate ◽  
The Impact

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

Online Modeling of CO2 Storage Systems

2021 ◽  
Author(s):  
Dale Douglas Erickson ◽  
Greg Metcalf
Keyword(s):  
Co2 Storage ◽  
Free Water ◽  
Oil Field ◽  
Management Tool ◽  
Carbon Dioxide Injection ◽  
Injection Wells ◽  
Internal Corrosion ◽  
Injection Process ◽  
Corrosion Risk ◽  
The Impact

Abstract This paper discusses the development and deployment of a specialized online and offline integrated model to simulate the CO2 (Carbon Dioxide) Injection process. There is a very high level of CO2 in an LNG development and the CO2 must be removed in order to prepare the gas to be processed into LNG. To mitigate the global warming effects of this CO2, a large portion of the CO2 Rich Stream (98% purity) is injected back into a depleted oil field. To reduce costs, carbon steel flowlines are used but this introduces a risk of internal corrosion. The presence of free water increases the internal corrosion risk, and for this reason, a predictive model discussed in this paper is designed to help operations prevent free water dropout in the network in real time. A flow management tool (FMT) is used to monitor the current state of the system and helps look at the impact of future events (startup, shutdowns etc.). The tool models the flow of the CO2 rich stream from the outlet of the compressor trains, through the network pipeline and manifolds and then into the injection wells. System behavior during steady state and transient operation is captured and analyzed to check water content and the balance of trace chemicals along with temperature and pressure throughout the network helping operators estimate corrosion rates and monitor the overall integrity of the system. The system has been running online for 24/7 for 2 years. The model has been able to match events like startup/shutdown, cooldowns and blowdowns. During these events the prediction of temperature/pressure at several locations in the field matches measured data. The model is then able to forecasts events into the future to help operations plan how they will operate the field. The tool uses a specialized thermodynamic model to predict the dropout of water in the near critical region of CO2 mixtures which includes various impurities. The model is designed to model startup and shutdown as the CO2 mixture moves across the phase boundary from liquid to gas or gas to liquid during these operations.

scholarly journals Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

2021 ◽  
Author(s):  
Tongchun Hao ◽  
Liguo Zhong ◽  
Jianbin Liu ◽  
Xiaodong Han ◽  
Tianyin Zhu ◽  
...  
Keyword(s):  
Production Efficiency ◽  
Design Method ◽  
Water Injection ◽  
Oil Field ◽  
Productivity Index ◽  
Injection Wells ◽  
Wellhead Pressure ◽  
Production Wells ◽  
Drilling Operations ◽  
The Impact

AbstractAffected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

Evaluation of the Influence of the Facies Genesis of the Reservoir Unit of the Fainsk Oil Field YUS1 Facility on the Effectiveness of Integrated Processing of the Injection Wells Bottomhole Formation Zone with the Application of Acid Compositions

2018 ◽  
Vol 785 ◽  
pp. 1-10
Author(s):  
Vadim Aleksandrov ◽  
Marsel Kadyrov ◽  
Andrey Ponomarev ◽  
Denis Drugov ◽  
Evgeniya Neelova
Keyword(s):  
Acid Composition ◽  
Process Parameters ◽  
Development Process ◽  
Geological Structure ◽  
Oil Field ◽  
Injection Wells ◽  
Formation Zone ◽  
Integrated Processing ◽  
The Impact ◽  
Practical Recommendations

One of the main problems with the bottomhole formation zone processing is the choice of an acid composition adapted to the peculiarities of the geological structure of the facility. The highest technological effect of the geological and technical interventions using physicochemical formation stimulation techniques is achieved when the genesis of processed deposits is taken into account during the process of treatment planning. The research objective is to assess the impact of the reservoir units formation (genesis) characteristics on the effectiveness of integrated processing of the bottomhole formation zone of injection wells with the application of acid compositions. Using the geological and routine analysis of the development process parameters for deposits located in various facies zones, the operational benefits of the bottomhole formation zone integrated treatments in injection wells were evaluated and practical recommendations were provided.

Design and Execution of the First Large-Scale Polymer Injection Pilot in Sirikit Oil Field

2021 ◽  
Author(s):  
Weeraya Wuttipittayamongkol ◽  
Pannapon Trinavarat ◽  
Warisa Nuntaprayoon ◽  
Monrawee Pancharoen ◽  
Rapheephan Laochamroonvorapongse
Keyword(s):  
Large Scale ◽  
Oil Field ◽  
Production Performance ◽  
Water Flooding ◽  
Small Scale ◽  
Mechanical Degradation ◽  
Close Monitoring ◽  
Polymer Injection ◽  
Fluid Saturation ◽  
Water Cut

Abstract Becoming more mature with field-wide water flooding implementation for more than 30 years, Sirikit Oil Field (S1) is going forward to the next rejuvenating step of enhanced oil recovery (EOR). Generally, the field contains light oil (40° API) in highly stratified sand-shale sequences with low net-to-gross ratios. High reservoir temperature, low permeability, and high water cut observed from production make it even more challenging for polymer injection projects. Nonetheless, the success from a small-scale field trial has shown a promising future of EOR application in the field and brought an execution of the first large-scale polymer injection pilot. Polymer screening laboratory tests, a reservoir simulation study, data acquisition program and techniques, injectivity tests, polymer injection unit design, and risk assessment were parts of the pilot preparation, in which the key learnings from the previous pilot have been incorporated. The gathering and determination of baseline parameters including production performance, injection profiles, reservoir fluid saturation profiles, etc., were registered for ultimate evaluation. Then, the continuous polymer injection has been started since October 2019 in two separated fault blocks where 12 injectors and 20 producers are located in different injection patterns. During several months of polymer injection, both foreseen and unforeseen changes have enlivened the pilot management. Although the injectivity test with polymer solution prior to the pilot demonstrated no injection difficulty, several wells have shown injectivity deterioration with time. Mechanical degradation is induced in these wells by the installation of flow restriction devices to lessen solution viscosity and, hence, prolong polymer injectivity. Well integrity issues and artificial lift breakdown negatively affect field production and close-in wells make it harder for voidage replacement control. Immediate troubleshooting and close monitoring have been placed and eventually leads to the recognition of encouraging results. Polymer helps improve vertical injection profiles as seen from injection logging. Saturation logging presents a sign of oil saturation decrease around the wellbore area. Reduction of water cut and rise of oil production have pleasantly come after a few months from the start. Intensive surveillance program will be continued over the course of pilot injection. The critical success of the EOR pilot execution depends on the detailed planning, prudent surveillance and comprehensive evaluation. Sirikit oil field is moving to a turning point and the pilot outcome would lead the way to a further milestone, so as to avoid premature end of the field's production.

scholarly journals Investigation of the influence of the heterogeneous permeability distribution on the oil phase displacement processes

2021 ◽  
Vol 5 (1(61)) ◽  
pp. 33-40
Author(s):  
Miсhail Lubkov ◽  
Oksana Zakharchuk ◽  
Viktoriia Dmytrenko ◽  
Oleksandr Petrash
Keyword(s):  
Finite Element ◽  
Difference Method ◽  
High Reliability ◽  
Oil Field ◽  
Injection Well ◽  
Shear Direction ◽  
Reservoir Pressure ◽  
Filtration Process ◽  
Injection Wells ◽  
The Impact

The object of research is the filtration processes of displacement of the oil phase under the influence of an injection well in a heterogeneous porous medium. It is possible to evaluate and take into account the effect of reservoir heterogeneity on the distribution of reservoir pressure (and, consequently, on the intensity of the filtration process) using numerical modeling of filtration processes based on the piezoelectric equation. To solve the non-stationary anisotropic problem of piezoconductivity, it is proposed to apply the combined finite-element-difference method of M. Lubkov, which makes it possible to take into account the inhomogeneous distribution of permeability inside the anisotropic oil-bearing formation and at its boundaries, and to adequately calculate the distribution of reservoir pressure. The use of the combined finite-element-difference method allows to combine the advantages of the finite-element method and the finite difference method: to model geometrically complex areas, to find the value at any point of the object under study. At the same time, the use of an implicit difference scheme when finding the nodal values of the grid provides high reliability and convergence of the results. The simulation results show that the distribution of the pressure field between the production and injection wells significantly depends on their location, both in the isotropic landslide and in the anisotropic oil-bearing reservoir. It is shown that the distance between the wells of more than 1 km levels out the effectiveness of the impact of the injection well on the oil filtration process. The influence of the permeability of the oil phase in the shear direction dominates the influence of the permeability in the axial directions (affects the pressure decrease by 4–9.5 %). In the case of a landslide-isotropic reservoir, the wells should be located in the shear (diagonal) direction, which will provide the lowest level of drop in the average reservoir pressure (by 4 %). Based on the information obtained, for the effective use of anisotropic low-permeability formations, it is necessary to place production and injection wells in areas with relatively low anisotropy of the formation permeability, especially to avoid places with the presence of landslide permeability of the formation. The location of the wells is important so that, on the one hand, there is no blockage of oil from the side of reduced permeability, and on the other hand, rapid depletion of the formation from the side of increased permeability does not occur. And also the mutual exchange between the production and injection wells did not stop. When placing a system of production and injection wells in anisotropic formations of an oil field, it is necessary to carry out a systematic analysis of the surrounding anisotropy of the formations in order to place them in such a way that would ensure effective dynamics of filtration processes around these wells. Using the method used, it is possible to predict the impact of an injection well on the distribution of reservoir pressure in the reservoir.

scholarly journals ANALYSIS OF THE TRACER STUDIES RESULTS: A STUDY OF AS1-3 FORMATION OF THE SEVERO-OREKHOVSKOYE OIL FIELD

2018 ◽  
pp. 44-51
Author(s):  
V. F. Dyagilev ◽  
S. T. Polischuk ◽  
S. A. Leontev ◽  
V. M. Spasibov
Keyword(s):  
Mathematical Analysis ◽  
Analysis Data ◽  
Oil Field ◽  
Tracer Studies ◽  
Injection Wells ◽  
Field Development ◽  
Field Practice ◽  
Production Wells ◽  
The Impact ◽  
State Of Field

In oil field practice tracer (indicator) studies are an effective and efficient method of monitoring the state of field development. Using the multifactor mathematical analysis, the nature and intensity of the impact of injection wells on production wells have been compared with the results of injection of indicator liquids. Injection of indicator liquids was carried out along the AS1-3 formation at the Severo-Orekhovskoye oil field through the wellheads of the injection wells. The technique provides for correlation of injection in all potentially possible directions within a given range of action (usually no more than 2 rows), excluding one or more of the wells and more from the analysis. There is a direct positive correlation between evaluation data on indicator downloads and multivariate mathematical analysis data. The convergence of the results is 65%.

scholarly journals Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir

Polymers ◽  
2021 ◽  
Vol 13 (11) ◽  
pp. 1765
Author(s):  
Mohamed Adel Alzaabi ◽  
Juan Manuel Leon ◽  
Arne Skauge ◽  
Shehadeh Masalmeh
Keyword(s):  
Porous Media ◽  
High Temperature ◽  
Polymer Solutions ◽  
High Salinity ◽  
Shear Thickening ◽  
Shear Thinning ◽  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Polymer Injection ◽  
The Impact

Polymer flooding has gained much interest within the oil industry in the past few decades as one of the most successful chemical enhanced oil recovery (CEOR) methods. The injectivity of polymer solutions in porous media is a key factor in polymer flooding projects. The main challenge that faces prediction of polymer injectivity in field applications is the inherent non-Newtonian behavior of polymer solutions. Polymer in situ rheology in porous media may exhibit complex behavior that encompasses shear thickening at high flow rates in addition to the typical shear thinning at low rates. This shear-dependent behavior is usually measured in lab core flood experiments. However, data from field applications are usually limited to the well bottom-hole pressure (BHP) as the sole source of information. In this paper, we analyze BHP data from field polymer injectivity test conducted in a Middle Eastern heterogeneous carbonate reservoir characterized by high-temperature and high-salinity (HTHS) conditions. The analysis involved incorporating available data to build a single-well model to simulate the injectivity test. Several generic sensitivities were tested to investigate the impact of stepwise variation in injection flow rate and polymer concentration. Polymer injection was reflected in a non-linear increase in pressure with injection, and longer transient behavior toward steady state. The results differ from water injection which have linear pressure response to rate variation, and quick stabilization of pressure after rate change. The best match of the polymer injection was obtained with complex rheology, that means the combined shear thickening at high rate near the well and moving through apparent Newtonian and shear thinning at low rate.

Simulation of Polymer Injection Under Fracturing Conditions—An Injectivity Pilot in the Matzen Field, Austria

2015 ◽  
Vol 18 (02) ◽  
pp. 236-249 ◽  
Author(s):  
Markus Zechner ◽  
Torsten Clemens ◽  
Ajay Suri ◽  
Mukul M. Sharma
Keyword(s):  
Polymer Solution ◽  
Field Test ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Oil Production ◽  
Polymer Rheology ◽  
Oil Viscosity ◽  
Polymer Injection ◽  
Stress Changes ◽  
The Impact

Summary Polymer flooding leads to enhanced oil recovery by accelerating oil production and improving sweep efficiency. However, because of the higher viscosity, the injectivity of polymer solutions is of some concern and is important to understand to predict incremental oil recoveries. Achieving high polymer-injection rates is required to increase oil-production rates. In the field test performed in the Matzen field (Austria), polyacrylamide polymers were injected for the past 2 years. Coreflood experiments with these polymers showed a significant increase in apparent viscosity because of the viscoelastic properties of the polymer solutions. Also, severe degradation of the polymer solution at high flow velocities was detected. In addition to coreflood experiments, flow experiments through fractures were performed. In these experiments, shear thinning and limited degradation of the polymer solution were observed and quantified. Detailed polymer-injection simulations were conducted that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and their effects on the fractures were also taken into account as a result of cold-polymer injection. The results of the simulations matched the field data both for waterfloods and polymer-test floods. The simulations revealed two distinct phases during the injection of the polyacrylamide-polymer solution: Injection under matrix conditions in an early phase resulting in severe degradation of the polymers Injection under fracturing conditions after the formation parting pressure is reached, leading to limited degradation of the polymers The calibrated model was used to investigate the impact of polymer rheology and particle plugging on injectivity and fracture growth. The results of the field test and the simulations indicate that screening of fields for polyacrylamide-polymer projects needs to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in screening such as oil viscosity, water salinity, reservoir temperature, and reservoir permeability.

scholarly journals Gas Lift Performance of Some Horizontal Wells in Ahdeb Oil Field

2021 ◽  
Vol 7 (3) ◽  
pp. 66-74
Author(s):  
Dr. Kareem A. Alwan ◽  
Dr. Maha R. Abdulameer ◽  
Mohammed Falih
Keyword(s):  
Water Injection ◽  
Injection Pressure ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Injection Wells ◽  
Artificial Lift ◽  
Electrical Submersible Pumps ◽  
Optimal Injection ◽  
Water Cut ◽  
The Impact

Ahdeb is one of the Iraqi oil fields, its crude characterized by medium API (22.5-28.9) and highly reservoir pressure depletion from Khasib formation due to lack of water drive. This makes it difficult to produce economic oil rates. Therefore, many water injection wells were drilled by the operators to maintain the reservoir pressure during production. In addition to that, electrical submersible pumps (ESP) were used in some productive wells. This study suggests exploitation of gas associated with oil production to be recycled to lift oil as a substitute for the ESP .The work in this study includes using PIPSIM software to build a model of four studied productive wells (AD1-11-2H, AD2-15-2H, AD4-13-3H, A4-19-1H) after choosing the suited correlation for each well. According to the statistical results, Mukherjee & Brill correlation is the best option for all wells. The use of PIPESIM software include determining artificial lift performance to determine the optimum amount of gas injected, optimum injection pressure as well as the optimum injection depth and knowing the impact of these factors on production, as well as the determination of the optimal injection conditions when water cut changes. According to the current circumstances of the wells, the depth optimized for injection is the maximum allowable depth of injection which is deeper than the packer by 100 ft and the amount of injection gas is (1.5, 1, 1, and 1) MMscf/day for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially and injection pressure (2050, 2050, 2050, and 2000) psi for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially.  

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