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 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.

scholarly journals MODERN METHODOLOGICAL POSSIBILITIES OF THE TRACER METHOD FOR ASSESSING THE COVERAGE OF AN OIL RESERVOIR BY FLOODING

2021 ◽  
Vol 21 ◽  
pp. 24-28
Author(s):  
D.A. Chernokozhev ◽  
◽  
K.I. Kuznetsova ◽  
R.R. Gazimov ◽  
A.S. Zasedatelev ◽  
...  
Keyword(s):  
Oil Field ◽  
Injection Well ◽  
Oil Reservoir ◽  
Tracer Method ◽  
Tracer Studies ◽  
Injection Wells ◽  
Reservoir Area ◽  
Field Development ◽  
Oil Field Development ◽  
Continuous Injection

The article presents the results of modeling tracer studies of the process of flooding of an oil reservoir. As a result of the studies, the dependences on the time of the change in the volume occupied by the injected water were obtained. Formulas are given that allow us to calculate the values of the coefficient of coverage of the reservoir area by flooding as a whole and the contribution of each injection well to flooding. The technology is implemented by continuously pumping the tracer into the injection well. Continuous injection of different tracers into different injection wells allows for operational monitoring of oil field development

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.

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.

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.

The Scapa Field, Block 14/19, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 369-376 ◽  
Author(s):  
G. J. McGann ◽  
S. C. H. Green ◽  
S. D. Harker ◽  
R. S. Romani
Keyword(s):  
North Sea ◽  
Production Test ◽  
Injection Wells ◽  
Integrated Production ◽  
Field Development ◽  
Recoverable Reserves ◽  
Production Wells ◽  
The Witch ◽  
Original Oil In Place

AbstractThe Scapa Field is located in UK North Sea Block 14/19 in the Witch Ground Graben, 112 miles northeast of Aberdeen. The field was discovered in 1975 by the 14/19–9 well which tested 32° API crude from the Scapa Sandstone Member of the Early Cretaceous Valhall Formation. The field is a combination structural/stratigraphic trap situated in a NW–SE trending syncline. Updip limit to the NE is by onlap termination of the reservoir sands onto the Claymore tilt block, and to the southwest by fault closure and/or sand pinch-out into tight conglomerates associated with the Halibut Shelf boundary fault. Two thinly bedded, fine- to medium-grained turbidite sand units, in partial pressure communication, form the oil–bearing zone within the Scapa Sandstone Member.Original oil in place was 206 MMBBL. In 1984, prior to development, a long-term production test was conducted via a deviated well drilled from the Claymore platform. Subsequent wells were thus drilled in a dynamic reservoir-pressure environment. Field development utilizes an integrated production/injection subsea template system tied back to the Claymore platform. Template production commenced in 1986 from currently estimated proved ultimate recoverable reserves of 63 MMBBL and averaged 28 000 BOPD in June 1988 from four production wells supported by four injection wells.

scholarly journals Influence of well management in the development of multiple reservoir sharing production facilities

2020 ◽  
Vol 75 ◽  
pp. 70
Author(s):  
João Carlos von Hohendorff Filho ◽  
Denis José Schiozer
Keyword(s):  
Oil Recovery ◽  
Development Project ◽  
Gas Production ◽  
Oil Field ◽  
The Other ◽  
Dynamic Flow ◽  
Field Development ◽  
Light Oil ◽  
Multiple Reservoir ◽  
The Impact

Well prioritization rules on integrated production models are required for the interaction between reservoirs and restricted production systems, thus predicting the behavior of multiple reservoir sharing facilities. This study verified the impact of well management with an economic evaluation based on the distinct prioritizations by reservoir with different fluids. We described the impact of the well management method in a field development project using a consolidated methodology for production strategy optimization. We used a benchmark case based on two offshore fields, a light oil carbonate and a black-oil sandstone, with gas production constraint in the platform. The independent reservoir models were tested on three different approaches for platform production sharing: (Approach 1) fixed apportionment of platform production and injection, (Approach 2) dynamic flow-based apportionment, and (Approach 3) dynamic flow-based apportionment, including economic differences using weights for each reservoir. Approach 1 provided the intermediate NPV compared with the other approaches. On the other hand, it provided the lowest oil recovery. We observed that the exclusion of several wells in the light oil field led to a good valuation of the project, despite these wells producing a fluid with higher value. Approach 2 provided the lower NPV performance and intermediate oil recovery. We found that the well prioritization based on flow failed to capture the effects related to the different valuation of the fluids produced by the two reservoirs. Approach 3, which handled the type of fluids similarly to Approach 1, provided a greater NPV and oil recovery than the other approaches. The weight for each reservoir applied to well prioritization better captured the gains related to different valuation of the fluids produced by the two reservoirs. Dynamic prioritization with weights performed better results than fixed apportionment to shared platform capacities. We obtained different improvements in the project development optimization due to the anticipation of financial returns and CAPEX changes, due mainly from adequate well apportionment by different management algorithm. Well management algorithms implemented in traditional simulators are not developed to prioritize different reservoir wells separately, especially if there are different economic conditions exemplified here by a different valuation of produced fluids. This valuation should be taken into account in the short term optimization for wells.

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 Evaluation of well screen efficiency using Simulation

2020 ◽  
pp. 24-31
Author(s):  
O. Ya. Faflei ◽  
R. O. Deynega ◽  
V. V. Mykhailiuk ◽  
A. V. Semenchuk ◽  
B. I. Zvir
Keyword(s):  
Raw Materials ◽  
Low Cost ◽  
Oil Field ◽  
High Rate ◽  
Production Wells ◽  
Hydrodynamic Processes ◽  
Carry Over ◽  
Pumping Equipment ◽  
Pumping Units ◽  
The Impact

The process of the oil field operation at the late stage is characterized by a significant content of mechanical impurities in the extracted raw materials and a high rate of water encroachment. Water encroachment plays a sig-nificant role in the processes of formation sand carry-over and the destruction of incompetent rocks of productive horizons in deposits. Today, to intensify the drainage of formation fluid from production wells, it is necessary to increase the depth of descent and to use more productive pumps. However, this leads to the growth of the draw down pressure and, as a rule, to more intensive sloughing of mechanical impurities out of the reservoir. First of all, the sand taken out of the formation is a highly abrasive agent, which causes the wear not only of the pump elements, but also of the tubings, valves, throttles, etc. Predicting the impact of mechanical impurities on the ele-ments of the pumping equipment for oil production is a complex task that requires consideration of many different factors. The sand which is carried out of wells is accumulated in the pipelines. Besides, it is accumulated in meas-uring units, separators, valves and other parts of group metering and pumping units. Process tanks and reservoirs at oil or condensate treatment plants are clogged with sand. To combat sloughing of sand, in most cases the meth-od of filtration is used. This method is not the most effective, but it is reliable, low cost, and environmentally friendly. Several constructions of downhole filters are analyzed. To evaluate the efficiency of the downhole filter, its research is carried out using simulation modeling. The dependence of the number of sloughed particles on their diameter is established in accordance with the hydrodynamic processes and characteristics of the working envi-ronment.

scholarly journals AN ASSESSMENT OF DISTURBANCE EFFECTS ON PLANT COVER OF NUMTO NATURAL PARK (KHANTY-MANSIYSK AUTONOMOUS OKRUG - UGRA)

2020 ◽  
pp. 81-89
Author(s):  
D. V. Moskovchenko ◽  
S. P. Aref’ev ◽  
V. A. Glazunov ◽  
I. V. Filippov
Keyword(s):  
Vegetation Cover ◽  
Oil And Gas ◽  
Plant Cover ◽  
Oil Extraction ◽  
Oil Field ◽  
Nature Management ◽  
Field Development ◽  
Natural Park ◽  
Oil Deposits ◽  
The Impact

The Numto Natural Park, Khanty-Mansi Autono-mous Okrug - Yugra, Russia, has recently attracted the attention of environmental organizations due to oil extraction operations in its territory. This paper presents the study of the vegetation cover dynamics and the assessment of natural and anthropogenic disturbances of Numto’s ecosystems. Due to the development of oil deposits, more than 60 adventitious plant species arrived to the park, and the synan-thropization index reached 26.4%. Tree rings showed the predominant influence of the climatic and pyrogenic components on the growth of trees. The technogenic impact that had occurred in the 1990s gave a spasmodic increase in cedar growth in the disturbed areas in the form of abnormal hard streaks. Later on, the impact of technogenic factors on the wood growth waned. Satellite imagery helped to determine changes in the vegetation cover. From 2011 to 2018, the area of disturbed sites doubled while the length of infield roads and pipelines increased by 5.7 times. The area of burnt fire sites increased manifold; how-ever, fires occurred at a considerable distance from the oil extraction sites and were of natural origin. Currently, the disturbed ecosystems, including burnt fire sites and fire-damaged ecosystems, occupy 2.1% of the oil deposits area, and the area of pyrogenic disturbances is larger than the area of technogenic ones. Compared to the oil and gas fields in the adjacent areas, the level of disturbance in the Numto Natural Park can be considered low. Since deer pastures were not disturbed by the oil extraction operations, the traditional nature management remains possible. Further oil field development requires ongoing monitoring of the ecosystem condition.

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