Development of Tight Upper Cretaceous Reservoir in Offshore Black Sea Adds Life to a Mature Asset

2021 ◽  
Author(s):  
I. Mitrea ◽  
R. Cataraiani ◽  
M. Banu ◽  
S. Shirzadi ◽  
W. Renkema ◽  
...  
Keyword(s):  
Black Sea ◽  
Upper Cretaceous ◽  
Rock Physics ◽  
Oil Production ◽  
Economic Life ◽  
Production Performance ◽  
Single Fracture ◽  
Well Performance ◽  
Acoustic Image ◽  
The Impact

Abstract This Upper Cretaceous reservoir, a tight reservoir dominated by silt, marl, argillaceous limestone and conglomerates in Black Sea Histria block, is the dominant of three oil-producing reservoirs in Histria Block. The other two, Albian and Eocene, are depleted, and not the focus of field re-development. This paper addresses the challenges and opportunities that were faced during the re-development process in this reservoir such as depletion, low productivity areas, lithology, seismic resolution, and stimulation effectiveness. Historically, production from Upper Cretaceous wells could not justify the economic life of the asset. As new fracturing technology evolved in recent years, the re-development focused on replacing old, vertical/deviated one-stage stimulations low producing wells with horizontal, multi-stage hydraulic fractured wells. The project team integrated various disciplines and approaches by re-processing old seismic to improve resolution and signal, integrating sedimentology studies using cores, XRF, XRD and thin section analysis with petrophysical evaluation and quantitative geophysical analyses, which then will provide properties for geological and geomechanical models to optimize well planning and fracture placement. Seven wells drilled since end of 2017 to mid-2021 have demonstrated the value of integration and proper planning in development of a mature field with existing depletion. Optimizing the well and fracture placement with respect to depletion in existing wells resulted in accessing areas with original reservoir pressure, not effectively drained by old wells. Integrating the well production performance with tracer results from each fractured stage, and NMR/Acoustic images from logs enhanced the understanding of the impact of lithofacies on stimulation. This has allowed better assessment and prediction of well performance, ultimately improving well placement and stimulation design. The example from this paper highlights the value of the integrating seismic reprocessing, attribute analysis, production technology, sedimentology, cuttings analysis and quantitative rock physics in characterizing the heterogeneity of the reservoir, which ultimately contributed to "sweet spot" targeting in a depleted reservoir with existing producers and deeper understanding of the development potential in Upper Cretaceous. The 2017-2021 wells contribute to more than 30 percent of the total oil production in the asset and reverse the decline in oil production. In addition, these wells have two to four times higher initial rates because of larger effective drainage area than a single fracture well. Three areas of novelty are highlighted in this paper. The application of acoustic image/NMR logging to identify lithofacies and optimize fracturing strategy in horizontal laterals. The tracers analysis of hydraulic fracture performance and integration with seismic and petrophysical analysis to categorize the productivity with rock types. The optimization of fracture placement considering the changes of fluid and proppant volumes without compromising fracture geometries and avoiding negative fracture driven interactions by customized pumping approach.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

Field Optimization Via Data Approach: A Case Study of Data Mining for Tight Gas Flowback Evaluations

2021 ◽  
Author(s):  
Yuan Liu ◽  
Bin Li ◽  
Hongjie Zhang ◽  
Fan Yang ◽  
Guan Wang ◽  
...  
Keyword(s):  
Data Mining ◽  
Production Performance ◽  
Reservoir Quality ◽  
Tight Gas ◽  
Well Performance ◽  
Gas Field ◽  
Field Development ◽  
Field Level ◽  
Depth Analysis ◽  
The Impact

Abstract The economics of tight gas fields highly depend on the consistency between expected production and the actual well performance. A mismatch between the reservoir quality and the well production often leads to a review of the individual well. However, such mismatch may vary from case to case, and it is hard to perform a field-level analysis based on individual well reviews. We introduce a new method based on data mining to assist the field-level diagnosis. LX gas field is located the in eastern Ordos basin. Compared to the main gas field in the center of the basin, LX field is less predictable in well performance. This predictability issue hinders field development in LX field because the field economics are substantially jeopardized by the inconsistency between the reservoir quality and the production performance. The traditional workflow to understand this issue at the field level is to review the details of a large number of individual wells in the area. This is typically an intense task, and too much detail from multiple disciplines may hide the true pattern of the field behavior. To resolve this issue, we applied data mining in our field development diagnosis workflow. Our new workflow in LX area started with the existing field datasheet, including logging summaries, completion treatment reports, and flowback testing datasheets. With the data extracted from these different sources, we visualized the consolidated information in various plots and graphs based on regression analysis, which revealed the relation between flowback ratio and the production, the flowback rate consistency from the different service suppliers, and the impact of water productions. The data mining approach helped to generate new understandings in LX gas field. With the in-depth analysis of the flowback data together with reservoir properties and operation parameters, the key problems in the field were identified for further development optimization, and the field economics can be significantly improved. The diagnosis method can be easily adapted and applied to any field with similar problems, and data mining can be useful for almost all large-scale field development optimizations.

Challenges from Well Shut-in Amid the Oil Downturn: Long Term Impacts on Near Wellbore Skin Buildup and Sand Control

2021 ◽  
Author(s):  
Mohammad Soroush ◽  
Mahdi Mahmoudi ◽  
Morteza Roostaei ◽  
Hossein Izadi ◽  
Seyed Abolhassan Hosseini ◽  
...  
Keyword(s):  
Hot Spot ◽  
Oil Production ◽  
Well Performance ◽  
Well Completion ◽  
Flow Control Devices ◽  
Sand Control ◽  
Control Devices ◽  
Inflow Problem ◽  
The Impact

Abstract In wake of the biggest oil crash in history triggered by the COVID-19 pandemic; Western Canada in- situ production is under tremendous price pressure. Therefore, the operators may consider shut in the wells. Current investigation offers an insight into the effect of near-wellbore skin buildup because of such shut-in. A series of simulation studies was performed to quantitatively address the impact of well shut-in on the long-term performance of well, in particular on key performance indicators of the well including cumulative steam to oil ratio and cumulative oil production. The long-term shut-in contributes to three main modes of plugging: (1) near-wellbore pore plugging by clays and fines, (2) scaling, and (3) chemical consolidation induced by corrosion. A series of carefully designed simulations was also utilized to understand the potential of skin buildup in the near-wellbore region and within different sand control devices. The simulation results showed a higher sensitivity of well performance to shut-in for the wells in the initial stage of SAGD production. If the well is shut in during the first years, the total reduction in cumulative oil production is much higher compared to a well which is shut-in during late SAGD production life. As the induced skin due to shut-in increases, the ultimate cumulative oil production drops whose magnitude depends on well completion designs. The highest effect on the cumulative oil production is in the case of completion designs with flow control devices (liner deployed and tubing deployed completions). Therefore, wellbore hydraulics and completion design play key roles in the maintenance of uniform inflow profile, and the skin buildup due to shut-in poses a high risk of inflow problem and increases the risk of hot-spot development and steam breakthrough. This investigation offers a new understanding concerning the effect of shut-in and wellbore skin buildup on SAGD operation. It helps production and completion engineers to better understand and select candidate wells for shut-in and subsequently to minimize the skin buildup in wells.

Key Factors in Shale Gas Modeling and Simulation

2014 ◽  
Vol 59 (4) ◽  
pp. 987-1004 ◽  
Author(s):  
Łukasz Klimkowski ◽  
Stanisław Nagy
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Production Performance ◽  
Hydraulic Fractures ◽  
Well Performance ◽  
Key Factors ◽  
Gas Well ◽  
Well Production ◽  
Multi Stage ◽  
The Impact

Abstract Multi-stage hydraulic fracturing is the method for unlocking shale gas resources and maximizing horizontal well performance. Modeling the effects of stimulation and fluid flow in a medium with extremely low permeability is significantly different from modeling conventional deposits. Due to the complexity of the subject, a significant number of parameters can affect the production performance. For a better understanding of the specifics of unconventional resources it is necessary to determine the effect of various parameters on the gas production process and identification of parameters of major importance. As a result, it may help in designing more effective way to provide gas resources from shale rocks. Within the framework of this study a sensitivity analysis of the numerical model of shale gas reservoir, built based on the latest solutions used in industrial reservoir simulators, was performed. The impact of different reservoir and hydraulic fractures parameters on a horizontal shale gas well production performance was assessed and key factors were determined.

scholarly journals An integrated workflow to perform reservoir and completion parametric study on a shale gas reservoir

2020 ◽  
Vol 10 (4) ◽  
pp. 1497-1510
Author(s):  
Mohamed Mahmoud ◽  
Ahmed Aleid ◽  
Abdulwahab Ali ◽  
Muhammad Shahzad Kamal
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Production Performance ◽  
Analytical Models ◽  
Well Performance ◽  
Short Term ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
The Impact

AbstractThe main objectives of this paper are to assess the long-term and short-term production based on both reservoir parameters and completion parameters of shale gas reservoirs. The effects of the reservoir parameters (permeability and the initial reservoir pressure) and completion parameters (fracture geometry, stimulated reservoir volume, etc.) on the short-term and long-term production of shale gas reservoirs were investigated. The currently used approach relies mainly on the decline curve analysis or analogs from a similar shale play to forecast the gas production from shale gas reservoirs. Both these approaches are not satisfactory because they are calibrated on short production history and do not assess the impact of uncertainty in reservoir and well data. For the first time, this study integrates initial production analysis, probabilistic evaluation, and sensitivity analysis to develop a robust workflow that will help in designing a sustainable production from shale gas plays. The reservoir and completion parameters were collected from different available resources, and the probability distributions of gathered uncertain data were defined. Then analytical models were used to forecast the production. Two well evaluation results are presented in this paper. Based on the results, completion parameters affected the short-term and long-term production, while the reservoir parameters controlled the long-term production. Long-term well performance was mainly controlled by the fracture half-length and fracture height, whereas other completion and reservoir parameters have an insignificant effect. Stimulation treatment design defines the initial well performance, while well placement decision defines well long-term performance. The findings of this study would help in better understanding the production performance of shale gas reservoirs, maximizing production by selecting effective completion parameters and considering the governing reservoir parameters. Moreover, it would help in accomplishing more effective stimulation treatments and define the potentiality of the basin.

Using geomechanical modeling to quantify the impact of natural fractures on well performance and microseismicity: Application to the Wolfcamp, Permian Basin, Reagan County, Texas

2016 ◽  
Vol 4 (2) ◽  
pp. SE1-SE15 ◽  
Author(s):  
Ahmed Ouenes ◽  
Nicholas M. Umholtz ◽  
Yamina E. Aimene
Keyword(s):  
Empirical Relationship ◽  
Production Performance ◽  
Fault System ◽  
Fracture Density ◽  
Natural Fractures ◽  
Well Performance ◽  
Optimal Position ◽  
Complex Fault ◽  
Quantitative Impact ◽  
The Impact

We have evaluated workflows to quantify the mechanical impact of natural fractures (NFs) on the production performance of hydraulically stimulated stages in shale wells. Variations in fracture orientation and density can enhance or degrade the transport and effectiveness of fracturing fluids. Specifically, we studied the effect of a complex fault splay system on a horizontal Wolfcamp B reservoir well. A general workflow that combines geophysics, geology, and geomechanics (3G) was evaluated and applied to the well. The benefits of the 3G workflow are threefold. First, the quantitative impact of the NFs on the regional stress is provided through the differential horizontal stress variation, which impacts fracturing complexity. Then, the reservoir strain map, validated with microseismic data, gives insights into the stimulated drainage pathways. Finally, the ability of the [Formula: see text] integral to predict poor hydraulic fracturing stages as a function of fracture density along the wellbore or as a function of the energy required to propagate a fracture. Building on the validated 3G workflow, a well placement workflow that takes into account the quantitative impact of NFs on well performance was developed on the sample Wolfcamp well. By comparing the [Formula: see text] integral of the same completion stage in simulations with and without NFs, stages with similar [Formula: see text] integral values in both simulations were identified as those not being affected by the NF network. This allows the workflow to provide the optimal position of a well in the presence of NFs associated with a complex fault system that may produce undesirable water. The result is a validated 3G workflow that provides a geomechanical explanation for an empirical relationship showing that high oil production is achieved within a “Goldilocks” range of natural fracturing.

Predicting and optimising the mature Windalia waterflood based on a capacitance-resistance model (CRM)

2012 ◽  
Vol 52 (2) ◽  
pp. 656
Author(s):  
Wee Yong Gan ◽  
Lina Hartanto ◽  
Andrew Haynes ◽  
Morteza Sayarpour
Keyword(s):  
Water Injection ◽  
Oil Production ◽  
Operating Conditions ◽  
Significant Heterogeneity ◽  
Well Performance ◽  
Fractional Flow ◽  
Injection Wells ◽  
Resistance Model ◽  
Production Wells ◽  
The Impact

Waterflood development drilling of the Windalia reservoir on Barrow Island at 40-acre spacing started in 1968, using five-spot and nine-spot inverted drive flood patterns. There was a general conversion to line drive in mid-1970 with various infill and realignment projects. The field comprises more than 220 active injectors and 400 producers. The reservoir is geologically complex, with low permeability and significant heterogeneity. Historically, empirical techniques and fractional flow models were used for forecasting, but these approaches have many inherent limitations; for example, they do not provide individual well performance and they are not sensitive to changes in operating conditions. More recently, a capacitance-resistance model (CRM) that uses historical injection and production data has been used to establish long-term behaviours between water injection and oil production wells, including inter-well connectivity, delay time constants and productivity indices. The evaluation of these behaviours allows direct quantification of waterflood efficiency at well-to-well level and improves identification of opportunities for changing injection patterns and prioritisation of operations and well workovers. Optimisation and forecasting of the Windalia waterflood is performed by maximising cumulative oil production by reallocating the available field wide injection water and evaluating individual injection wells target rates. Numerous optimisation scenarios were built into the models to account for the impact of changing operating conditions such as water availability and aging of wells and processing facilities. CRM is robust and is appropriate for simultaneous optimisation of well rates in a field where water injection and oil production wells are shut-in frequently. The PowerPoint presentation is not available to APPEA.

Impact of Delayed Flowback on Well Performance: Case Study

2022 ◽  
Author(s):  
Ruqia Al Shidhani ◽  
Ahmed Al Shueili ◽  
Hussain Al Salmi ◽  
Musallam Jaboob
Keyword(s):  
Hydraulic Fracturing ◽  
Large Scale ◽  
Gas Permeability ◽  
Real Data ◽  
Formation Damage ◽  
Single Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Wellhead Pressure ◽  
The Impact

Abstract Due to a resource optimization and efficiency improvements, wells that are hydraulically fractured in the tight gas Barik Formation of the Khazzan Field in the Sultanate of Oman are often temporarily left shut-in directly following a large scale massive hydraulic fracturing stimulation treatment. Extensive industry literature has often suggested (and reported), that this may result in a significant direct loss of productivity due to the delayed flowback and the resulting fracture conductivity and formation damage. This paper will review the available data from the Khazzan Field address these concerns; indicating where the concerns should and should not necessarily apply. The Barik Formation in the Khazzan Field is an over-pressured gas-condensate reservoir at 4,500 m with gas permeability ranging from 0.1 to 20 mD. The average well after hydraulic fracturing produces 25 MMscfd and 500 bcpd against a wellhead pressure of 4,000 psi. A typical hydraulic fracturing stimulation treatment consists of 14,000 bbl of a borate-crosslinked guar fluid, placing upwards of 1MM Lbs of high conductivity bauxite proppant within a single fracture. In order to assess the potential production loss due to delayed flowback operations, BP Oman performed a suite of formation damage tests including core samples from the Barik reservoir, fracture conductivity considerations and dynamic behaviors. Additionally, normalized production was compared between offset wells that were cleaned-up and put onto production at different times after the hydraulic fracturing operations. Core tests showed a range of fracture conductivities over time with delayed flowback after using the breaker concentrations from actual treatments. As expected, enhanced conductivity was achieved with additional breaker. The magnitude of the conductivity being created in these massive treatments was also demonstrated to be dominant with respect to damage effects. Finally, a normalized comparison of an extensive suite of wells clearly showed no discernible loss of production resulted from any delay in the flowback operations. This paper describes in details the workflow and resulting analysis of the impact of extensive shut-in versus immediate flowback post massive hydraulic fracturing. It indicates that the impact of such events will be limited if the appropriate steps have been taken to minimize the opportunity for damage to occur. Whereas the existing fracturing literature takes the safe stance of indicating that damage will always result from such shut-ins, this paper will demonstrate the limitations of such assumptions and the flexibility that can be demonstrated with real data.

scholarly journals Is a PD game still a dilemma for Japanese rural villagers? A field and laboratory comparison of the impact of social group membership on cooperation

2021 ◽  
Author(s):  
Yohei Mitani
Keyword(s):  
Social Group ◽  
Prisoner's Dilemma ◽  
Field Experiments ◽  
Group Membership ◽  
Prisoner’S Dilemma ◽  
Economic Life ◽  
Community Members ◽  
Prisoner’S Dilemma Game ◽  
Prisoner's Dilemma Game ◽  
The Impact

AbstractLocal norms and shared beliefs in cohesive social groups regulate individual behavior in everyday economic life. I use a door-to-door field experiment where a hundred and twenty villagers recruited from twenty-three communities in a Japanese rural mountainous village play a simultaneous prisoner’s dilemma game. To examine whether a set of experiences shared through interactions among community members affect experimental behavior, I compare villagers’ behavior under in-community and out-community random matching protocols. I also report a counterpart laboratory experiment with seventy-two university student subjects to address the external validity of laboratory experiments. The findings are three-fold. First, almost full cooperation is achieved when villagers play a prisoner’s dilemma game with their anonymous community members. Second, cooperation is significantly higher within the in-group compared to the out-group treatment in both the laboratory and field experiments. Third, although a significant treatment effect of social group membership is preserved, a big difference in the average cooperation rates is observed between the laboratory and field.

scholarly journals Multi-Criteria Analysis of the Mass Tourism Management Model Related to the Impact on the Local Community in Constanta City (Romania)

Inventions ◽  
2021 ◽  
Vol 6 (3) ◽  
pp. 46
Author(s):  
Catalin Anton ◽  
Angela-Eliza Micu ◽  
Eugen Rusu
Keyword(s):  
Black Sea ◽  
Seasonal Cycle ◽  
Local Community ◽  
Local Economy ◽  
Management Model ◽  
The Black Sea ◽  
Mass Tourism ◽  
Tourism Management ◽  
The Impact ◽  
The City

Traditionally and socially, the tourism in Constanta is considered to be important to the local economy. Sun and beach locations are both a draw for locals and tourists to the city, on the Black Sea. However, vacation-oriented activities in the city only have a seasonal cycle. In this paper, we proposed to analyze the mass tourist activity in Constanta, taking into account economic, social, and environmental conditions. Additionally, we attempted to build a model based on the data available. The model was developed using a PESTEL analysis to determine the supportability factor of the indicators identified. We also set out to create a projection of the activities proposed for analysis by 2050. To create a model for coastal areas, the data used in this research must be accurate and consistent. Furthermore, correctly identifying indicators and their relationships is a critical step in conducting a thorough study. Last but not least, finding the calculation coefficient for the activity in question is critical, as collecting data from various activities might be challenging when trying to find a feasible model.

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