bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of the Potential of Low Salinity Water Flooding in the High Temperature and High Salinity Dong-He-Tang Reservoir in the Tarim Oilfeild, China: Experimental and Reservoir Simulation Results
Authors: Liu Yongbing , Jiang Tongwen , Zhou Daiyu , Zhao Ji , Xie Quan , Saeedi Ali 
Published: October 2016

Abstract
This paper presents a systematic assessment of the potential of low salinity water flooding for the Dong-He-Tang reservoir in the Tarim Oilfield, China. This reservoir has a high reservoir temperature of 140 °C, high formation water salinity of 142,431 ppm total dissolved solids and an in-situ oil viscosity of 2.2 cp.
Our laboratory evaluation included contact angle tests, and spontaneous imbibition and core-flooding experiments using representative core samples from the reservoir. Contact angle tests were conducted at various temperatures (60, 100 and 140 °C) and pressures (20, 30, 40 and 50 MPa). Core-flooding experiments were conducted under the reservoir temperature of 140 °C. Formation brine and low salinity water (100 times diluted formation brine) were used in the experiments.
Contact angle and spontaneous imbibition experiments showed that low salinity water shifted the reservoir wettability towards more water-wet. In addition, spontaneous imbibition experiments showed that low salinity water recovered significantly more oil than high salinity water.
Furthermore, corefloods were conducted using low salinity water under tertiary and secondary modes. Experimental results were history matched to derive relative permeability curves and capillary pressure curves while considering the non-uniqueness of such history-matching. Results showed that compared to high salinity water flooding, low salinity water shifted relative permeability curves towards lower residual oil saturation, showing a higher oil relative permeability and lower water relative permeability at the same water saturation.
The parameters derived from laboratory experiments were used as input for reservoir simulation models to investigate the potential of low salinity water flooding in the reservoir using two layered box models. Findings showed that low salinity water accelerated oil production by increasing the oil relative permeability, thus resulting in a higher recovery factor with only a fraction of pore volume of low salinity water injection. Implications of these findings, such as slug size, salinity of injected brine, non-uniqueness of derived relative permeability curves on incremental oil recovery were assessed.
This paper is novel in the following aspects. First, the potential of low salinity water at a high reservoir temperature of 140 °C was systematically investigated. Second, laboratory experiments showed that low salinity water changed the reservoir wettability towards more water-wet, which is consistent with the observed shift in the relative permeability curves derived from core-scale numerical simulation. Third, the potential of the low salinity water in such high temperature environments was assessed using reservoir simulation based on the input from laboratory experiments.
A Unique Anti-Salt Polymer for EOR
Authors: Zhang Xiaoqin , Li Xia , Guo Songlin , Sun Gang , Guan Wenting 
Published: October 2016

Abstract
Daqing Oilfield is a heterogeneous sandstone oilfield with multiple layers. In order to protect the environment, produced water is widely recycled to prepare polymer solution, leading to great polymer consumption and poor economic effectiveness. For this reason, an exploratory research on anti-salt polymers is carried out. Polymer LH2500 is screened out and applied in pilot test in No.3 Block of Xingbei development zone, Enhanced recovery factor reached 10.3%, 45% polymer consumption was saved for ordinary polymers.
However, as produced water is recycled to prepare polymer solution, anti-salt polymer pilot test is urgently needed. To further enhance the recovery factor, anti-salt polymers of low concentration should have high viscosity in the high underground salinity.
Performance Culture Using Technical Limit Methodology: Learnings from Two Years of Deepwater Drilling
Authors: Crea F.. , Rabbitte T. P. , Lyons A.. , Chircop J.. 
Published: October 2016

Abstract
This paper describes a two-year journey drilling deepwater exploration wells across three different countries, in challenging market conditions. The journey began in 2013 when the Transocean Deepwater Millennium was contracted by Woodside, in a 100 USD/bbl oil price environment, to drill deepwater exploration wells in Western Australia. The drilling campaign commenced in April 2014 with difficulties experienced through the first two wells. A recovery plan was initiated in late November 2014 that saw continuous improvement and top quartile performance achieved by the end of the campaign. These results were achieved despite the oil price falling below 35 USD/bbl and an unplanned transition to international waters in South Korea and Myanmar.
This paper focuses on the practical steps taken by the Woodside (Operator) and Transocean (Drilling Contractor) leadership team to influence workforce culture and recover from a slow start.
The recovery plan began with the alignment of Transocean's Management, Woodside's Management and the offshore leadership teams' vision and objectives. Technical Limit (TL) methodology was used to develop a set of performance indicators to monitor rig efficiency, establish clear and achievable targets for the off-shore crew, and to address the top five priorities for improvement.
Dynamic Production Targeting in Unconventional Gas Forecast Simulations Under Complex Economic and Facilities Constraints
Authors: Coman Chris , Mohiuddin Zeeshan 
Published: October 2016

Abstract
Unconventional gas fields can contain thousands of wells that may be located in geographically distinct areas, on a number of different authority to prospect (ATP) lease blocks. Wells flow to surface facilities that have varied fuel consumption rates and production constraints and which may also be located under different ATP leases to the wells. ATP leases may be wholly owned by the operator or production may be split with joint venture (JV) partnerships, under potentially complex production sharing contracts (PSC). Operators will have known gas contracts and predicted future gas demand that they must supply, but the full-field production rates required to meet these targets, following distributions, are unknown and variable.
This paper will present a methodology to dynamically control full-field production targets during simulation, such that the operator's predicted future gas demand can be reliably modeled, after fuel gas and JV equities are accounted for. The amount of excess production needed in each timestep is not fixed, and it changes dynamically based on many factors, such as block productivity, surface facility constraints, and the terms of the PSCs. This, and other complex behaviors can be captured and modeled within the solution, with relative ease.
The solution designed uses simulator keywords and user-defined quantities (UDQs) to account for all of these factors during forecast simulations of the model. Following implementation, the required full-field gas production target is dynamically calculated at each timestep, such that it meets the operator's gas demand, after removal of fuel gas and JV equity. This approach can significantly reduce the time taken to produce a valid production forecast, with production optimized to meet capacity limits in all cases and desensitized to subsurface and operational change. We describe in depth the rationale and technical details of the solution and provide an example case to demonstrate its implementation.
Top 10 Improvement Suggestions For Delivery Of Mega Projects
Authors: Alotaibi Mohammed Saad 
Published: October 2016

Abstract
With oil prices more than halved over the last year, the oil industry is gradually slipping into the red. Out of the 10 of the 20 European and North American oil and gas producers that have reported third-quarter results, seven have posted losses (Arab Times, 29 Oct 2015) with the remaining 3 reporting sharp drops in profits. Also oil producing countries are affected by the drop in oil price and several are reporting state budget deficits for 2015.
At current oil prices and oil price predictions, the challenge to find and deliver economically viable development opportunities (projects) is greater than ever.
Although many articles have been published on how to execute large projects, the industry still makes many unnecessary mistakes. Although estimates and statistics vary, general consensus is that the industry is still "losing" billions each year from poor project execution.
The article addresses the following topics; Poor Front End LoadingChanges during project executionNo or small Owner's teamProject is Schedule drivenInsufficient Operations input in (Toxic Facilities) DesignMega projects considered just bigger projectsRisk can be transferred to ContractorNo robust quality assurance planNo integrated teamsInsufficient stakeholder management
Optimising Upstream Separation Facilities by Retrofitting Existing Separators and Using Inline Separation
Authors: Westra R. W. , Barker R. A. 
Published: October 2016

Abstract
Existing operating facilities are often restricted by key bottle necks in the processing facilities that limit overall production. Typical bottlenecks limited capacities of separators and scrubbers that lead to liquid carry-over and in turn impact downstream compressors; water-in-oil emulsions leading to off-spec crude oil and too high oil-in-water content to meet discharge or re-injection specifications. By addressing and removing these bottle necks in a cost efficient matter the overall production and revenue of the crude oil production facility can be increased.
Especially in the current environment, any investment costs should be balanced by a quick return on investment to make good business case for investment. In this work a general retrofit strategy is presented, that consists of several steps, including problem analysis, bottleneck finding, different solutions strategies, and a selection phase. The focus is mainly focused on how to optimize separators and get the most out of existing production facilities.
A large focus of the production optimization methodology presented is on limiting the CAPEX requirement of proposed solution, in order to meet reduced budgets from oil operators in an industry suffering from declining crude oil prices. In order to achieve this different solution strategies are available and presented in this paper. Several case studies are presented in this paper, which clearly show benefits of the structured approach outlined. These cases shown how bottle necks are removed and overall production of a facility is increased.
Real-Time Interpretation of Leak Isolation with Degradable Diverter Using High Frequency Pressure Monitoring
Authors: Bogdan Andrey V. , Keilers Adam , Oussoltsev Dmitri , Lecerf Bruno 
Published: October 2016

Abstract
Degradable diverters are commonly used in multistage fracturing to increase the number of fractures along the wellbore and provide temporary isolation. Still, interpreting the effects of a diverter downhole remains challenging. In this paper, a nonintrusive monitoring technique is presented, which enables interpreting the effects of the diverter on multistage fracturing treatments.
This technique relies on the processing of pressure data acquired at high frequency. Unlike other monitoring techniques, its deployment is straightforward and relies only on surface acquisition and interpretation algorithms. It does not necessitate any change or additional steps in operations by utilizing events which are part of fracturing treatments. Data are interpreted on-site and in real time, and the results lead to an improved understanding about the performance of the diverter downhole, the evolutions of the wellbore connectivity with the formation, and the degradation process of the diverter.
The high-frequency pressure monitoring (HFPM) technique was used during several multistage fracturing operations. We present a case where the degradable diverter was used to effectively plug a leak during the fracturing treatment. The leak had inadvertently developed in a region of the well toward the heel, threatening the fracture stimulation stage aimed at the toe of the well. The HFPM technique was used to locate the leak, confirm its successful plugging with a degradable diverter, and monitor the degradation of the diverter. The HFPM provided control of the leak and data on when to pump additional diverter and the effects of the operation. The example demonstrates in a compelling manner that the HFPM technique enables real-time decisions that ultimately improve multistage fracturing treatments and operations relying on effective isolation and diversion.
The HFPM presented herein is a novel, nonintrusive method for monitoring multistage operations and enabling real-time decisions. The technique is particularly valuable for monitoring treatments that rely on diversion and zonal isolation. HFPM is enabled by state-of-the-art signal processing and interpretation algorithms. It has the potential to become a ubiquitous technique that is part of each and every multistage fracturing treatment.
Modelling of Drainage Capillary Pressure: Using the Modified Carman-Kozeny Purcell Model to Identify the Type of Pore Throat Distribution Inherent in Laboratory Data
Authors: Behrenbruch Peter , Do Huu Minh Triet , Bui Khang Duy , Hoang Tuan Gia 
Published: October 2016

Abstract
Capillary pressure relationships (drainage) involve key SCA parameters measured in the laboratory. Reservoir engineers use capillary pressure relationships in reservoir engineering calculations and dynamic reservoir simulation and petrophysicists use such relationships in saturation-height modelling. The objective of this paper is to describe a novel technique to identify pore throat or grain size distributions from capillary pressure profiles.
Capillary pressure, laboratory data are traditionally obtained from three different types of experiments: centrifuge, porous plate and mercury injection. The modified Carman-Kozeny Purcell (MCKP) model may be used in matching various laboratory results. Initial application of the MCKP model involved a standard matching procedure without differentiating according to the type of pore throat or grain size distribution. In this paper a refined, more powerful analysis technique is described in detail where matching of any laboratory data with the MCKP model is obtained in model space, showing various characteristics.
Characteristic profiles observed in model space can be directly attributed to the type of pore throat or grain size distribution: homogeneous (narrow), broad (poorer sorting) and bimodal (two distinct distributions), or a mixture of distribution types. Comparison of model generated profiles with laboratory curves indicate a high degree of congruence, typically R2 &gt; 0.99, consistently better than any other capillary pressure formulation. The technique is also able to pick up artefacts, such as a sample fracture or laboratory procedural issues. It is shown how the MCKP model may be used in predicting capillary pressure relationships from basic parameters by building a framework based on end-point correlations derived from available laboratory data.
The paper presents various examples and a detailed case history for the Bayu-Undan gas field, covering various pore structure and diagenetic characteristics.
Reinstating Well Integrity in Severely Buckled Tubing
Authors: Mackie Colin , Bill Bjorn , Masson Graham , Kinch Elliot 
Published: October 2016

Abstract
Restoring well integrity with through-tubing intervention straddles is a relatively common activity. It is normally a lot less complex and less technically challenging than a more expensive well completion workover. However, a particular well in the North Sea was far from straightforward and presented a near impossible intervention challenge. The production tubing was severely buckled, which significantly reduced the effective tubing drift to depth and it was evident that the solution required extremely robust intervention equipment.
The well was completed as a primary sand column oil producer. The well experienced extensive corrosion and suffered from complex well integrity challenges. Initial attempts to restore well integrity were not successful, primarily due to the reduced tubing drift. Calliper interpretation software was used to identify the areas of significant corrosion within the tubing. Wellbore modelling revealed severely buckled tubing above the required straddle setting depth. The operator was forced to source a slim straddle design which was capable of passing through the tight restrictions.
The Anchored Production Straddle (APS) was the solution, with its small OD and relatively large ID. The APS was then customised to accommodate the depth and length parameters of damage within the well. The APS was successful in returning a challenging well to production and reinstating the production tubing integrity.
Due to the nature of the well, the robustness of the APS allowed for more than 150 downward jars through the tight restriction to deploy to depth. Despite the significant jarring, the APS was successfully set and the post-operation leak detection proved the straddle integrity.
The paper will look at the qualification tests done on the equipment, the execution of the operation, and the behaviour of the well before and after the intervention operations.
Optimal Selection of Materials of Construction for Gas Processing Facilities; Lessons Learnt from a Design Case Study
Authors: Lawrence Praveen , Marriott James , Giovanoglou Apostolos 
Published: October 2016

Abstract
In gas processing facilities, the minimum metal temperatures (MMT) in process equipment and piping are usually observed during highly transient depressurization operations ("blowdown"). The MMT usually sets the material of construction and can have a huge impact on project costs and ultimately project viability.
To explore this issue we use a recent case study that considers the design from Pre-FEED through to Final Investment Decision of a gas processing facility. During pre-FEED, the most widespread methodology for designing the depressurization system, based on idealized equilibrium volumes, was applied. This showed that extremely low metal temperatures could be expected in nearly all parts of the processing facility. To avoid material embrittlement, large vessels and piping would have required expensive stainless steel construction for ~80% of the facility.
As a result, a more detailed methodology for accurate assessment of MMT during depressurization was applied. This methodology involves a detailed representation of the processing facility using accurate dynamic models and requires a greater level of analysis and more effort. It does, however, account for different system pipe and vessel dimensions and wall thickness; as well as system elevations, points where condensate liquid may accumulate, drainage and the location of blowdown valves. The results predicted much more accurate MMT at each location throughout the processing facility.
Having identified specific locations of concern, the design team developed targeted solutions addressing all predicted issues whilst minimizing capital expense. Savings were achieved by optimizing material selection and other critical design specifications. By utilizing the detailed blowdown methodology throughout the design cycle only 30% of the facility is being constructed from stainless steel.
We conclude by reviewing the different methods for depressurization system design, their relative merits and discuss how designer engineers can identify systems that require more thorough attention.
Improvement of Production Data Analysis Method for Shale Gas Wells
Authors: Wei Pang , YouZhi Duan , Hui Yue , Juan Du , Tongyi Zhang 
Published: October 2016

Abstract
Rate normalized pressure (RNP) and derivative (RNP') method uses the log-log plot of RNP and RNP' versus material balance time (te) to interpret formation and hydraulic parameters like permeability and fracture half-length. It's a very useful methodology and sometimes the only way to conduct transient rate and pressure analysis for shale gas wells because pressure buildup is rarely recorded. However, the method may be not applicable because material balance time is not a monotonic increasing function of time especially when the one well has a short production history and has big vibration of production rate. A new method is proposed to solve the above problem for shale gas wells.
In the new method, the average material balance time (cumulative production (Np) divided by average gas rate) is used to replace te. Therefore, the increasing monotonicity with production time is guaranteed. Curves of te vs. production time and average te vs. production time are contrasted. Different field cases with smooth decreasing gas rate and the cases with sharp change rates are used to check the applicability for the proposed new method. The plots of RNP & RNP' vs. average te, RNP & RNP' vs. te are drawn for different shale gas wells data for accuracy comparison.
Results show that the new method has similar type-curve with the RNP & RNP' vs. te method and can be used to interpret the formation and hydraulic parameters by diagnosing typical flow regimes for shale gas wells. Compared with the RNP & RNP' vs. te method, the new method theoretically improved the accuracy production date analysis because the x axis is a monotonic increasing function of production time while not showing inflection points in RNP & RNP' vs. te plots. Field case with smooth decreasing gas rate shows that the new method and RNP & RNP' vs. te method can both get satisfactory log-log plot match and rate & pressure history match. Although the RNP & RNP' vs. average te may give smaller SRV volume, the interpretation results for both methods are comparable. The shale gas case with sharp vibrated gas rate shows that the new method can get both better log-log plot match and rate & pressure history match, in return, the interpretation results may be more confident.
The RNP & RNP' vs. average te method may improve the production data analysis (PDA) accuracy when the shale gas wells have huge rate vibrations which may be caused by fluid flow-back, choke size change, temporary well shut-in and etc. However, more shale gas wells data should be used to test the method.