bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Slow and Fast Warm-Up Rates on Cement Sheath Integrity in SAGD Wells: Using Dynamic Flow Simulators for Early Time Analysis
Authors: Nascimento C. M. , Demirdal B. 
Published: October 2017

Abstract
The original viscosity of the oil in place is greater than 1,000,000 centipoises in most cases in Western Canada. As a result, steam assisted gravity drainage (SAGD) is a widely used thermal recovery method to produce bitumen reserves for the last 10-15 years. SAGD involves drilling two horizontal wells (one on top of each other roughly 5 meters) apart and injecting steam from the top well (called "injector") to reduce the viscosity of oil in place by heating and produce the flowing oil from the bottom one (called "producer").
Initially, there is very little to no pressure communication between the injector and producer since the bitumen is in solid state. As a result, in order to initiate communication between the wells so steam injection can penetrate into the reservoir to heat the rock and the fluids, both wells were circulated with steam and this phase is called "circulation". During circulation, steam is injected to the wells through long tubing and returns are received back through short tubing. In addition to be quite critical to the overall production performance of the reservoir, circulation phase has a critical impact on the integrity of the well since during this phase the well was introduced to heating for the first time. Considering the fact that steam is being injected in a cold well, thermal loading impacts on casing and cement are expected to be the highest during earlier times of circulation. While injecting steam at higher rates as early as possible has operational benefits, effects of such practice on zonal isolation should be evaluated in detail.
A well operated by Devon in Jackfish field was used for this purpose and a dynamic flow simulator was modelled to investigate the impact of slow (going from 1 ton/hr to 5 ton/hr in 5 days) versus fast warm-up during early stages of circulation phase on cement sheath. Field data captured by distributed temperature sensing system (DTS) was used to validate the model and comparison on cement heating rate at different depth intervals during slow and fast warm up cases were made to determine at what depths and durations the heating rates of cement are different between the two cases.
The combination of the field results and simulation enabled to determine the critical time frame where different circulation strategies have the highest impact on cement heating rates. The simulation results also provided insight on transient temperature distribution across wellbore and near wellbore during early times of circulation.
Design Optimization of Slotted Liner Completions in Horizontal Wells: An Analytical Skin Factor Model Verified by Computational Fluid Dynamics and Experimental Sand Retention Tests
Authors: Mahmoudi M. , Nejadi S. , Roostaei M. , Olsen J. , Fattahpour V. , Lange C. F. , Zhu D. , Fermaniuk B. , Nouri A. 
Published: October 2017

Abstract
The term skin is used to describe pressure drop caused by a flow restriction near the wellbore. The skin factor of wells completed using slotted liners can be explained by a number of phenomena including: the flow across the slots, flow convergence towards slots, near wellbore permeability, and occlusion of liner open area due to corrosion and scale deposition. This paper introduces an analytical skin model for the slotted liner, which incorporates these phenomena, and can be used to optimize the slotted liner design. The introduced analytical model was verified by physical and Computational Fluid Dynamics (CFD) models.
The proposed analytical skin factor model for slotted liners is based on slot width, slot density, the spatial distribution of slots, and near-liner permeability. The model also incorporates partial plugging of slots. The model is validated using experimental Sand Retention Testing (SRT) data. A series of SRT experiments were conducted at different flow rates for two Particle Size Distributions (PSD) from the McMurray Formation in Northern Alberta. The experiments were also modeled by the CFD to better understand the flow dynamic near the liner.
Results of the analytical model and experimental tests were generally in agreement. However, results of the analytical model deviate from experimental tests for narrow slots and high flow rates. In these cases, the analytical model predicts smaller skin than the experimental tests. For cases related to narrow slots and higher velocity the pore plugging close to the liner is significant which was not modeled in the analytical model. Moreover, for very fine sand (low permeability) sand-pack the deviation from the experimental results is higher in comparison with medium uniform sand (higher permeability) sand-pack. CFD simulations showed the effect of the slot width on the depth of the convergence zone, which is not included in the analytical model. Since the analytical model follows the experimental results for common flow rates in thermal production, the model could be used to assess the skin for different possible designs and choose the best slot specifications that minimize the skin.
This paper presents the details of an analytical model for the skin factor verified by experimental data and CFD simulation. This analytical model can be used to optimize the liner specification for the best flow performance. This paper also outlines the limitations of the analytical models for calculation the skin/pressure drop.
Effective Application of Combination Technologies and Processes for Successful SCP Well Abandonment
Authors: Amanov Bauyrzhan , Aidoo Ato , Khouzin Azat , Lommers Cas , Viti Massimo , Valiakhmetov Rustem 
Published: October 2017

Abstract
This paper discusses the effective application of a Combination Technologies and Processes that allowed successfull abandonment of wells with Sustained casing pressure (SCP), on the Karachaganak field. The planning and execution processes of SCP elimination are examined.
Previous experience in the abandonment of wells with SCP using existing procedures and methodologies for cement and bridge plug placement, on the Karachaganak field, has not always been successful. In some instances sustained casing pressure reappeared, resulting inadvertently in re-entry for intervention.
In 2015 several SCP wells were successfully abandoned using a combination of technologies. The processes will be described in detail in this paper, including:
Image log to enable selection of the interval for section milling Section milling - removal of a section of casing Under reaming to remove remaining cement sheath from the wall of the outer casing Inflatable Bridge Plug - mechanical barrier for placement in the opened window interval.
Karachaganak is a giant gas-oil condensate field with presence of H2S and CO2. Due to that, during well abandonment SCP issue must be eliminated to comply with Republic of Kazakhstan regulation and oil industry standards. SCP, regardless of its value can pose hazards not only to the environment but also be a source of formation of man-made deposits. To ensure industrial safety, environmental expediency and to meet regulatory requirements, the wells with SCP require regular monitoring.
The above mentioned technologies and processes were successfully implemented in wells abandonment and elimination of SCP on wells in the Karachaganak field. All wells were monitored throughout the year, considering the huge variance in the severe ambient weather conditions throughout, and it was proved that no issues with SCP have reoccurred so far.
This paper provides well construction and integrity teams’ information on a solution that could be used in many other wells around the world. The benefits achieved by the Kazakhstan operator open up opportunities to solve SCP problems and prevent future intervention.
The Role of Internal Diameter Tolerances in Interpreting Casing Inspection Logs
Authors: Atakishiyev Fuad , Alkhasov Emin , Schoepf Virginie , Zett Adrian 
Published: October 2017

Abstract
Multi-finger caliper tools are widely used for inspection of casing inner wall condition, particularly for determining wear, corrosion, deformation and scaling. The maximum pipe wall penetration, and hence metal loss, inferred from this method is greatly dependent on the casing inner diameter value (provided by casing manufacturer) used as a reference. Evidence of overestimated casing wear, including new completions, has raised the question around the validity of such interpretations.
Most of the casing is manufactured to API 5CT (ISO 11960) standard. The manufacturer‘s specification has an associated tolerance on casing outer diameter and thickness that is then used in the multi-finger caliper logs interpretation. The tolerance for casing with outer diameter (OD) greater or equal than 4.5″, is between -0.5% and +1% of OD. The pipe wall thickness tolerance ranges between manufacturer's nominal thickness and 12.5% metal loss.
The calculation of casing internal diameter (ID) tolerance is a difficult task as this is controlled by the casing mass tolerance which in practice is not easy to measure. To overcome the challenge, we implemented a new approach of calculating the minimum and maximum casing inner diameter and then using the ID tolerance as a reference for multi-finger caliper logs interpretation.
This approach has been tested with field data, and shows good correlation to actual casing inner diameter measurements performed at surface and is used as a baseline for new casing strings.
This paper will describe in detail the approach taken and compare the difference between interpretation outcomes with and without using the casing inner diameter tolerance. The benefits of calculating casing inner diameter tolerance and applying it to multi-finger caliper log interpretation results will be backed up with evidence from field log data acquired in ACG.
The Comparison of Inflow Profiling Technologies for ERD Wells Including PLT, Fiber Optics DTS, Stationary Chemical Tracers: A Case Study from the Caspian offshore Yuri Korchagin Field in Russia
Authors: Shtun S. Y. , Senkov A. A. , Abramenko O. I. , Matsashik V. V. , Mukhametshin I. R. , Prusakov A. V. , Nukhaev M. T. 
Published: October 2017

Abstract
The purpose of this paper is to compare the permanent monitoring systems based on optical fiber systems and intelligent chemical tracers. This analysis was carried out based on an operational assessment of similar systems for permanent monitoring of horizontal wells in the Yuri Korchagin oilfield for 3 years in various regimes of operation.
The paper discusses the main advantages and limitations of these systems and provides their comparison to conventional production logging tools (PLTs).
Application of Experimental Design for Probabilistic IOR Evaluation at Korolev Field
Authors: Galimzhanov Saken , Iskakov Elrad , Levchenko Pavel , Turmanbekova Aizhan , Zhumagulov Kanat 
Published: October 2017

Abstract
Tengizchevroil (TCO) is the biggest operator in Kazakhstan developing two world's deepest supergiant oilfields - Tengiz and, its satellite field, Korolev. With over 20 years of oil production at TCO, reservoir pressure has been declining and is approaching bubble point pressure. In order to arrest the declining pressure trend and extend oil production plateau, TCO is evaluating Improved Oil Recovery (IOR) opportunities, including potential Waterflood in Korolev field.
Accurate Waterflood evaluation requires improved characterization of the main uncertainties impacting ultimate recovery under IOR processes. Therefore, we built next-generation Korolev reservoir model (SIM15K) which incorporates results of the latest characterization efforts based on the latest wide- azimuth 3D seismic survey. This work led to updated Korolev depositional model, which helps to understand the links between geological settings and fracture occurrence. In conjunction with the first implementation of Dynamic Data Integration workflow, this resulted into updated Low-Mid-High fracture models - one of the main factors controlling Waterflood performance in naturally-fractured reservoirs.
This paper focuses on Brownfield Experimental Design (ED) of Korolev field, which is specifically designed to provide an estimate of IOR Incremental Recovery. We identified 23 main uncertainty parameters for each Low-Mid-High Fracture models. The Brownfield ED was run with two development scenarios: Primary Depletion and Waterflood to get probabilistic assessment of Incremental Waterflood Recovery. Overall 803 cases were required for each fracture model and development scenario to generate good quality proxies for cumulative recoveries and History-Match error. Those proxies were used to sample the entire space of uncertainties and define P10/50/90 targets.
As a result of robust Brownfield ED, we selected P10/50/90 models to capture both range in Incremental Waterflood Recovery and Ultimate Recovery under Primary Depletion. The underlying uncertainty parameters for the final model selection were picked based on their relative impact on the objective functions. Currently, the new SIM15K model is being used for Korolev Waterflood evaluation and optimization, Reserves estimation, existing infrastructure optimization and future projects design.
An Integrated Pore Scale and Reservoir Modeling for Near Miscible Three-Phase Flow WAG Flooding Reservoir
Authors: Gibrata Muhammad A , Hashem Mohamed 
Published: October 2017

Abstract
Reliable of pore scale and reservoir modeling in reservoir with water alternating gas (WAG) flooding is challenging and important for getting an accurate reservoir characterization, enhanced oil recovery (EOR) and reservoir management. Inaccurate characterization and modelling of these reservoir properties and fluid will lead to high uncertainty of reservoir characterization, minimum oil recovery and reservoir management concerns. Hence it is useful to predict and assess effects on pore-scale and EOR of field scale.
The comprehensive pore-scale and reservoir modeling approach is required by the integration of various sources such as those from petrophysical, geological, reservoir and production data. Utilize the 3D network structure of representative reservoir rock properties. In prediction and guide SCAL based; investigation the effects (sensitivity) of interfacial tensions, contact angles, wettability, spreading coefficient, balance of viscous and capillary forces into miscibility on the oil layers between gas and water in a fully interconnected three-phase flow pore-network model. Utilize thermodynamic criteria for rock properties and oil layers, which affect the oil relative permeability for accurate prediction of residual oil and maximize oil recovery.
I have used an integrated pore scale and reservoir models workflow: establish pore network model, validate with SCAL, up scale to well logs, utilize formation pressure/sampling/testing and combine with structural data of geology-seismic and perform history match of the reservoir dynamic modeling. The effect of balance of capillary and viscous forces in pore scale have been evaluated in the research. It has provided a reliable properties for a reservoir dynamic model.
In the research, I have used similar range of reservoir and fluid properties such as pore throat size in reservoir range for pore network model. I analyze pore scale and field scale oil recovery during WAG at immiscible and near miscible condition to generate the three phase relative permeability models (by modified weighting for near miscible). The current simulations at the reservoir scale shows that the highest oil recovery for the water-wet is obtained by injecting near miscible gas. Recovery increased by over 10% during WAG injection in agreement with typical values on SCAL and pore network models.
The comprehensive approach of near miscible three phase flow WAG in pore network model, core-logs validation and the reservoir model are important in reservoir modelling. The integration is used for getting an appropriate relative permeability, capillary pressures and water saturation in near miscible Gas and Water Alternating Gas (WAG) flooding of reservoir. Thus it can give an accurate and robust of reservoir characterization, maximize oil recovery and optimum reservoir management.
An Evaluation of Microbial Flooding for Enhanced Oil Recovery, Fuyu Oilfield, China
Authors: Jinfang Wang , Zhengmao Wang , Jun Tian , Chengfang Shi , Jian Gao 
Published: October 2017

Abstract
This paper depicts the laboratory results as well as reservoir surveillance and well production performance of microbial flooding in Fuyu oilfield, China. A four-spot water flooding has been applied from 1973, and various measures to increase production has been implemented since 1981. However, 1/3 non-absorbing reservoir and the invalid circulation of injection water lead to low production rate, high water cut, big flooding difference and low sweep efficiency.
To reduce water channeling, the Microbial Enhanced Oil Recovery (MEOR) test was initialed in Fuyu oilfield, China, in 1992. A microorganism named CJF-002 fed on nutrient was discovered as huff-puff test from 1996~2001. To replace the nutrient with high cost, a new nutrient was developed, using cornstarch as main raw material from 2002~2004. Furthermore, multi-slug microbial flooding was conducted at 22 injection-production well groups in 2005. The cell count of CJF-002 was more than 10^7cells/ml, and injection pressure less than 10MPa. The concentration of CJF-002 and crude oil composition in the sample was analyzed in laboratory before and after MEOR. Moreover, injection profiles monitoring and tracer tests were compared. Finally, the results of laboratory and tests were contrasted with well production performances.
The results observed microbial propagation under reservoir conditions with temperature 30°C and PH 7.5. The effect of injection profile modification was confirmed, which was helpful for plugging the high permeable zones and reducing water channeling. The agreement is obtained with the well production performances. Among them, 87.3% wells indicated a 50~100% oil production increase and an 8% water cut decrease. The water-drive laws curve shows the characteristic of drop, which means the improvement of development effect. The tests show that the composite indigenous microorganism oil displacement technology can enhance the oil yield of mature oilfield and recovery ratio, and it is an effective stimulation measures.
Modelling and Verification of Gravel Pack Treatments in ACG Field to Improve Sand Control Reliability
Authors: Hasanov Hikmet , John Colin , Wassouf Philip , Jain Samyak 
Published: October 2017

Abstract
Proper design, installation and evaluation of sand control completions is vital for ensuring sand control integrity and mitigating against production deferrals due to sanding events. This is becoming increasingly important in the ACG Field, located offshore Azerbaijan, where wells require gravel pack completions with shunt tube technology and narrow operating windows between reservoir and fracture pressures. However, due to the lack of suitable commercially available software and a standardized workflow, gravel pack operations have been designed and evaluated using a combination of customized spreadsheets, historical data and software ported from other industry segments, none of which support the complex flow paths, conditions and range of technology utilized. While this did work, it was a time-consuming and inefficient process that required a number of assumptions and continuous data transfer which could allow for inconsistencies when applied at scale with an increasing number of users.
To improve and standardize the design and evaluation of wells in the ACG field, a novel, commercially available sand control software was introduced for performing pre-job modelling, on-the-job calibration and post-job analysis in an integrated workflow for all stages of the sand control operation including wellbore displacements, step rate tests, gravel pack and reverse out. The software supports all common sand control technologies and flow paths, enabling the determination of optimal completion and hydraulic configurations during planning, identification of potential issues and redesign of the treatment during installation, as well as automatic analysis of surface and downhole data for a more detailed understanding of downhole events and mechanisms during post-job evaluation.
This integrated workflow is presented using case studies from the ACG field to illustrate its application and benefits. The workflow is found to be simpler, more effective and more accurate than the techniques used in the past, enabling all necessary modeling to be quickly and easily performed in-house for improved planning and optimization of upcoming operations. Further, the automated analysis of surface and downhole gauge data enabled detailed evaluation to be completed in a timely manner which maximized the value of the acquired data and ensured lessons learned could be effectively implemented. Finally, the ability to directly compare simulated and actual treatment data allowed the engineers to calibrate and validate the model for more accurate modelling of future treatments.
A Pore Network Model for Studying Boundary Layer Effect on Fluid Flow in Tight Formation
Authors: Mingqiang Chen , Linsong Cheng , Renyi Cao , Chaohui Lv , Jiuzhu Wu , Hao Liu 
Published: October 2017

Abstract
Due to intensive heterogeneity and micro-nano-meter-scale pores in tight formation, flow mechanism differs significantly from that in conventional reservoirs. Therefore, the capability to simulate pore scale flow in tight formation is of great importance in many applications, such as oil extraction from tight reservoirs and accurate prediction of oil production. In this paper, a 3D random network model which can characterize the heterogeneity of tight formation is proposed. Based on the established network model, a flow mathematical model in consideration of boundary layer effect is developed, whereas parameters in boundary layer thickness formula are determined by Particle Swarm Optimization algorithm. Then, repeated iterations are used to solve the flow mathematical model until the relative error of pressure in each pore between two adjacent iterations arrives at the given error, which guarantees the accuracy of the simulation result. The result is then validated by micro-tube experiment. Furthermore, factors influencing pore scale flow in tight formation are studied. Results show that: as a result of boundary layer effect, absolute permeability is no longer a fixed value, it increases with the increase of pressure gradient and reaches a stable value when displacement pressure gradient is large enough. In low displacement pressure gradient, non-linear flow appears. As average coordination number increases, connectivity of tight formation becomes better, absolute permeability and velocity are larger at the same pressure gradient; When pore radius remains unchanged, as aspect ratio increases, throat radius becomes smaller, effective space for fluid flow is compressed, leading to smaller absolute permeability and velocity at the same pressure gradient; Change of 3D random network model size through varying throat lengths has little effect on pore scale flow; With the increase of fluid viscosity, boundary layer becomes thicker and the effective flow space grows smaller, resulting in lower permeability and velocity at the same pressure gradient. When displacement pressure gradient is large enough, absolute permeability tends to a stable value, which has nothing to do with fluid viscosity.