bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cocurrent Spontaneous Imbibition In Porous Media With the Dynamics of Viscous Coupling and Capillary Backpressure
Authors: Andersen Pål Østebø , Qiao Yangyang , Standnes Dag Chun , Evje Steinar 
Published: October 2018

Summary
This paper presents a numerical study of water displacing oil using combined cocurrent/countercurrent spontaneous imbibition (SI) of water displacing oil from a water-wet matrix block exposed to water on one side and oil on the other. Countercurrent flows can induce a stronger viscous coupling than during cocurrent flows, leading to deceleration of the phases. Even as water displaces oil cocurrently, the saturation gradient in the block induces countercurrent capillary diffusion. The extent of countercurrent flow may dominate the domain of the matrix block near the water-exposed surfaces while cocurrent imbibition may dominate the domain near the oil-exposed surfaces, implying that one unique effective relative permeability curve for each phase does not adequately represent the system. Because relative permeabilities are routinely measured cocurrently, it is an open question whether the imbibition rates in the reservoir (depending on a variety of flow regimes and parameters) will in fact be correctly predicted. We present a generalized model of two-phase flow dependent on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media because of fluid/rock interaction (friction) and fluid/fluid interaction (drag). These momentum equations effectively replace and generalize Darcy's law. The model is parameterized using experimental data from the literature.
We consider a water-wet matrix block in one dimension that is exposed to oil on one side and water on the other side. This setup favors cocurrent SI. We also account for the fact that oil produced countercurrently into water must overcome the so-called capillary backpressure, which represents a resistance for oil to be produced as droplets. This parameter can thus influence the extent of countercurrent production and hence viscous coupling. This complex mixture of flow regimes implies that it is not straightforward to model the system by a single set of relative permeabilities, but rather relies on a generalized momentum-equation model that couples the two phases. In particular, directly applying cocurrently measured relative permeability curves gives significantly different predictions than the generalized model. It is seen that at high water/oil-mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less countercurrent to more cocurrent compared with conventional modeling. Although the viscous-coupling effects are triggered by countercurrent flow, reducing or eliminating countercurrent production by means of the capillary backpressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard cocurrent-imbibition setups.
Novel Approach in Digital Diagnostic for Plunger Lift in Unconventional Wells at Vaca Muerta
Authors: Barros J. L. , Claramunt J. I. , Ferrigno E.. 
Published: October 2018

Abstract
This paper presents studies performed to optimize the operation of the artificial lifting system, Plunger Lift, in wells producing unconventional oil in the Vaca Muerta Formation, Unconventional Region, YPF S.A., Argentina.
The field has more than 280 wells equipped with Plunger Lift. Most of them are instrumented, and automated, telesupervised.
Despite the level of technology deployed, both in the field and in SCADA systems, the dedication of specialized production engineers was necessary to study the wells on a daily basis and in real time, implementing exception handling, in order to detect early warnings and assess opportunities for optimization.
On the basis of experience in the operation and optimization of this extraction system and the work of multidisciplinary teams, diagnostic and decision making flowcharts were elaborated and then considered as early warning algorithms in SCADA control panels. This paper presents the results of these studies and the benefits obtained.
Plunger-Assisted Gas Lift and Gas-Assisted Plunger Lift
Authors: Burns Maggy 
Published: October 2018

Abstract
Plungerlift was installed in conjunction with gaslift to improve efficiency in delifiquification of unconventional gas wells. The dual artificial lift methods were implemented to more aggressively reduce bottom-hole pressure, in order to increase production in Barnett Shale wells.
Wells are selected based on a series of metrics, including gas-liquid ratio, fluid production, casing pressure and differential between casing and line pressure. The basics of both plunger-assisted gaslift (PAGL) and gas-assisted plungerlift (GAPL) both utilize injection gas and a plunger to optimize the well. Plunger-assisted gaslift is continuous injection and continuous plungerlift. PAGL is implemented on higher gas and fluid producers. These wells require the addition of injection gas to raise the critical velocity needed to lift both the plunger and the fluid of the well. GAPL is intermittent injection and conventional plungerlift. It is implemented on lower gas and fluid producers. Gas is only injected during certain phases of the plunger cycle to supplement the wellbore inflow and successfully lift fluid and plunger to surface.
This presentation will describe the process and results of installing PAGL and GAPL on specific case studies in the Barnett Shale. Historical data, including production, pressures and producing methods will be presented, to compare the results of prior lift methods to those of PAGL or GAPL. By implementing PAGL and GAPL, bottom-hole pressure was successfully lowered and production increased. A secondary benefit is the reduced quantity of gaslift that results in lower operating costs and a more-effective use of horsepower. The results of over-injection in unconventional wells will also be notated.
This presentation will detail the benefits and results of dual artificial lift that can efficiently and economically add value to a field.
Challenging Sand Producer Well Handling with PCP in Eastern Desert, Egypt
Authors: Alsawi Kamel , Hegazy Mahmoud , Elhady Khaled , Sayed Mahmoud 
Published: October 2018

Abstract

Objectives/Scope
Kuwait energy company has started to develop oil reserves since 2008 in AREA-A Concession, started with production of 2,000 BOPD increased to 7,300 BOPD in 2017, and due to presence of depleted and shallow wells in YUSR Field "main producing field" in the concession, sand production troubles started to increase, and one of the challenging wells "YUSR-38" which was re-completed on Rudis-1B reservoir via beam pumping system; but unfortunately the well failed three times due to plunger sticking in barrel and caused some complicated fishing operations due to sever sand production; however increased the plunger clearance to -0.007 and used sand screen with the pump, tried to restore the well production via running the well with PCP but unfortunately sand fall down above the pump and lead to stuck again.
Therefore, initiated a challenging objective to restore the well production and to get learned from the previous well failures via running well designed PCP to handle the sand production and to handle the maximum well productivity matching the current reservoir depletion

Methods, Procedures, Process
Four ways were considered for maximizing the well productivity and to handle the excessive sand production, firstly perform sand clean out job till reach bottom of the hole and ensure rat hole is well cleaned due to limited volume of rat hole "6 Mt. inside 5″ casing", secondly Performed sand sieve analysis and determined the particle size of sand and calculated sand settling velocity, and hence took a decision to reduce the utilized tubing size from 3 ½″ to 2 7/8″ to increase fluid and sand velocity to overcome expected sand settling velocity, thirdly; increasing pump speed to overcome the expected sand settling velocity and utilized PCP size 15-1800 to match well depletion due to utilizing higher PCP speed, that is in addition pumping brine water from casing side to match PCP productivity due to increasing PCP speed to overcome sand settling velocity, and finally utilized slotted tag bar with PCP installation to avoid plugging pump intake with sand due to limited volume of rat hole

Results, Observations, Conclusions
The well productivity was restored and the well is currently producing 100 BOPD with current life time exceeds 3 months and still working; while in the previous installations the life time didn't exceed two weeks, and production didn't exceed 60 BOPD.

Novel/Additive Information
The well productivity was restored and the well is currently producing 100 BOPD with current life time exceeds 3 months and still working; while in the previous installations the life time didn't exceed two weeks, and production didn't exceed 60 BOPD.
Impact of Gas Lift Design in Unconventional Wells - A Delaware Basin Operator's Perspective
Authors: Kannan Subash K , Boyer Matthew , Dufresne Jeff , Gonzalez Luis E. 
Published: October 2018

Abstract
Gas lift is becoming a predominant, intermediate term, artificial lift system in the Delaware and other basins. Besides the proper selection and management of the gas lift systems, design methodology is still a challenge due to the drastic change in flow conditions in the transient phase. The main objective of this paper is to develop a new methodology to design and optimize gas lift wells in unconventional reservoirs. A case study is provided to review, model, and analyze the current design over different stages of the well's production life. Consequently, application of new designs over different stages of the well's life will be implemented using a performance comparison which includes production and unloading scenarios. Actual well data will be used along with steady-state and dynamic modeling for unloading and production performance estimation. The models will be evaluated using actual data to perform history matching over different stages of the well's production life. This evaluation will also answer the following questions: Is the use of conventional mandrels the best option for these types of wells? Are the number of mandrels deployed using the traditional design methodology the correct solution? Are the tools used to design and analyze these types of wells sufficient? Most importantly, is more data required to create a better design and analysis? Also, this study compares the existing design to modified designs and justifies how the later could perform better. Integration of all data sources including historical performance, flowing bottom hole pressure, inferred dynamic IPR data, and the use of dynamic and nodal analysis tools for modeling while varying production conditions and unloading scenarios.
Innovative Downhole Design for Optimizing ALS Installation at Shale Oil Wells
Authors: Cuneo I.. , Ardito J. M. , Rivero G. Garcia 
Published: October 2018

Abstract
The aim of this paper is to show how tubing (TBG) installation has evolved, with the problems and learning processes experienced along the brief history of exploitation of the Vaca Muerta formation in the Loma Campana field.
The production behavior of wells from Vaca Muerta consists initially of flows close to 100m3/d, with sufficient pressure to produce natural flowing by the 5" casing, controlled by an orifice at wellhead.
Once the flowing period finishes, the well starts using mechanical pumping to keep producing with this system in the long term. Wells with a higher gas oil rate (GOR) are converted to plunger lift before resorting to mechanical pumping.
Due to the fact that a well experiences different extraction stages in a relatively short period of time (flowing by casing - flowing by TBG - Plunger Lift - mechanical pumping), it is necessary to find an installation that is flexible enough to allow switching from one stage to the other with the least amount of slickline and pulling interventions.
Likewise, the installation should be able to minimize the effects of sand and gas existing in Vaca Muerta, which affect the performance of mechanical pumping.
Thus, this paper shows how TBG installations have changed to finally reach the current installation. This installation allows the conversion of a flowing by TGB installation into a mechanical pumping installation with gas buster, poor boy type, using slickline intervention and pump and rod running, thus avoiding the necessity of moving the TBG.
Getting Wells Back to Production Using an Innovative Artificial Lift System for Recovering Inactive Wells
Authors: Vargas A. F. , Duran J.. , Simpson A.. , Santos R.. , Doval J. M. , Muñoz L.. , Patino Jerez A. E. , Rativa C.. , Hernandez N.. , Rozo Rozo , Rios D.. 
Published: October 2018

Abstract
This paper presents a successful application and the lessons learned during a pilot test under which a new electrical submersible pumping technology was installed in 4 wells. These helico-axial downhole pumps, V-Pump, were installed under a program of new technologies testing, which aimed for artificial lift run life extension in an extremely high sand-producing field under current cost constraints.
The oil price turndown forced Casabe Field to leave some wells inactive, even though they still have significant reserves. The cause of this decision was the expenses associated to the high frequency of interventions required due to the adverse sand production effects on the artificial lift systems.
Due to the low run life of conventional artificial lift systems that are customary to use in the field, it was necessary to search for emerging technologies that would meet the challenge presented. A screening process for new technologies were conducted, and after that, these pumps were installed in four wells, which were continuously monitored with downhole temperature, vibration and pressure sensors, fluid levels measurement, VSD readings and production tests, which would allow to understand the technology performance to achieve the desired run life, oil production gain, and to obtain lessons learned to design the second phase of the testing project.
The use of this innovative pumping technology extended the run life in the pilot wells between 180% and 420%, allowing the production of their remaining oil reserves, and giving a new approach in the production strategy of the field. One well is still running after 13 months.
Also, based on the on the information collected during the well production phase, through downhole sensors and VSD parameters, and the findings during the pump's dismantle, some recommendations were made to improve the performance in the second phase of the project. Recommendations include both improvements in the pump design and to the screening process of candidate wells.
Development of Low Toxicity and High Temperature Polymer Drilling Fluid for Environmentally Sensitive Offshore Drilling
Authors: Liu Xiaodong , Xie Binqiang , Gao Yonghui , Gu Huiling , Ma Yongle , Zhang Yong , Zhang Ruxin , Li Qingyang 
Published: October 2018

Abstract
It brings severe challenges to drilling fluids when drilling high temperature deep well in environmentally sensitive sea area and facing strict environmental protection laws and regulation requirements meanwhile, the toxic value of drilling fluid must reach up the standard requirement of 30,000 mg/L.A new, environmentally safe water-based polymer system has been developed for drilling applications with temperatures resistance to 200°C and biological toxicity value LC50 more than 100,000 mg/L.
The new system consists of two basic polymeric components for high temperature rheology and filtration control, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight material, providing superior performance for a variety of drilling environments. The system shows the base slurry is light colored and non-toxic to the marine environment, which can be discharged directly into the sea. The environmental friendly feature is a significant superiority over traditional high-temperature systems, such as sulfonated drilling fluid and oil-based drilling fluid which normally require the use of a large number of poisonous additives.
Experiments show that the new system has three important characteristics. Firstly, thermal stability time is more than 72h when aging at 200°C, HTHP filtrate loss is in the range of 12 to 25mL between temperature of 150 and 200°C, and sodium chloride and calcium chloride pollution resistance reach up to 200,000ppm and 5,000ppm, respectively. Secondly, the characteristic of excellent lubricity and inhibition can be comparable to oil based drilling fluids. Thirdly, the low biological toxicity also is one the most important characteristic, 96h LC50 semi lethal concentration of artemia is more than 100,000 mg/L, and EC50 median effective concentration of luminescent bacteria is more than 300,000 mg/L, which meet the biological toxicity discharge requirements for the first level sea area.
The extensive testing results of this new drilling fluid demonstrated its superiority characteristic and low biological toxicity to marine environment. Good results from field testing in Bohai offshore oil field are also presented, the deepest test well depth is 6066m, and the highest downhole temperature is 204°C.
Well Control for Offshore High-Pressure/High-Temperature Highly Deviated Gas Wells Drilling: How to Determine the Kick Tolerance?
Authors: Chen Xuyue , Yang Jin , Gao Deli , Huang Yi , Li Yanjun , Luo Ming , Li Wentuo 
Published: October 2018

Abstract
Kick tolerance is a vital parameter for well control. It indicates if a shut-in operation can be performed or not, an appropriate method of well killing should be selected. However, the kick tolerance determination for offshore high-pressure/high-temperature (HP/HT) highly deviated gas wells drilling still remains as a challenge to the oil and gas industry due to the presence of narrow safe mud weight window of the HP/HT well section, complex borehole temperature profile, influx distribution and high frictional pressure loss. In this work, a model of volume kick tolerance specific for offshore HP/HT highly deviated gas wells drilling was presented based on the pressure bearing capacity of highly deviated open hole, casing shoe, casing, blowout preventer (BOP) and choke valve. Meanwhile factors affecting the volume kick tolerance were also investigated. The result shows that both of the volume kick tolerance for shut-in and the volume kick tolerance of well killing increase with wellbore inclination of the highly deviated section, and the highly deviated wellbore or highly deviated wellbore may have a much higher volume kick tolerance than that in vertical wellbore. With other parameters values setting constant in this case, the volume kick tolerance of well killing increases with the geothermal gradient while the increase rate is not obvious. This work provides a practical tool for enhancing well control in offshore HP/HT highly deviated gas wells drilling.
First-Time Implementation of Water Management Technology to Improve Water Flooding Performance in a Multi-Restriction Injector Well: Brownfield Redevelopment, Onshore Thailand
Authors: Thawatthukool Prasen , Toempromraj Wararit , Lilaprathuang Pipat , Kaewwetchawong Chasin , Weeramethachai Deephrom , Kiatrabile Thanita , Krisadasima Supakorn , Wattanasuwankorn Reawat , Daohmareeyor Tuanangkoon , Kangsadarn Arweephan , Kritsanaphak Kritsana , Pathmanathan Indran 
Published: October 2018

Abstract
An operator recently launched a "water-shutoff" polymer development project for an onshore injector well in a brownfield operation in Thailand. To effectively improve water flooding performance in this field, shutting off a water thief zone was a prerequisite.
Several conservative expanding tubing pads placed in the upper zones restricted access to the lower zone perforations or placement of another tubing pad in the lower zones; therefore, operational planning and strict laboratory testing were performed. This included setting-time testing using an actual chemical blend in batch mode, which closely simulated bottomhole conditions. The process required shutting off the upper zone to facilitate water injection into the lower zone, employing coiled tubing (CT). The design consisted of a shut-off treatment with a lost-circulation material (LCM) to help ensure wellbore fluid placement and shutoff in the high-permeability water thief zone at the designated positions, and to ensure that the pressure response could be monitored from the surface.
The shut-off operation was performed as planned, and CT was used for cleanup after placement. Water-production monitoring has shown that the shut-off polymer is one of the best solutions for this field in terms of safety, economics, and operation. As a result of well testing, after the thief zone shut-off treatment, water injectivitywas decreased by approximately 97%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer’s seal-off performance for development of future field strategies. Such an operation could help increase oil recovery by 5 to 10% of oil in place.
This technique does not require mechanically sealing off the perforations, making it more feasible for future well interventions and enabling a greater injection rate for chemical EOR where desired.