bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Well Selection Method Based on Improved Pressure Index for Polymer Flooding
Authors: Chen Cunliang , Han Xiaodong , Liu Xue , Wang Cheng 
Published: January 2020

Polymer flooding is one of the important measures to exploit the remaining oil in the middle and high water cut of oil fields. And the key to the success of the polymer flooding is the selection of the polymer flooding well. Pressure index (PI) and the degree of fullness (FD) are significant parameters, which are commonly used for polymer flooding project design and injection well performance analysis in China, due to their economical application. However, PI and FD are insufficient in discrimination and calculation method, which can only reflect the present heterogeneity of the formation. As a result, efficiency of polymer flooding decision might be not as good as expected.
Improved pressure index (IPI) is established on basis of PI and FD. IPI is the ratio of the mean of pressure to the downfall of the wellhead pressure under the condition of unit water injection. The smaller the IPI value, the more the polymer flooding should be made. IPI not only takes the present heterogeneity of the formation into consideration, but also the transformation of pressure variation tendency. And IPI is a dimensionless parameter, which keeps initial advantages of PI and FD—simple and low cost.
This method has been applied to nearly 50 Wells. The success rate of polymer flooding exceeds 92%. The measure reduce the water cut at the same time increase oil production. It not only improves the recovery yield, but also brings good economic benefit. In addition, the paper presents a field case study to validate the methodology. IPI is far more accurate than PI and FD. In summary, IPI is not only feasible, but also saves a lot of money.
IPI has been applied to several oil fields in Bohai. And the effect is remarkable, which provides a good reference for the development of other oil fields.
Drones Make a Step Change on How the Oil Industry Manage Safety and Environmental Risks
Authors: Saadawi Hisham 
Published: January 2020

Continuing development in the technologies of unmanned aerial systems or drones offer opportunities to the oil industry to make a step change to the way we manage safety and environmental risks. The use of drones can minimize exposure of personnel to dangerous environments, monitor the environment and enhance asset integrity.
The SPE vision is to advance the oil & gas community's ability to meet the world's energy demand in a safe, environmentally responsible and sustainable manner. HSE or Health, Safety, the Environment and Sustainability are core values in the oil & gas industry.
This paper reviews how the current and potential applications of drones in the oil industry can enhance safety and environmental aspects of oil and gas operations.
Experimental Study on the Wettability of Longmaxi Formation Shale in the Sichuan Basin, China
Authors: Tao Liang , Kang Ning , Deng Xianan , Hou Dianpeng , Guo Jianchun , Li Lingduo , Zhao Zhihong 
Published: January 2020

Abstract
The wettability of conventional reservoirs have been extensively studied in the past. However, Shale is rich in organic matter, composed of many mineral components in complex relationships, and contains pores of various scales from micrometer to nanometer, so it is very difficult to evaluate the wettability of shale. In this study, low field nuclear magnetic resonance (NMR) was used to test the water wettability of shale and a new mixed wettability model was built to quantitatively calculate the organic matter contact angle and evaluate the water wettability of organic matter. The experimental results show that the surface of the shale exhibits complex non-uniform mixed wettability, both oil-wet and water-wet; with the increase of soaking time, the water wettability of shale enhances significantly and the equilibrium time of water imbibition is 5-10 days; the average contact angle of water with organic matter is 75.2°, indicating water can enter organic matter pores, but at weaker capacity than entering inorganic pores. The research results are helpful for making clear the micro mechanism of the action between fracturing fluid and shale reservoir and designing fracturing scheme.
Enhanced Seismic Interpretation Guided by Multi-Azimuthal Borehole Seismic Data
Authors: Kumar Rajeev , Beck Byron , Al-Enazi Falah , Shabbir Ahmed 
Published: January 2020

In the oil & gas industry, surface seismic imaging is critical in defining the sub-surface structure & stratigraphy but could suffer from poor seismic resolution due to complex geology. This paper describes applications of Walkaway and Walkaround VSPs recorded over an oilfield with low surface seismic resolution located in the offshore Arabian Gulf. Two further challenges needed to be addressed: i) estimation of azimuthal anisotropy, and ii) calibration of PS seismic data.
Walkaway VSP was proposed as a viable solution to obtain the higher seismic resolution by placing the receiver below the strong shallow reflectors. A multi-azimuthal (4 orthogonal lines) walkaway VSP survey was acquired based on pre-survey modeling to achieve the objectives of higher resolution and calibration of PS data obtained during OBC acquisition. Walkaround VSP was also acquired in two settings: a deep setting to estimate the azimuthal anisotropy to provide information on presence of natural fractures in the main producing reservoirs, and a shallow setting to investigate the causes of a major lost circulation zone.
3-Component downhole receivers and a powerful seismic source (6-Gun Cluster) were used to acquire good quality signal below the near surface attenuating layers. Passing through an elaborate 3-component processing chain, the walkaway survey resulted in hi-resolution subsurface PP and PS images (both in time & depth). These images provide detailed sub-surface features which were not observed in the existing surface seismic, resulting in improved reservoir characterization, as well as calibration of the surface PS seismic data. Walkaround VSP data were interpreted in terms of fracture azimuth (Fast Shear direction) and fracture density variation with depth (ratio of transverse to radial amplitudes). The Walkaround VSP results show good correlation with core data across two discrete reservoir intervals. Walkaround VSP data recorded across the shallow lost circulation zone showed strong anisotropy that coincides precisely with the lost circulation zone indicating high fracture density, with the fast velocity azimuth being consistent with the regional stress field.
It was the first time that high resolution VSP images (vertically and spatially) were generated for this field. High resolution walkaway VSP images were utilized to enhance the existing horizon and fault interpretation and reservoir characterization. The Walkaround VSP also helped to understand the azimuthal anisotropy and presence of natural fractures near the well in the main producing reservoir.
Prevention of Barite Sagging for Invert Emulsion Drilling Fluid While Drilling High-Pressure High-Temperature Wells
Authors: Basfar Salem , Elkatatny Salaheldin , Al-Majed Abdulaziz , Al Sheri Dhafer 
Published: January 2020

High-pressure high-temperature (HPHT) reservoirs required special drilling fluid with high density and steady rheology to sustain the challenging conditions. Barite is one of the most weighting agents to increase the mud density at a low cost. But drilling HPHT wells causes settle the barite particle down in the wellbore known as barite sagging. Barite sagging may lead to several issues, for instance, stuck pipe, density variation, loss of circulation and well control problems.
To prevent the barite sagging, a new copolymer was used in this study. Static sag experiments were conducted to evaluate the mud in drilling break for both cases vertical and 45° inclined wells, dynamic sag tests also were performed to simulate the sagging while drilling. Static and dynamic sag tests were conducted to evaluate the ability of copolymer to suspend the weighting materials in the invert emulsion drilling fluids (IEF). Then the effect of adding copolymer in rheology, electrical stability, and HPHT filtration was achieved.
The objective of this study is to assess the effect of adding the new copolymer to IEF (polymer based on styrene and acrylic monomers) on the suspension efficiency of the weighting agent and rheological stability in HPHT condition
The results obtained showed that 1 lb/bbl of the new copolymer didn't affect the electrical stability of the invert emulsion mud. The sag issue was prevented after adding 1 lb/bbl of the copolymer for both vertical and inclined situation and in the dynamic case at a temperature greater than 300 °F. For the rheology test, the copolymer enhanced the plastic viscosity, yield point and gel strength of the mud to increase the mud stability during drilling HPHT wells. Adding 1 lb/bbl of copolymer had no effect on HPHT filtration loss and filter cake thickness.
The novelty of this study is to provide the oil and gas industry with newly designed mud to solve the barite sagging for the invert emulsion drilling fluid at high density to sustain the HPHT.
Integrated Asset Model as Decision-Making Tool to Design Surface Network and Optimal Artificial Lift System
Authors: Maiorano Stefano , Viganò Marco Cesare , Selvaggio Pietro , Rossi Roberto , Distaso Ripalta Eleonora , Stano Elena 
Published: January 2020

This work describes an innovative application of Integrated Asset Model (IAM) implemented for Mexico Area-1, aiming to simulate the whole asset development. The context of application is strongly complex, since the asset is composed of five reservoirs, connected to the same Floating Production Storage and Offloading unit (FPSO). The reservoirs are separated and different in terms of structure, initial pressure regimes and characteristics of oil.
A cross-platform model of the whole Area-1, has been developed in order to implement simulation constraints from asset to well level in a unique tool.
Moreover, an innovative process was defined to increase the accuracy of the IAM, improving the control of the wells equipped with electrical submersible pumps (ESP), through the honouring of the ESP working conditions. Reservoir models include actually dedicated instructions to monitor and handle wells production according to gas-liquid ratio (GLR) at the ESP intake. This allows to operate the pumps as per design, obtaining more reliable simulation results.
The IAM, combined and enhanced with the new process, enables to run several sensitivities comparing different technologies for network configurations and artificial lift systems in order to select the finest solution to maximize the production. The enhanced model, improved in reliability, permits, in fact, to dispose of a unique tool suitable for different purposes: multi-phase pump (MPP) deployment assessment, ESP design support, water injection handling and facilities sizing.
In conclusion, the enhanced IAM merges all the constraints in a single apparatus allowing the monitoring of the asset from the reservoir to the network scale, by means of the generation of reliable fluid production profiles.
Shrouded Y-Tool Application for Optimum ESP System Run Life
Authors: AlRashidi AlAnoud , AlAnsari Aminah , Radcliffe Alan 
Published: January 2020

It is critical to manage the temperature rise seen in the electrical power system and submersible motor, in order to have an optimum Electrical Submersible Pump (ESP) run life. This paper presents a case study in which a solution was applied to better manage the heat rise seen in the ESP during operations, particularly in low flow applications, that has led to a measurable increase in ESP run life across the field.
A Middle Eastern Operator of ESPs had installed wells completed with Y-tools and ESPs that showed unusually high motor temperatures and shorter than expected system run lives. A study was conducted, and the remedial action implemented was to install a shroud around the Y-tool, reducing the flow space in the annulus thus increasing the velocity of fluid past the motor. The study compared the data gathered from the shrouded and non- shrouded Y-tool ESP installations to determine the effectiveness of the corrective actions.
Motor temperature is a function of bottom hole temperature, percentage load against nameplate, fluid properties, power quality and fluid velocity past the ESP motor. This study has shown that the shrouded ESP significantly increased the fluid bypass velocity (more than 1ft/sec) alongside the submersible motor to deliver the required cooling for stable, reliable operation. Unshrouded systems experienced higher motor and intake temperatures that is instrumental in the deterioration in the insulative properties of the electrical system and leads to greater current leakage with the passage of time.
This paper will provide full, detailed knowledge on shrouded Y-Tool systems that can be effectively applied for low flow rate production, allowing well bore full access for wireline or coil tubing jobs. Moreover, efficient motor cooling is provided by the higher fluid velocity and while providing a better pump performance, is expected to result positively in ESP run life.
Continuous Circulation Drilling, MPD: Adding Value Through Safety Enhancements and Cost Control.
Authors: Colaianni Francesco 
Published: January 2020

In an industry climate with a high focus on reduced well costs and drilling time, the use of continuous circulation system (CCS) as a simple MPD solution offers many benefits, including the control of bottom hole pressure along with enhanced wellbore cleaning and stability. These features become crucial requirements for personnel safety, operational efficiency and cost reduction, particularly in drilling environments with very narrow margins and more extreme deep-water, high-pressure/high-temperature situations, high deviated and extended reach horizontal sections.
Continuous circulation drilling naturally provides a downhole steady-state condition and, as a result, the formations do not suffer from pressure oscillations while hole-cleaning and borehole stability improve, reducing the chance of drilling issues related to bottom hole pressure management in open hole. The CCS can be applied as a stand-alone device or in combination with a closed-loop MPD System, making connections with MPD simpler and faster.
Technology of Multi-Stage Hydraulic Fracturing Dual Laterals in One Trip for Multilateral Wells
Authors: Zhang lina , Chen Shichun , Zhang Heng , Zhang Songjie , Yang Wenling , Hu Jintong , Yu Xueliang , Cui Yuanzhong 
Published: January 2020

With its advantages of a shorter construction period, a less cost and a higher production, multilateral drillingtechnology has become widespreadthroughout the petroleum industry. Multi-stage hydraulic fracturing technology is also widely used in the field to deal with poor reservoir conditions such as layers with low pressure and permeability. However, conventional hydraulic fracturing technology used in multilateral well encounters difficulties. Not only has itcalled for a complicated operation of accurate re-entry, but also significantly extends the completion time while having to controlthe well, thus greatly increasing the risk of making a dead well and limiting the development of the technology.
In order to deal with those difficulties, the authors of this study researched this new technology which can achieve the goal of self-orientating control, accurate re-entry control and fracturing multilaterals without having to controlthe well. The first aim is to achieve the goal of a single trip self-orientating control system during drilling different multilaterals, thus means drilling tools will enter the lateral we choose only by the self-orientating control system while without any other tools or instruments in this process. To get this, a self-orientating system is studied which provides a base for subsequent operations and it is kept at the bottom of the hole perpetually. In other words, the self-orientating control system functions as the root of the whole system. The other aim is to achieve the goal of selective re-entry. During the processes of washing and fracturing, the BHA must re-entry the lateral designed, thus a special tool is needed to work as a guide to lead the BHA into the right hole. The special tool we designed is called junction. It works as a bridge between the bottom lateral hole and the running BHA. The re-entry system will enter the hole selectively based on the mechanical parts onthe junction. The last but the most important is to fracture the multilaterals together without having to controlthe well. Compared with conventional operation, fracturing/killing/bridging operationsare not needed for the lower lateral before starting to drill the upper lateral, thus not only one trip has been decreased, but also no risk to lead to a dead hole.
A Fieldtest has been performed on an abandoned well, showing the success of the technology. Special tools and operation procedures were involved. The two laterals were fractured only in one trip which demonstrates its superior performance compared to conventional multi-stage hydraulic fracturing that requires two or more trips for multilateral wells.
Air/Foam Drilling Coupled with Drilling with Casing Technique Enables Operator to Drill and Isolate Troublesome Section to Target Depth on Multiple Wells in Pakistan
Authors: Khalid Ali , Ashraf Qasim , Luqman Khurram , Hadj-Moussa Ayub , Khurshid Imran 
Published: January 2020

The Kirthar fold belt located in southern Pakistan, contains some of the largest gas reserves of the country. Operators when attempting to drill in the locality face a major hurdle in the surface hole sections. The surface section on most wells contain a group of three formations, Kirthar Limestone, Ghazij Shale, and Laki Limestone. Both the Limestone formations are highly fractured and exhibit total circulation losses, while the Shale formation is highly reactive and exhibits a swelling and sloughing behavior when drilled with a conventional water-based mud system. The operator on many occasions suffered stuck pipe incidents up to 3 times per well due to the massive circulation losses and shale instability problems.
An air/foam system was initially used to eliminate the major problem of total lost circulation. The foam base fluid was formulated to contain a special blend of shale inhibitors to address the reactive nature of the shale formation. A special combination of polymers was also added to the base fluid to stabilize the foam in the presence of these shale inhibitors. The designed air/foam system was able to eliminate lost circulation completely and minimize the swelling and sloughing of the shale formation in a few wells drilled. While running the surface casing the operator observed high compression against the shale formation and in most instances the casing was set prematurely leaving a part of the vulnerable limestone formation exposed in the next section. As the next section required a much higher mud weight to drill, numerous cement plugs had to be peformed to bridge off the exposed limestone formation.
The operator then further desired a solution that would enable them to drill without losses and allow them to land the surface casing to target depth. A drilling with casing system was first considered for this objective, but it was found to be incompatible with the air/foam system. The operator then finally decided to drill the section with an air/foam system and run the casing with a drilling with casing system, reaming through the troublesome shale formation.
A series of wells were then drilled with an air/foam system, and the casing was run with a special drillshoe laced with pdc cutters. As expected high compression was observed against the shale formation. The casing was then connected to the top drive utilizing a specifically designed tool and reamed joint by joint to bottom. A conventional mud system was used while reaming the casing to bottom. The operator by the application of these two unique methods was able to drill and isolate the section in all future wells to target depth and achieve a cost and time saving of as much as 50 percent.
Customized Integrated Approach for Increasing Reservoir Understanding and Lowering Costs: Case Study, Deepwater Gulf of Mexico
Authors: Michel Franck , Rennie Allan , Guidry Garrett C. , Robbins Ben , Iqbal Shaikh Aamir , Kizziar Steven 
Published: January 2020

In the deepwater Gulf of Mexico (GOM), an operating company planned to drill and log a challenging wellbore in a mature field within the Upper Tertiary set of target sands. High levels of depletion as well as extremely tight pore pressure margins were anticipated. The operator and the service company's drilling and evaluation (D&E) integrated teams developed a highly collaborative environment from the early planning stage of the project, aligning people and processes and enabling applications.
Regional knowledge from an archived geomechanical model was updated during collaborative planning sessions, enabling both parties to have a consistent understanding of the subsurface challenges to correctly drill and log each interval. Potential wellbore instability issues were mitigated using a proactive geomechanics analysis and hydraulics management from an integrated real-time operations center (iROC).
Formation compressional slowness from a logging-while-drilling (LWD) sonic system was used, updating the geomechanical model for accurate real-time pore pressure and wellbore stability analysis. Additionally, the sonic system was used for top-of-cement (TOC) evaluation behind the intermediate casing to satisfy the Bureau of Safety and Environmental Enforcement (BSEE) requirements to differentiate fully bonded pipe from free pipe. Geosteering services from real-time log response correlations and at-bit geological predictions were used to correctly geostop for an intermediate casing point before pressure regression. An LWD formation pressure system provided pressure tests over various depth intervals, providing excellent fluid gradient determination for the primary target sand package. An LWD azimuthal density system delivered high-quality borehole images within the 16 ½-in. borehole section, providing dip information for geological correlation to seismic. Further, the azimuthal density image system resolved the interbedded shale/sand sequences, allowing dip analysis for geological model correlation within the reservoir.
Challenges for this wellbore included shallow water hazards, wellbore instability, setting intermediate casing above the sand targets, and the depleted reservoir section. The deployment of specific technologies with associated unique applications discussed in detail within this paper led to superior well construction execution under time (8 days) and under budget (USD 4 million).