bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unconventional Techniques Overcome Narrow-Margin Cementing: Case Studies from Malikai Deepwater Project, Malaysia
Authors: Hoe Yijing , Duong Anh , Heu Tieng Soon , Md Radzi Mohd Razif 
Published: October 2018

Abstract
As Malaysia’s first tension leg platform, the Shell Malikai project, represents an unconventional approach towards deepwater operation in this region. In a field embedded characterized by reservoir drawdown from adjacent production wells, the lowest cementing margin is 0.65 ppg. Annular gaps between casings of as tight as 0.53 in each side further elevates the equivalent circulating density (ECD). Cementing software simulation predicts risk of heavy losses during cement placement and subsequently lack of isolation between multiple hydrocarbon-bearing zones. The loss of zonal isolation would mean crossflow between the reservoir. At worst case, some of the water injector wells may be abandoned due to inability to inject into the target reservoir and uncertainties of injection efficiency. This represents a significant loss of capital investment. A two-pronged solution has been developed to secure the long-term well integrity of the deepwater project. Implementation involved front-end design, modelling, planning, and execution.
Two-stage cementing is a technique by which selected intervals along the casing can be cemented in separate stages. It reduces the risk of losses due to long column of cement slurry exerting high hydrostatic head towards the weak formation. In 11 3/4in liner with tight annular gap, the risk of taking losses is high. Therefore, two-stage cementing was employed, combined with specialized blended lightweight 11.5-ppg cement. First-stage cement will provide good liner shoe strength for drilling ahead, and second-stage cement will provide zonal isolation for two hydrocarbon zones near the top of the liner. For 9 5/8in liner, due to the presence of a pressure ramp at the top of the section and weak formation at the bottom, managed pressure cementing (MPC) was the chosen approach to mitigate the risk of losses. MPC is a technique that enables cementation to be conducted in a hydrostatically underbalanced condition where surface backpressure (SBP) is applied to maintain the bottomhole pressure between the highest pore pressure and the lowest fracture pressure of the well.
The combination of MPC and two-stage cementing, together with other existing best practices, formed an integrated solution in narrow margin cementing. This has resulted in flawless cementation for two water injector wells. No losses were observed during cement displacement, there was no gas migration, and the liner top packer was successfully set, and pressure tested in MPC mode. A subsequent cement log confirmed the top of cement requirement was fulfilled. The paper will further explain on how this unconventional technique were planned and executed.
Initiatives in Cooperating with Local Government and Communities Promote the Development of a HTHP Gas Field in Remote Area of China: Development of Keshen Gas Field
Authors: Jiang Tongwen , Liu Huifeng , Yang Xiangtong , Liu Yuan , Feng Jueyong , Ren Huining , Guo Hu 
Published: October 2018

Abstract
Keshen gas field is located in the southern foothill of Mount Tianshan, Western China. Administratively it belongs to Baicheng County, a poor and remote county. This county is composed of 20 ethnic groups, who have their own cultures and languages, which pose difficulties for project management. With a series of initiatives for cooperating with the local government and communities, a yearly natural gas productivity of 5 billion cubic meters were established within five years.
A series of measures were taken to win the support of local government. A 108-kilometer long highway was constructed in the mountainous area and shared with local communities. A pipeline network was established to transmit natural gas from Keshen gas field to the suburban areas of Baicheng and other remote places, which changed the local main fuel from firewood into clean natural gas. We hired local people, trained them and gave them decent salaries. More than 2,000 job opportunities were provided to local ethnic minorities, which accounts for 18.5% of the total workers in this project.
Thanks to the initiatives we have taken, a harmonious development mode was established in Keshen gas field. It was put into production within five year's construction. The average productivity of a single well is more than 500 thousand cubic meters. The total amount of taxes as well as the GDP of Baicheng County was twice as before. The southern Xinjiang pipeline network encircles half of the Tarim Basin. 41 towns along the pipeline and 4 million people are benefiting from the natural gas produced from Keshen gas field. In return, the local government and communities provided a lot of conveniences for the project crew. The government released several restrictions on seismic exploration and pipeline construction. Since the project crews were mostly from urban areas, the local residents also help us to recognize risks and formulate risk-reducing practices for conducting engineering work in the Gobi and desert area. We also instructed the local residents to do business with Keshen development project, including selling of construction and living materials, renting of equipment, transport vehicles, etc. This initiative also helped to reduce unemployment rate and benefit the project management as well.
Keshen gas field is one of the most complicated reservoir in China, not only because of the ultra-deep HPHT reservoirs, but also because of the complicated social environment. A win-win cooperation mode between the Oilfield Company and local communities has been established after a series of initiatives. This set a solid foundation for the sustainable development of Keshen gas field and also set an example for the development of reservoirs in remote areas.
Embracing Opportunities and Avoiding Pitfalls of Probabilistic Modelling in Field Development Planning
Authors: Hajizadeh Mobaraki Alireza , Deo Tewari Raj , A Karim Rahimah 
Published: October 2018

Abstract
Uncertainty and risk analysis is an inseparable part of any decision making process in the field development planning. This study sheds light on the available approaches to capture the range of uncertainties but digs deep into the misuses of the probabilistic approach that renders the method difficult and time consuming to implement with little added value for risk mitigation and proper decision making.
Probabilistic modeling using dynamic simulation models has been adopted in recent decades to address the variations in forecasted production profiles and to capture the uncertainties. However, there are misuses in the approach that pose questions on the outcome and its meaningfulness. Lack of enough spread in the forecast, history-matched models with physically incorrect parameter ranges/ combinations and models suggesting contradicting development scenarios are among examples. These in turn make the probabilistic forecasting output inconclusive and considering the high computational cost and time required to perform the exercise makes it unattractive to management. In this paper four case studies including mature and green fields have been described and a number of main issues and pitfalls of using probabilistic dynamic modeling in those cases are analyzed. General workflows are then presented for green and brown fields based on experimental design, proxy modeling, optimization and prediction candidates selection that provides solution for proper selection and implementation of the probabilistic dynamic modeling.
It is argued that probabilistic modeling can help better capture the uncertainties and reduce the risk in field development planning provided that a fit-for-purpose approach is taken with correct understanding of the data requirement according to the reservoir complexity, the physical processes being modeled and assumptions used in the methodologies and simulation engines. This is in contrast to the attempts to capture the ranges of recoverables based on deterministic high and low cases that is often inefficient as the optimistic high-case of ‘hole-in-one’, may suggest an ideal but not plausible scenario whereas the pessimistic low-case of ‘train-wreck’ may be economically unattractive. The exercise then leaves the companies with the best technical estimate model to make the final call and the numbers from other models are only used for reserve booking purposes.
The published papers in the literature include discussions on deterministic vs. probabilistic approaches and selection of base case models, the detailed algorithms and also case studies done using the published methods available in the commercial softwares. This paper however discusses the misuses of the probabilistic dynamic modelling approach and tries to inform the audience of the pitfalls of not understanding the reservoir and/or the tools used in implementing the methods and in this sense it is novel.
Early-Stage Detection of Scales in a Deepwater Field Offshore Ghana via Remote Monitoring of Multiphase Meter
Authors: Darab Mahdi , Nygaard Rune , Singh Arvinder Paul 
Published: October 2018

Abstract
Multiphase metering has enabled addressing a number of flow assurance challenges, including the detection of scale formation. This capability is especially appreciated in subsea fields, where the physical access is restricted and flow assurance challenges can be detrimental to maintaining production with a reasonable cost. The scale detection capability of the multiphase flowmeters using live multiphase flow data facilitates a proactive approach by the operators to detect and remediate productivity and flow assurance issues arising out of scale deposition.
A successful early-stage detection of scales in an oil well in deepwater field offshore Ghana via remote monitoring of multiphase metering data is reported. The displacement of the operating point of the multiphase meter and the swift developments in a matter of days provided the necessary live data for the hypothesis of the scale formation in the meter's venturi. Necessary mitigation action was taken and increases in production due to removal of scale demonstrated presence of scale. An in-house-developed remote surveillance and diagnostic system carried out this detection. The results of this project demonstrate the practical capability of remote monitoring of multiphase metering data for flow assurance purposes.
Statistical Analysis of Effect of Sensor Degradation and Heat Transfer Modeling on Multiphase Flowrate Estimates from a Virtual Flow Meter
Authors: Bikmukhametov Timur , Stanko Milan , Jäschke Johannes 
Published: October 2018

Abstract
Accurate flowrate measurements in petroleum production systems are important for optimization, fiscal metering, and production allocation. Sometimes, Virtual Flow Meters (VFMs) are used for this purpose instead of physical meters to reduce cost. These systems estimate the flowrates using a computational model that represents accurately the production system of interest. Since VFM systems mostly rely on pressure and temperature measurements, it is important to understand how accuracy and degradation of sensors influence the VFM flowrate estimates.
In this work, a VFM system for a subsea oil well was created using a transient multiphase model built in a commercial software and controlled from an external computational routine. A statistical analysis of VFM simulation results was performed to quantify the effect of pressure sensors degradation on the VFM flowrate estimates. In addition, the effect of temperature matching and a segmented approach to represent the well heat transfer were evaluated.
The analysis showed that the sensor degradation effect should be considered in VFM systems carefully, especially if a high estimation accuracy is required. Measurement drift was found to be the most critical factor of the sensor degradation but high measurement noise can also cause considerable errors of the flowrate estimates. In addition, it was found that a complex representation of the wellbore heat transfer is not required to obtain accurate flowrate predictions and simplified models can be used instead.
Design, Fabrication and Field Trial Testing of a Novel Rotating Continuous Circulation Tool RCCT
Authors: Badran Mohammed , Gooneratne Chinthaka , Saqqa AbdulKarim 
Published: October 2018

Abstract
In this paper, we present an innovative Rotating Continuous Circulation Tool (RCCT) that allows both limited rotation of a drillstring assembly and uninterrupted circulation of drilling fluid during making up of, or breaking out, a drill pipe, to/from the drillstring assembly. Continuous/nearly continuous drilling has many advantages such as reducing the risk of stuck pipe and wellbore collapse as well as the efficient removal of cuttings resulting in improved borehole cleaning. The RCCT is a sub with a central bore and upper and lower ends that connect to the drillstring assembly. The upper and the lower part of the RCCT are able to rotate independently and in unison through a clutch/sleeve system. A central bore valve that is coupled to the upper part of the RCCT is able to selectively open and close the central bore. There is also a side entry port in the sidewall of the upper part that is controlled by the central bore valve to selectively allow drilling fluid to be injected into the central bore. A preliminary field trial to validate the RCCT was safely and successfully performed in a hydrocarbon well during a cement cleanout operation. The four RCCT subs were successfully tested for rotation with the rotary table and for drilling dynamics while cleaning out cement. Recommendations for improvements from this trial test are planned to be implemented in future field tests.
Agile Field Development Planning: A Systems Approach
Authors: Ciccarelli John , McLachlan Duncan , Singh Himadri , Thomson Rob 
Published: October 2018

Abstract
It can take months, perhaps a year or two, to get through Front End Loading (FEL) stages with the current industry approaches. As the industry strives to be more efficient, faster to market in this lower for longer world, we need a different and much faster, lower risk approach that does not erode value. Multiple tools exist that allow subsurface/surface simulation integration and coupling, but these are cumbersome to configure and not appropriate for an early field development at the stage of pre-FEED (Front End Engineering and Design).
To meet this challenge, an agile approach to Field Development Planning (FDP) has been established. The approach is inspired by agile project management techniques and best practices that are currently used in the automotive, aerospace, construction, software development industries and lean start-ups. It is based on parallel sprints rather than the waterfall approaches to project management. Collaborative teams work on parallel deliverables to create a minimum viable product (MVP) and value drivers for further development are established quantifiably with an Analytic Hierarchy Process (AHP). The notion of a fully representative dynamic techno-economic model is presented. This model applies a multi-dependent system thinking approach, with dynamic integration of economic, reservoir, subsea, facilities and schedule data.
Two case studies are discussed where this approach was used to maximise economic benefits of the asset and accelerate the decision-making process during FEL stages: Identification of the best compression solution to optimise the economic outcome of production from a complex group of 350 wells intersecting different reservoirs. The result of this example was an 18-month acceleration of the decision process and 30% cost saving.Deciding whether the FEED should be oriented towards simultaneous or sequential production for the development of two marginal offshore satellite fields.
This presentation will be of interest to anyone looking to speed up the time to first oil/gas and reduce production costs on undeveloped or underdeveloped fields and bid more confidently on assets during licence rounds with less risk. It will also be of interest to those wanting to accelerate their decision-making process during FEL stages from months or years to weeks and allow decision makers to visualise and test inter-dependencies creatively with less cognitive bias.
Displacement Efficiency for Primary Cementing of Washout Sections in Highly Deviated Wells
Authors: Renteria Alondra , Maleki Amir , Frigaard Ian , Lund Bjornar , Taghipour Ali , Ytrehus Jan David 
Published: October 2018

Abstract
Anywhere between 0%-80% of cemented wells have integrity failures, suggesting both geological and operational factors. One way geology affects cementing is via irregular wellbores, e.g. washouts. Here we study the effects of washouts on mud removal in strongly inclined wellbores, experimentally and via 2-D computational simulations, with aim of identifying key control parameters.
Experiments were performed with 2 fluids with properties representative of drilling mud and cement (or spacer), displaced at constant flow rate through a 10 m long annular flow loop. A downstream "washout" section of the annulus had an enlarged outer diameter. Twenty-four conductivity probes tracked the arrival times of the displacing fluid by measuring the conductivity of fluids as they pass. The experimental matrix includes 8 experiments with 2 eccentricities (standoff = 1, 0.58), 4 angles of inclination and slightly variable rheology. The simulation study covered wider ranges of variables. The results of simulations and experiments agree qualitatively on the main effects, as shown in [7].
Here we extend the study using the 2D simulation to study the effects of washout length and diameter, for both concentric and eccentric wells, all oriented horizontally. The simulations provide detailed information on the evolution of the fluid-fluid interfaces as they pass through the washout, as well as information on the velocity fields and stresses. In any near-horizontal section there is a delicate balance of buoyancy and eccentricity influences, in both regular and irregular geometries. Under some circumstances an irregular section seems to have a positive stabilizing effect on the interface. However, this positive message is balanced practically by uncertainty of washout size and in-situ mud properties and the positive effects are not universal. We find that increasing the washout diameter always appears to decrease the displacemnt efficiency, for both concentric and eccentric annuli. Increasing the washout length is less clear in its effects. In all cases, the main risk from residual drilling mud in isolated washouts is that it can contaminate the cement slurry as it passes.
A General Purpose Model for Multiphase Compositional Flow Simulation
Authors: Wu Shuhong , Dong Jiangyan , Wang Baohua , Fan Tianyi , Li Hua 
Published: October 2018

Abstract
Reservoir simulation has come a long way since its birth in the 1950s and now is an important tool for reservoir engineers to predict oil and gas production and optimize reservoir management. In the past, many existing models were developed to simulate fluids with a specific fluid characterization such as black oil, compositional and thermal models. Today, the need for optimizing reservoir life with different recovery techniques and different fluid characterizations is urgent to fully evaluate oil and gas fields assets.
In this paper, a flexible general purpose model has been developed for multiphase isothermal or thermal compositional flow simulation in porous media, including formulations, phase behavior calculation, various numerical techniques. Based on general mass balance equations and energy balance equations, a mass variable set has been chosen for the generality for all types of fluids (black-oil, compositional and thermal) to ensure that each grid block has the same amount of primary unknowns and it is convenient for Jacobian matrix construction. The model decouples fluid and formulation from the rest of simulator and makes is possible to model different reservoir physics in one single simulator.
The model have tested and validated on various standard comparative benchmark problems like black-oil model, compositional model as well as large complex field cases with over one million grid blocks and an actual reservoir simulation. The test results show that the simulator is comparable with current commercial simulators in accuracy and speed. When different recovery techniques are used in a reservoir life cycle, the model is more efficient and accurate without the need of switching simulators. The generic and modular design architecture provides convenience for extensions of modeling additional flow processes and implementing new numerical solution methods. Developing a general purpose reservoir simulator is the main focus in state-of-the-art reservoir simulation research. The proposed general purpose model for multiphase compositional flow simulation in this paper is one step closer to the goal.
Rigless Intervention to Secure Internal Blowout IBO Monitoring Gas Wells Offshore of Brunei
Authors: Leong Azemi , Azizan Yusri , Yong Yee Tzen , Song Yan , Abd Rani Rudzaifi Adizamri , Jasni Mohd Majdi 
Published: October 2018

Abstract
Mature fields often include wells or platforms that require a plug and abandonment (P&A) job and decommissioning. Two high-pressure gas wells were identified in a field offshore Brunei that required a coiled tubing unit (CTU) intervention to secure them. The job was further complicated by high reservoir pressure in a tight formation, a small platform area, and no existing surface facility.
Because the flowline and pipeline equipment on the platform are not in service, a method was needed to take large volumes of returns. To overcome this challenge, an integrated operation was designed and planned that uses a complete catenary CTU and a pumping and flowback package with a mobile storage support vessel. The returns system will enable liquid (brine and spacer) and gas returns with pressures of up to 5,000 psi. The mobile storage support vessel enables the returns to be stored before disposal at an onshore facility.
Before killing the wells and pumping cement across the perforation, multiple tubing plugs must be removed. High tubing pressure indicated some communication to the reservoir; consequently, the plug removal strategy with coiled tubing (CT) must include risk mitigation to ensure that the plugs can be removed safely.
After all plugs were removed, the wells were successfully killed by using a 17 kPa/m (14.45 ppg) calcium chloride/calcium bromide (CaCl2/CaBr2) blend brine. The next operation was to spot cement across the perforation to a depth that is below where the tubing will be cut during the P&A process. The spacers and cement design must be tailored to avoid compatibility issues with the CaCl2/CaBr2 and the presence of carbon dioxide (CO2). The cement placement with CT is critical to prevent flash reaction with the kill fluid and to minimize the volume of contaminated cement. The cement was placed successfully and tested in accordance with the Brunei Shell Petroleum requirement.
The wells were safely secured and ready for the planned P&A process. These operations marked the first successful operation on high-pressure, tight gas wells with no surface facilities on the platform within a sensitive environment. The use of a mobile storage support vessel enabled the wells to be killed successfully. This approach demonstrates that a similar method and similar planning can be used to safely and economically perform future interventions.