bluuebunny/crossref_metadata_2025_split huggingface dataset:
Smart Horizontal Wells for Development of Thin-Oil-Rim Reservoirs
Authors: Carpenter Chris 
Published: October 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17753, “Smart-Horizontal-Well Drilling and Completion for Effective Development of Thin-Oil-Rim Reservoirs in Malaysia,” by Keng Seng Chan, Rahim Masoudi, Hooman Karkooti, Ridzuan Shaedin, and Mohamad B. Othman, Petronas, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed.
For thin-oil-rim reservoirs, well placement, well type, well path, and the completion methods must be evaluated with close integration of key reservoir and production-engineering considerations. This involves maximizing reservoir-fluid contact and drainage, optimizing well productivity, and optimizing the well life-cycle production profile along the wellbore. Field-implementation cases in Malaysia have shown that this integrated approach can significantly minimize the well count, enhance the well performance, and improve the ultimate recovery per well in thin-oil-rim reservoirs with varying reservoir complexity and uncertainties.
Introduction
Development of oil-rim reservoirs in Malaysia has been improved progressively in recent years through a series of reservoir-engineering studies and successful field implementations. Although typical oil-rim reservoirs are characteristically wedged between a gas cap and an underlying aquifer, they can be structurally very complicated, with faults and flow boundaries having varying dips and saddles. Oil-rim reservoirs of various sand thickness can also be stacked and compartmentalized. Aquifer support varies from sector to sector, resulting in uneven pressure depletion and fluid-contact change.
Wells are completed with multiple strings to produce separately from various different stacked sands with significantly large pressure difference. Well life can be short producing at high watercut and high gas/oil ratio (GOR) because of wells having partial penetration operated at high pressure drawdown. For such a well-development strategy, idle-well rate increases dramatically. Currently, active wells in some key oil-rim reservoirs number far less than 50%. Field oil recovery remains low even after 25 years of continuous production.
Force Balance in Thin-Oil-Rim Reservoirs
There are several drive mechanisms dominant in oil-rim reservoirs—namely, gas-cap and aquifer expansion, viscous and gravity balance, and solution-gas-expansion drive. Produced-gas reinjection; controlled pressure drawdown at wells in different reservoir sectors on the basis of varying aquifer strength and sand-layer dip angle; and the placement, spacing, and completion of the wells could all affect the balance of these drives. The art of this balance is to keep the oil rim in place, avoiding dramatic migration of the oil rim by having a good vertical displacement conformance.
Crown-Plug Pulling Performed as Riserless Light Well Intervention in the Gulf of Mexico
Authors: Carpenter Chris 
Published: October 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173647, ’Crown-Plug Pulling Performed as Riserless Light Well Intervention in the Gulf of Mexico - Overcoming the Challenges,’ by Garry Andrews and Angel Luviano, Welltec, prepared for the 2015 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 24-25 March. The paper has not been peer reviewed.
In a riserless-light-well-intervention (RLWI) operation in the Gulf of Mexico (GOM), a crown plug failed to release. Slickline (SL) was the first method to be put into action. It was believed that repetitive attempts had broken the seal, resulting in saltwater inflow that had created hydrates. Twenty-five percent methanol/ethanol/ glycol was pumped while jarring, but eventually the contingency plan was activated. This consisted of a hydraulic stroking tool, which managed to remove the upper crown plug successfully and allowed the operation to continue.
Introduction
Electric line (e-line) has become the preferred method of intervention in the industry for a number of tasks with a growing array of lightweight solutions available to operators as an alternative to the heavy-duty approach of coiled tubing (CT) or the limited approach of SL. With the growing number of subsea wells and the greater efficiency of RLWI, logic dictates that the industry will see more and more e-line interventions for subsea wells in place of heavier interventions.
The Hydraulic Stroking Tool
The hydraulic stroking tool used during the operation presented here provides the necessary force for most mechanical-intervention jobs. It can push or pull a number of times, in spite of well depth or lateral deviation, during the same run. The particular tool used for this operation was designed to pull with a force of 33,000 lbf. Since this operation was completed, this hydraulic stroking tool has been redesigned to apply up to 60,000 lbf of axial force downhole with its bidirectional hydraulic ram. When plugs or stuck tools need to be pulled, specific tools and adapters can be attached to the actuator piston. All mechanical operations are run from the surface, and operations begin after the stroking tool has anchored itself.
The design of this particular hydraulic stroking tool presents operators with a number of advantages, including the ability to perform mechanical interventions without “killing” the well. Additionally, the tool contains fail-safe measures that allow the system to default to a safety mode if any operational problem occurs. The hydraulic stroking tool can be used for a number of services, including opening and closing valves and sliding sleeves, retrieving and setting gas lift valves and plugs, setting straddle packers, and fishing operations. The tool is deployed stand-alone in vertical wells or conveyed by tractor and can provide services to both horizontal and extended-reach wells onshore and subsea.
Experimental Laboratory Setup for Visualization and Quantification of Cement-Sheath Integrity
Authors: De Andrade J.. , Sangesland S.. , Skorpa R.. , Todorovic J.. , Vrålstad T.. 
Published: October 2016

Summary
The annular cement sheath is one of the most-important well-barrier elements, both during production and after well abandonment. It is, however, well-known that repeated pressure and temperature variations in the wellbore during production and injection can have a detrimental effect on the integrity of the cement sheath.
A unique laboratory setup with downscaled samples of rock, cement, and pipe has been designed to study cement-sheath-failure mechanisms during thermal cycling, such as debonding and crack formation. With this setup, it is possible to set the cement under pressure and subsequently expose the cement to temperature cycling under pressure as well. Cement integrity before and after thermal cycling is visualized in three-dimensional by X-ray computed tomography (CT), which enables quantification of and differentiation between debonding toward the casing, debonding toward the formation, and cracks formed inside the cement sheath itself.
This paper describes in detail the development and functionality of this laboratory setup along with the experimental procedure. Several examples to demonstrate the applicability of the setup, such as tests with different types of casing surfaces and different rocks, are also shown.
Reduction of Residual Oil Saturation in Sandstone Cores by Use of Viscoelastic Polymers
Authors: Qi Pengpeng , Ehrenfried Daniel H. , Koh Heesong , Balhoff Matthew T. 
Published: October 2016

Summary
Water-based polymers are often used to improve oil recovery by increasing sweep efficiency. However, recent laboratory and field work have suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation (ROS). The objective of this work is to investigate the effect of viscoelastic polymers on ROS in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120 cp) and then waterflooded to ROS with brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM).
Significant reduction in residual oil was observed for all corefloods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number, NDe). An average residual-oil reduction of 5% original oil in place (OOIP) was found during HPAM polymer floods for NDe of 0.6 to 25. HPAM floods with very-low elasticity (NDe &lt; 0.6) did not result in observable reduction in ROS; however, another 10% OOIP residual oil was reduced when the flow rate was increased (NDe &gt; 25). All experiments at constant pressure drop indicate that polymer viscoelasticity reduces the ROS. Results from computed-tomography (CT) scans further support these observations. A correlation between Deborah number and ROS is also presented.
Innovative Logging Technique Enables Accurate Detection of Temperature Anomaly Source in a Special Completion
Authors: Al-Hajri Nasser M. , Al-Ageel Ibraheem M. , Al-Subaie Fehead M. , Nekhily Mohammed M. , Mishkes Abdulrahman T. , Al-Ajmi Mohammed D. 
Published: October 2016

Abstract
This paper will outline the events associated with Well-A integrity diagnostics, which took place prior to and during workover operations. Well-A tubing was pulled out and inspected by the workover rig. The results of workover operations assessment have distinctively validated previous rigless diagnostics. A detailed recap of Well-A sequence of events will be made in this paper.
Well-A is a standalone injector. It has been especially completed to utilize the same well to supply and inject water simultaneously. Well-A has a 4 1/2" tubing completed on a 9 5/8" casing. The water producing formation is shallow and was perforated in the 9 5/8’’ casing. The produced water flows naturally to the surface through the tubing casing annulus. A surface pump injects the produced water into a deep formation through the 4 ½’’ tubing, as a reservoir pressure maintenance mean to support oil production. This unique downhole completion entails a set of challenges related to continuous well integrity monitoring and future corrective actions.
A routine wireline temperature survey at shut-in conditions detected a downhole temperature anomaly. A heating effect was noticed compared to previous temperature surveys, which indicates upward crossflow from the injecting formation to the producing formation. The temperature profile started deviating from the normal geothermal gradient around the 4 1/2" by 9 5/8" packer depth.
Two suspected sources of temperature anomaly were identified: a failure in the 4 1/2" by 9 5/8" packer and/or a leak in the tubing. Further well integrity diagnostic surveys were run to confirm the downhole temperature profile and detect the source of the temperature anomaly.
Given the nature of Well-A's completion, a flowmeter log could not pinpoint the source of leak. As an alternative, a spectral noise log was run to distinguish the different flow characteristics of the well at shut-in, producing/injecting, and transient conditions. The transient logging technique was innovatively deployed in this special completion to record sounds from the leak source when the well was normalizing from injection temperature condition to shut-in temperature condition. The distinctive flow sounds of the transient logging mode singled-out the source of temperature anomaly to be tubing leaks. The accurate rigless diagnostics helped optimize the workover operations, saving rig time and allowing the proper planning of rig corrective actions ahead of schedule.
Dual Parallel Simultaneous Injection and Production SIP Completion in Single Wellbore Reduces Development Costs and Accelerates Production
Authors: Anthony E. P. , Al-Zuabi H.. 
Published: October 2016

Abstract
In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment. Rather than dually produce or inject from separate reservoirs or layers, production & injection are achieved simultaneously, from the same wellbore, through successive tubing strings. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone.
Optimization of Steamflooding Heavy Oil Reservoirs Under Uncertainty
Authors: Temizel Cenk , Energy Aera , Balaji Karthik , Ranjith Rahul , Coman Chris 
Published: October 2016

Abstract
Conformance improvement is the key to success in most enhanced oil recovery (EOR) processes, especially CO2 foaming or steamflooding. Despite technical and economical restrictions, foam has been used as dispersions of microgas bubbles in the reservoir to help improve mobility. Steam-foam has many applications in the industry, including but not limited to heavy oil reservoirs, which are an important part of the future energy supply. Steam-foam applications have been used to help prevent steam channeling and steam override, thus improving overall sweep efficiency, not only in continuous steam but also in cyclic steam injection processes. Due to the high temperatures achieved during steamfloods, a robust understanding of chemistry including the thermal stability of surfactants is important.
The effectiveness and therefore the economics of the steam-foam process are strongly dependent on surfactant adsorption and retention. With that in mind, effective sizing of the foam injected requires a good understanding of the process. In this study, a reservoir simulator is used in which surfactant transport is modeled with surfactant availability determined by a combination of surfactant adsorption, surfactant thermal decomposition, and oil partitioning due to temperature. A robust commercial optimization and uncertainty tool is coupled with the reservoir simulator to generate the scenarios defined by control variables for optimization and uncertainty parameters for sensitivity analysis.
The degree of mobility reduction is interpolated as a product of factors that include aqueous surfactant type and concentration, presence of an oil phase, and the capillary number. An empirical foam modeling approach is employed with foam mobility reduction treated by means of modified gas relative permeability curves. Simulation results including the sensitivity of parameters and controlling agents, providing a better understanding on the influence of surfactant adsorption and thus the amount of chemicals to be used, are presented and discussed to serve as a guide for future applications. It is not easy to find documented examples of realistic optimization studies where significance of each parameter with its uncertainty is outlined and discussed using a realistic reservoir model. The simultaneous use of optimization and uncertainty led to a better understanding and thus control of decision variables with range of uncertainty that will be useful in analyzing prospective assets.
Conceptual Design for Maintaining Production of High CO2 Gas in Marginal Field Offshore by Using a Thermoplastic Pipe
Authors: Yananto Hanto , Girindra Yuyung 
Published: October 2016

Abstract
SRA is one of the well platforms in a marginal gas field operated by PT Pertamina Hulu Energi Offshore North West Java (PHE ONWJ). SRA production is evacuated to the SA platform via a 6.3 km 8" Main Gas Line (MGL), which has been in operation since 2002. Changing corrosiveness of the fluids produced at SRA after the MGL integrity and in 2015 several leaks were detected. Repair by conventional means or replacement was deemed uneconomic. A study was therefore initiated to evaluate the technical and economic feasibility of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields with high CO2 content without increasing safety or environmental risks.
In the appraisal stage, several technology options were considered and a thermoplastic pipe was selected as the preferred alternative compared to traditional rigid carbon steel pipeline. The assessment process started with a pipeline technology review, followed by technical compatibility/acceptance study, a check of commercially available pipe sizes and a comparison of total installation cost, installation schedule, and operation-maintenance considerations. The decision was facilitated by Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk.
The thermoplastic plastic pipe assessed is a flexible pipe for shallow water consisting of polyethylene (PE) internal liner, annular ring steel strip armor, and PE outer sheat. The PE inner liner is nearly hermetic, but allows traces of gases such as CH4, CO2, H2S, and H2O to permeate through. These permeants tend to accumulate in the flexible pipe annulus. A slight overpressure above atmospheric develops in the pipe annulus driving the gases to the end fittings where they are vented, preventing excessive pressure build up.
Additional weight is required for on bottom stability of thermoplastic pipe to be laid in Offshore North-West Java area. The installation spread will be using the available Pipe Lay Barge blanket contract for the Pipeline Repair and Replacement Program.. Even though some advantages of flexible pipe cannot be obtained in this project, such as additional weight required and lay barge usage instead of DP2, the selected concept is still the most economic compared to other options. The CAPEX is 10% less than carbon steel pipe. OPEX reductions can be achieved by reducing pigging operations and eliminating In-line Inspection (ILI) and chemical injection.
Strategies for Early Detection of Downhole Casing Failures Caused by Corrosive Formations
Authors: Al-Ajmi Mohammed D. , Al-Hajri Nasser M. , Mishkes Abdulrahman T. , Saloojee Mohammed C. , Fayyaz Muhammad Faisal 
Published: October 2016

Abstract
The Middle Eastern formations E & K are aquifers which are commonly problematic due to their corrosive characteristics, have been known to directly cause downhole casing completion leaks, and hence require careful risk assessment. If severe corrosion is not detected early then related leaking completions can lead to water from these upper formations cross flowing down into producing reservoirs with results being economic loss due to reservoir damage and/or direct loss of production. Environmental impacts of hydrocarbons leaking into shallow aquifers are an obvious risk of a leaking casing. The worst-case scenario is when production fluids, particularly methane and H2S, enter these formations via near-surface casing leaks and migrate to the surface where the potential for catastrophe is highest. This investigation explores causes and effects of severe external well casings corrosion in an oil-producing brownfield in the Middle East.
This research utilizes advanced corrosion monitoring technology, capable of measuring total wall thickness of concentric casings, which were logged in adjacent wells within a one-half mile radius. An important part of the well assessment strategy also includes examining historical drilling and cementing of several other completions in the same field to categorize the probability of integrity failure due to external corrosion.
Observations include establishing correlations between these lost circulation formations and measured external casings corrosion wall loss. The corrosive characteristics and impact of these dynamic, near-surface aquifers is also discussed to establish the root cause of external casing leaks. The objective of this study is to share these lessons-learned and develop a strategy for recognizing, mitigating, and/or avoiding similar well integrity conditions. By instituting a well-to-well pattern recognition classification of known problematic wells, promoting an enhanced corrosion surveillance frequencies.
Seamless Integration of Technology with People and Process Through In-House IT - A Case Study
Authors: Deka Mousumi , Roychoudhury Atindra 
Published: October 2016

Abstract
Oil India Limited (OIL) is the 2nd largest national E&P Company of India. Its legacy dates back to more than 100 yrs. Change in economic environment of India has led to a faster rate of development and steep rise in energy need. To meet the growing energy demand, OIL too has grown: both in size and geographical spread to a pan India Company having global footprints in exploration and producing assets.
Growing size and geographical spread, made it imperative for OIL to leverage advantages of emerging IT tools in its operations and processes. However, seamless integration of the IT tools with OIL’s golden legacy and culture is a challenge.
Being an E&P company, monitoring of progress of drilling operations and production of Crude Oil & Natural Gas, their supply to consumers and analyzing their trend is of prime importance to management and decision makers. The prevailing method of paper based reporting and telephonic data flow in this legacy company ended to online tabular reports with the implementation of SAP ERP across the organization in OIL. However, the same was unable to fulfil the need and expectation of top management resulting in decision makers continued dependence on subordinates. The requirement of a modern day visual IT tool like interactive Dashboard with relevant online graphical data and analytics has become the need of the hour.
This paper describes how an interactive Dashboard has been effectively and successfully introduced as an effective operational information and Knowledge Management tool in a legacy driven company like OIL. It also emphasizes special efforts made to customize the Dashboard in a way to blend it with existing methodology of information sharing to bring in acceptability to users. Further, the paper describes how successful and cost effective the in-house development/ implementation process compared to outsourced development.