bluuebunny/crossref_metadata_2025 huggingface dataset:
The Shift of a Dividend Policy and a Leverage Policy during the 2008 Financial Crisis
Authors: Lim Kwangsoo
Published: October 2016

This paper investigates how firms shifted their dividend policies and leverage policies in response to the economic shock caused by the 2008 financial crisis. The sample countries are United States, Great Britain, France, Germany, Australia, Japan, China, and Korea. The empirical relationship of firms’ dividend policies with their capital structures and earnings was likely to undergo a major change around the 2008 financial crisis, as firms adjusted their capital structures and dividend policies in response to the extreme credit crunch caused by the financial crisis. The extent and the speed that firms deleverage themselves and reduce their dividends were likely to be influenced by countries’ cultural and social norms. This paper finds a significant reduction in dividends across sample countries except Great Britain and France after the 2008 crisis. This finding supports the free cash flow theory that dividends are paid to dissipate free cash flow to address agency conflicts between managers and shareholders. This paper finds a higher correlation between dividends and leverages before the 2008 crisis, and that it strengthened after the crisis except Great Britain and Korea. This finding is consistent more with the pecking order theory than with the trade-off theory of leverage.
Guest Editorial: An Environmental Perspective on Risk Management and Water
Authors: Anderson Scott
Published: October 2016

Guest editorial

There is no denying that the oil and gas industry, as well as the agencies that regulate its activities, have significantly improved many aspects of environmental performance in recent years. Standards and practices have changed, in some cases drastically, leading to risk reductions in a number of areas.

Despite this progress, there is always more to be done to identify and manage risks associated with oil and gas development. As industry continues to evolve through technical advances, so should leading practices and regulations. This is particularly important given that the broader public is increasingly aware of and concerned about potential impacts on the environment and their communities from development, especially where those impacts involve water. Fortunately, improved understanding of risks and newly emerging risk control options make continual improvement possible.

Where should industry and its technical advisers concentrate at this juncture? A number of noteworthy, long-awaited reports on the environmental impacts of oil and gas development have been published over the past year or are awaiting publication. To a significant degree, these reports coalesce into a few major areas of concern, and endeavor to provide guidance on how governments and industry can achieve additional risk reductions to minimize or eliminate potential impacts on water.

The Reports

US Environmental Protection Agency (EPA), “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources,” Draft, June 2015 The EPA report highlights potential vulnerabilities to drinking water and confirmed pollution events. Vulnerabilities include (1) inadequately cased or cemented wells resulting in belowground migration of gases and liquids, (2) inadequately treated waste water discharged into drinking water resources, and (3) spills of hydraulic fracturing fluids, flowback, and produced water. Given these vulnerabilities and knowledge gaps highlighted by EPA, industry should not take too much comfort in the widely reported conclusion that the EPA found no evidence of widespread, systemic impacts.

California Council on Science and Technology (CCST), SB4 Commissioned Report for the California Natural Resources Agency, “An Independent Scientific Assessment of Well Stimulation in California,” July 2015 The CCST summary report contains an appendix summarizing the “most concerning risk issues” including (1) the number and toxicity of chemicals in hydraulic fracturing and acid stimulation fluids, (2) hydraulic fracturing in reservoirs with a long history of oil and gas production, (3) spills and leaks, (4) beneficial use of produced water, and (5) disposal of water in percolation pits.
Technology, Efficiency, and Midstream Growth Drive Long-Term Future for Marcellus, Utica
Authors: Parshall Joel
Published: October 2016

While the collapse in oil price is reshaping opinions about the North American shale revolution and the outlook for oil producers, natural gas producers in the United States are in a somewhat different position. They have contended with low prices since late 2008 and yet remain in a domestic market with substantial long-term growth potential while soon anticipating access to higher-priced global export markets as low-cost producers.

No producing area is more invested in the future of US natural gas than the Marcellus Shale that stretches across much of the Appalachian Basin, with development activities concentrated in Pennsylvania and West Virginia. The Marcellus produces approximately 20% of US gas supplies. And beneath the formation lies the highly prospective Utica Shale, in which drilling and production, especially in eastern Ohio, are getting under way.

The near-term outlook is anything but rosy at current natural gas prices ranging below USD 3/Mcf at the wellhead. However, the producers generally have plenty of experience with low prices. With a constant focus on technological innovation and increased efficiency, and the continuing expansion of the midstream network to create more marketing options, the gas industry in the Marcellus and Utica is laying the groundwork for a better future for many decades to come.

“I think we’re just really in the beginning of realizing how much potential is actually in the Marcellus and the Utica,” said Jeffrey Daniels, director of the Utica Shale Energy and Environment Laboratory at Ohio State University. Daniels is a professor of Earth sciences at the university and a member of the Ohio Oil & Gas Commission.

According to the most recent estimate by the US Energy Information Administration, the Marcellus holds 354 Tcf of proved gas reserves. However, technically recoverable gas reserves, an assessment that does not consider gas prices, have been estimated at 480 Tcf by Terry Engelder, a geosciences professor at Pennsylvania State University.
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

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

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 < 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 > 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

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

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

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

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

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

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.
Use of a New Casedhole Resistivity Tool Helping Optimization of Production and Time in Wells With Hole Issues; a Case History from the Greater Burgan Field, Kuwait
Authors: Bahman Hussain , Naik Vinay , Gazi Naz , Malik Abdullah , Al-Sabea Salem , Ali Farida , Hayat Laila , Marafie Hussam , Bibi Amro , Barnett Steven , Eremenko Vasiliy B.
Published: October 2016

A mature field similar to the Greater Burgan field in Kuwait brings many challenges. The Kuwait Oil Company (KOC) has determined that the production from the Burgan oilfield of South & East Kuwait required to be maintained as per the production plan. Often, the unavailability of suitable surface locations posed several challenges, and drilling was one of them. A new approach helped to address these issues which otherwise delayed production. The Lower Cretaceous Burgan sands are divided into five main reservoirs; two reservoirs consist of stacked, massive fluvial channels, while the remaining three mostly consist of deltaic distributary channels and bays in a tidal delta setting, grading to shallow marine. These three reservoirs are also discontinuous, both laterally and vertically.

Every year in the Greater Burgan field, a large number of wells are drilled targeting the Cretaceous reservoirs. The Greater Burgan field has been producing for more than 60 years. Due to the unavailability of suitable surface locations, highly deviated wells are drilled, and to reach them at target reservoir, the well profile sometimes passes through faults which create partial or total losses while drilling, which results in badhole condition. In some of the wells, owing to poor hole conditions, recording openhole logs are not possible. Normally in such cases where openhole logging is not possible, PNC logs are carried out. However, recording of PNC logs is only possible after 2-3 months when the effects of mud invasion and mud filtrate are reduced to a minimum. However, this delays production.

Openhole logging had to be abandoned in one of the recently drilled wells, due to poor hole conditions. Resistivity Behind Casing tool (RBC) was proposed to be run in this well as a replacement for the PNC log. The RBC provides the measurement of reservoir bed resistivity in order to determine the oil saturation for estimating reserves. The RBC uses stationary measurements where the tool’s probes apply current to the steel casing. The current that is leaked into the formation is then measured and processed to determine the formation resistivity. The tool has a depth of investigation of 7 to 34 ft depending on the bed thickness and is therefore not influenced by the effects of mud invasion.

Based on the casedhole resistivity, potential intervals were identified, perforated and were put on early production. Casedhole resistivity paved a way for replenishment of missing data on openhole electrical logging. This has enabled early production from a well with badhole issues.
Efficient and Scalable Methods for Dual-Porosity/Permeability Models in Fractured Reservoir Simulations
Authors: Cui Tao , Wang Kun , Liu Hui , Luo Jia , Chen Zhangxin
Published: October 2016

In this paper, the multi-stage preconditioners are modified and applied to dual-porosity/permeability (DPDK) model problems. Employed as the first step of the multi-stage preconditioning processes, two modified decoupling processes for DPDK problems are developed. In a DPDK model, mass transfer both between fractures and between matrices is allowed, which means that the pressure both in fractures and matrix behaves as an elliptic property, so it is natural to employ two preconditioning stages solving the fracture pressure system and the matrix pressure, respectively, which draws the first type of a multi-stage preconditioner in this paper. Since the transmisibility between fracture blocks is much higher than that between matrices, the elliptic property of the fracture pressure is much stronger. Hence, we remove the stage of solving the matrix pressure system in the second type of a multi-stage preconditioner. Moreover, an extra stage of the ILU preconditioning process is added to the above multi-stage preconditioners in order to improve their efficiency, which results in another two multi-stage preconditioners. Combination of the modified decoupling processes and four new multi-stage preconditioners are studied and compared by large-scale reservoir simulation problems. Based on these numerical experiments, the optimal method to solve the DPDK model problems is concluded.
How to Age Gracefully – Pipeline Life Extension
Authors: Selman Allison , Hubbard Rex
Published: October 2016

This paper presents the engineering process for performing a design life extension study (or design requalification) for an offshore pipeline system. The principles and process however, could be applied to design requalification of any physical asset.

Every pipeline system is designed for a theoretical maximum duration called its design life. In some instances there may be a requirement to continue operations beyond this date. This paper provides guidance on the technical life extension processes and procedures and it focusses on the engineering that is required to provide adequate assurance for safe continued operations.

This paper presents the two main international guidelines that are typically used: NORSOK Y-002 and ISO 12747. The life extension process is discussed step-by-step with guidance on technical considerations at each stage. A case study example is used to demonstrate how the process has been applied to assess the fitness for service of an offshore pipeline system for an additional 20 years.

Pipeline life extension opens up many development opportunities, especially in challenging economic conditions. If a pipeline can be re-used or re-purposed for future developments then significant CAPEX reductions can be achieved for small, nearby developments. To enable this opportunity the risks of continued operation must be fully understood following a systematic and comprehensive approach to assess the risks. Once the risks are understood then they can be adequately managed through a proactive integrity management program.
Safety Measures Undertaken and Planned for North Kuwait's Sour Hydrocarbon Installations
Authors: Alomair Ahmad , AlSaleh Mohamed
Published: October 2016

Kuwait Oil Company (KOC) is developing Jurassic fields spread over 65 X 50 Km in North Kuwait, which are aimed to support the state's growing gas demands. The present contribution to Jurassic production is from Raudhatain, Sabriyah, NWRA, Um-Nigah & Dhabi fields of sour MM/NS reservoirs. Some of the wells and flowlines of these fields are located outside current KOC security fence very close to the existing public Farm Houses, posing great threat to public in the event of toxic H2S gas release. This paper mainly describes KOC's Production & Project Gas Group initiatives undertaken to mitigate the threat to public safety (potential Societal Risk) by implementing effective barriers to minimize the source and impact of any toxic gas release.

Immediate safety measures undertaken include installation of field crash barriers along entire flowlines/corridors that prevent damage to existing surface flowlines. Mid-term protection by boundary fencing is in advance stage of installation for UN, NWRA, DA & Liyah fields and H2S warning signs are installed at well heads as well as along flowline routes. Long-term plans are underway to install required safety instrumented instrumentation for improved safeguarding systems of well heads, flow lines & the Early Production Facility (EPF-50) protection. The plan includes monitoring facilities of potential H2S release and public warning system (in two phases) for emergency preparedness and crisis management.

The paper presents few specific cases of how by implementing the safety measures and barrier installations so far have yielded results in avoidance of hazardous condition and unsafe incident.

In addition, the paper also presents process safety features like hazard analysis and risk assessment studies (HAZOP, SIL assessment, QRA etc.) carried out to identify potential risks associated with site specific situations (both for Jurassic field areas and EPF-50 plant) based on ALARP principle.
Safety Risk Management of Drilling Operations
Authors: Zhang Shaohui , Teng Xinxing , Wang Ling , Wang Shuai , Wen Liangfan
Published: October 2016

Safety risks of drilling operations exist widely because of the hostile environment, ageing equiments, more challenging wells, human errors, etc. Failure to control or eliminate the safety risks may affect the drilling safety and lead to drilling accidents, resulting in enormous economic losses, or even casualties. Previous drilling accidents had shown great challenges of safety risk management, such as outdated management ideas and tools, poor awareness of safety risks, lack of effective safety risk information sharing and incomplete risk management system.

In this paper, the potential safety risks associated with drilling facilities, workers, and management are figured out, and the corresponding risk management measures are formulated. Meanwhile, the guidelines for safety risk management of drilling operations are established. In addition, the guidelines are combined with the information technology, and the Web and mobile versions of the intelligent safety risk management software of drilling operations are designed and developed. The safety inspector in drilling sites can use mobile terminals to identify the drilling risks, being recorded in the form of text, pictures, video and other documents, and choose the risk control and mitigation measures. The safety management staff in the company can monitor the results of chosen measures in time by using the Web version, and provide effective and timely technical support for the field’s safety risk management if necessary.

With the use of the intelligent safety risk management software of drilling operations, the two-way communication and safety risk information sharing between drilling sites and drilling safety management departments can be realized. A complete drilling safety risk management system can also be gradually developed in the process of risk identification, record, report, analysis, control, mitigation and prevention.

The intelligent safety risk management software of drilling operations has been applied in some oilfields, and reveals excellent application prospects. Being an intelligent management tool, the software system can significantly improve the safety risk management efficiency, and finally realize the informational management of safety risks in drilling operations.
Mobile Data Acquisition: There's An App For That … Or Is There?
Authors: Linden Mason
Published: October 2016

The world of mobile data acquisition is transitioning rapidly from paper and pencil to the smartphone and tablet. In this age of big data, one of the primary operational risks is how to collect reliable, accurate and timely data in a cost efficient manner. Modern operations require a large amount of accurate data to make informed engineering decisions on maintenance and operation of large numbers of assets, using OPEX as efficiently as possible. Remote locations, poor connectivity and a need for highly bespoke data acquisition tools mean that industry is required to solve its own challenges.

Wood Group has been in the role of self-determination and innovation in mobile data acquisition for the better part of a decade and shares in this paper a series of key design decisions and case-study examples of the process in action. The experience shows that real efficiency gains are possible and that if industry can come together to solve some of the challenges in a connected way our work environments will continue to transform.
Change in Geomechanical Properties of Limestone Due to Supercritical CO2 Injection
Authors: Zhang Yihuai , Lebedev Maxim , Sarmadivaleh Mohammad , Barifcani Ahmed , Iglauer Stefan
Published: October 2016

CO2 geo-storage in deep saline aquifers or oil and gas reservoirs is a key technology to mitigate anthropogenic greenhouse gas emissions. Technically, CO2 is captured from large emitters, e.g. coal-fired power plants, and injected deep underground into geological formations. In case of hydrocarbon reservoirs, this can be combined with CO2-enhanced petroleum recovery, which is rather efficient. One potential host rock for CO2 is thus porous limestone; however, the geomechanical response (especially at the microscale) of the limestone when it is exposed to the acidic CO2-fluids (CO2 saturated brine or wet supercritical CO2) is only poorly understood.

We thus measured the geomechanical properties of Savonnières limestone cores before and after injection of supercritical CO2 at the microscale. The CO2 was injected at representative flow conditions: a fully brine saturated storage reservoir at approximately 1000m depth (323K temperature, 10 MPa pore pressure, 5 MPa effective stress) was simulated, and 10 pore volumes of supercritical CO2 were injected at a capillary number of 10-6, which mimics storage conditions. The dynamic elastic properties and the formation factor were measured and compared with the geomechanical response.

We found that the dynamic Young’s modulus decreased, while permeability and porosity increased after scCO2 injection; however, the micro-scale indentation moduli showed a dual behaviour: while the indentation modulus slightly increased in less consolidated rock areas, it decreased in the more and highly consolidated areas. We conclude that the scCO2 injected into limestone weakens the well consolidated areas, but strengthens the weaker areas.
Dual String Section Milling Tool Design Optimisation Using Advanced Numerical Simulations
Authors: Deshpande K. M. , Haq M. A. , Gajula S. , Teale D.
Published: October 2016

Well Intervention Plug and Abandon (P&A) operations play an important role at the end of life cycle of a subsea well in safely dismantling the well such that the well no longer poses any environmental hazards. P&A operations for subsea wells require sophisticated and efficient downhole tools that can operate at downhole pressures safely and reduce Non-Productive Time (NPT). A Dual String Section Milling (DSSM) downhole tool removes two adjacent casings in single trip reducing NPT while conducting safe P&A operations is discussed in this paper. This paper’s objectives are two fold first is to utilize advanced computational fluid dynamics (CFD) to improve DSSM tool life span for safe and economical P&A operations and second is to develop methodology for a quick and reliable solution for field personnel by combining CFD results with known closed form hydraulic models.

The DSSM tool must maintain a certain pressure drop and flow range to achieve optimum performance. Higher flow rates and pressures can reduce tool life and cause erosion/washouts due to higher flow velocities. To address these issues simultaneously numerical simulations are conducted to optimize the DSSM tool design and operating parameters. To prove validity of numerical results CFD simulation outputs are compared against available test data and a good match is observed. Three dimensional CFD simulations are conducted using pressure based algorithm for numerically solving Reynolds-Averaged Navier-stokes (RANS) equation using second order upwind discretization scheme and k-ε turbulence model. Extensive CFD results are utilized in generating flow coefficients for closed form hydraulics models to formulate pressure drop versus flow rate charts for field usage.

CFD simulations are conducted for flow rates between 100 gpm to 700 gpm to understand flow characteristics and pressure drop distribution within DSSM tool. CFD simulations showcased the locations prone to washouts; particularly washouts were observed around 90 degrees bend angles. The washout locations indicated by CFD analysis matched very well against the available test data. The DSSM tool design was then optimized using CFD simulations such that fluid velocities were below washout velocity and also higher annular velocities were maintained to alleviate hole cleaning problem during milling operations. The pressure drop versus flow rates curves obtained using flow coefficients showed correct trends with higher pressure drop for higher flow rates and higher pressure drop for reduced nozzle size. Thus utilizing CFD analysis, optimization and laboratory testing, service life of DSSM tool was increased, thus saving substantially on field NPT.
Analysis and Test of Flow Field of Two-Stage Series Downhole Hydrocyclone
Authors: Yang Gao , He Liu , Shujun Bao , Fengshan Wang , Guoxing Zheng , lei Zhang , Bo Yu , Li Zhang
Published: October 2016

Hydrocyclone is a critical component of downhole oil-water separation technology. Sometimes, it is necessary to use two hydrocyclones in series in order to improve the effectiveness of downhole oil-water separation and reduce oil concentration in reinjected water. Unlike single-stage hydrocyclones, however, a two-stage series hydrocyclone is characterized of a more complicated flow field, more significant flow field interference and more factors that affect separation effectiveness.

The flow field of a two-stage series hydrocyclone is analyzed and, in particular, the distribution of oil phase, pressure field and velocity field near the overflow port of the second stage hydrocyclone is studied by means of a two-stage series hydrocyclone oil-water separation model built based on the hydrodynamic theory.

According to our analysis, when the water content of oil-water mixture is higher than 97%, the two-stage series hydrocyclone offers insignificant advantage in separation effectiveness compared to a single-stage counterpart; when the water content is lower than 97%, the effectiveness of separation using a two-stage series hydrocyclone is very significant, where the second stage hydrocyclone provides good repurification of underflow of the first stage hydrocyclone, helping to reduce oil concentration in reinjected water. It is also discovered that the geometry of the connector located between the two hydrocyclones is the major factor affecting the separation effectiveness of the second stage hydrocyclone. Cylindrical connector, which is identified as the best geometry by comparing connectors of three different structures through modeling analysis, can not only improve the separation effectiveness of the series hydrocyclone but also offer decreased pressure loss.

The accuracy of analysis and calculation results are further verified through comparison of results of lab tests conducted on the two-stage series hydrocyclone on the basis of analytical calculation.