bluuebunny/crossref_metadata_2025 huggingface dataset:
Preventing Dropped Objects on Offshore Units and Installations
Authors: Corcoran Chris , Stroubakis Demetri , Sarthy Ahmad
Published: March 2018

ABS has published the first international class standard on the subject of dropped object prevention. The objective is to promote offshore safety through improved asset integrity management and the use of inherently safe design principals. This paper serves to increase dialog among owners, operators and manufacturers by presenting the drivers behind the development of the ABS standard and examples of what can be accomplished to achieve a dropped object free working environment.

Dropped objects are among the top 3 causes of injuries in the work environment and accounted for 14% of fatalities in the US Upstream Oil and Gas Industry from 2003-2014. A summary of statistical information will be presented along with the results of research on regulatory requirements and current design standards. A brief history of dropped objects in the workplace as they relate to the historical development of safety systems will be discussed and the content of the ABS Guide for the Prevention of Dropped Objects on Offshore Units and Installations will be presented.
The Use of Advanced Logging Technologies to Identify the Hidden Hydrocarbons in an Interbedded Sandstone-Shale Reservoir
Authors: Nugroho Cahyo , Bouchou Ramdane , Ghioca Monica , Le Viet , al-Turkey Shaikha
Published: March 2018

This paper presents a detailed study on how to detect the presence of light-oil in a low-resistivity and interbedded sandstone-shale environment. Based on the basic log response (high GR readings, 45-55 API, low resistivity values, 3-5 ohm.m, low-to-moderate porosity), the studied interval was considered a non-oil bearing zone. The interval was re-evaluated by adding some advanced technologies and the results showed the zone to be oil bearing. Fluid sampling has confirmed that the zone is oil bearing zone.

The advanced logging technologies were magnetic resonance, mineralogy and high-resolution borehole electrical imaging. The mineralogy tool was logged to identify and quantify the formation minerals and also the clay typing. The magnetic resonance tool was used to identify the different fluids inside the pores and also to measure the fluids saturations. The high-resolution borehole electrical imaging was used to analyze the sedimentary facies and the formation structures. At last a sample of the formation fluid was successfully taken after flushing out the filtrate from the formation for about 10 hours and pumping out about 40 liters.

The NMR technology played an important role in detecting and quantifying the oil over the interbedded sandstoneshale zone. The fluid typing analysis of magnetic resonance measurements identified up to 50% oil saturation with permeability index ranging from 10 to 20 mD. As the tool can only read between 2 and 4.2 inches inside the formation, the saturation analysis is affected by the mud filtrate. This means that the actual oil saturation might be much higher than 50%. The mineralogy tool showed 25-35% volume fraction of clay, mainly illite, kaolinite, smectite, and the remaining volume is quartz. These fractions indicate that the interval is shaley. Because of its low vertical resolution, it was not possible to see any interbeds with the mineralogy tool. However, the high resolution borehole electrical imaging showed clearly the formation sedimentary structures which are interbedded sandstoneshale. The fluid sampling has confirmed that the low resistivity pay in the interbedded sandstone-shale interval is an oil bearing reservoir.

This type of reservoirs is usually underestimated when evaluated with only the standard logging technologies, because of the effect of the shale laminations on the measured formation resistivity. So, in such environment, the use of different technologies is required to first understand the nature of the environment and also to overcome the impact of the laminations in identifying the presence of oil and also quantify it.

The combination of the NMR, mineralogy, high resolution imaging and fluid sampling technologies has proven its successfulness over interbedded sandstone-shale reservoirs.
Development of a Novel Compact Sand Sample Analyzer Mitigates Space and Time Constraint
Authors: Gupta A. , Salleh N. I. , Tan B. C. , Choi Y. X. , Zulkifli N. M. Q. M , Hassan A. F. , Manaharan I. , Harun H. E.
Published: March 2018

Analysis of sand sample to get sand concentration in oil wells requires a proper set-up with significant footprint in a sand producing oil platform. Also, the conventional procedure used by most operators result in high time consumption leading to delay in results if required immediately. Logistics of having a lab at the platform is also a challenge. Further, evaluation of particle size distribution becomes a further challenge in a limited space. The paper describes development of a compact sand sample analyzer with a reduced foot print and quick analysis for better decision making. The current methods of sand count analysis were analyzed in detail and various options were look into to save the foot print and time on the analysis of sample so that sampling compliance can be met. The two main steps in standard sand production concentration measurement method i.e. heating of sample to dry and remove moisture and weighing the sample accurately required two different sets of equipment and it is time consuming. A moisture analyzer equipment is replaced by these two equipment making the entire system very compact and reducing the duration of results from hours to minutes. Also, the sieve size of sample collection was reduced to accommodate a smaller footprint PSD Analyzer as well. The proposed set-up was tested in lab and it is found that a 3 hours procedure of evaluating sand count was reduce to 20 minutes i.e. increasing the efficiency almost ten times. When comparing the logistics challenge, the sand count result turn around time was reduced from almost 7 days to few hours. Similarly, the compact PSD set -up resulted in cost saving of conducting in house PSD and getting such a data in a matter of hours. All this lead to huge cost saving and most importantly efficiency in complying with sampling standards. The standard practice where minimum of 3 personnel with more than 10 sq. ft. of equipment footprint and more than a day require to get the result is reduced to a 20 kg suitcase with only one personnel and less than 30 minutes for the total analysis. The novel idea of using a moisture analyzer in place of the two equipment had a uniqueness because in this case moisture analyzer was indirectly used for some other purpose. Also, the modification in sieve could not have made this set-up compact. The sampler has proved a breakthrough for sampling analysis for all major sand producing fields within operator and this unique idea will benefit industry as a whole.
Real Time Condition Monitoring of the Wellbore Seal through Hydraulic Fluid Analysis Using an Active Wellbore Sealing System during Managed Pressure Drilling
Authors: Johnson Austin , Sundaramoorthy Saravanan , Piccolo Brian , Fraczek Justin
Published: March 2018

Objectives/Scope

This paper introduces an active wellbore sealing system for use in Managed Pressure Drilling (MPD) incorporating a wellbore seal condition monitoring system. The paper will discuss how finite element analysis which has previously been validated with full scale testing can be expanded to develop the condition monitoring system.

Methods, Procedures, Process

In contrast to a passive rotating control device, an active MPD wellbore sealing system requires hydraulic pressure to engage a sealing element and form a wellbore seal. The paper will investigate the relationship between wellbore sealing pressure and hydraulic fluid parameters using the results of finite element analysis on a sealing technology which has been previously operated offshore in addition to extensive full-scale testing in a lab environment.

Results, Observations, Conclusions

The paper will show how the required hydraulic fluid requirements to form a wellbore seal change over time due to sealing element wear. The information can be used to predict the remaining life of the existing sealing element as well as proactively alarm the driller of the need to replace a seal sleeve due to a sudden deviation from expected behavior. The implementation of a real-time, condition monitoring system for the MPD wellbore seal is intended to increase the rig's confidence toward using MPD for challenging hole sections as well as circulating out small influxes from the well without closing the SSBOP, further reducing the risk of stuck pipe events.

Novel/Additive Information

The active MPD wellbore sealing system is a non-rotating, offshore wellbore annular sealing device which is integrated into the riser. It contains a seal of elastomeric composition which seals against drill pipe during all tripping and drilling operations. As the seal wears, the hydraulic closing fluid requirement to maintain an annular seal changes, which indicates the amount of seal material remaining.
High-Speed Robust Simulation Delivers Fast, Detailed Results for a Complex Offshore Field
Authors: Thapliyal Anil , Kundu Sudeb , Dimri Sunil Kumar , Dutt Ankit , Mishra Shubham , Aggarwal Akshay , Agarwal Ankit , Ojha Aditya , Bradley David , Giddins Marie Ann
Published: March 2018

For planning the operations of Oil and Natural Gas Corporation Limited (ONGC) in the complex Heera field, it was estimated that over one hundred simulation runs would be needed to complete the history match of the field and almost the same number of simulations would be needed for production forecasting. Heera is a large field, with multiple faults and seven stacked carbonate formations. There are significant variations in petrophysical properties, and variable degrees of communication between reservoir zones. The simulation models include 479 wells with commingled production or injection. Well trajectories are complex and include multilateral and horizontal configurations. Field development options include use of simultaneous water alternating gas (SWAG) for enhanced oil recovery.

Combining all these features, it would be difficult to run all the necessary sensitivity cases within the required project timeline, using a conventional reservoir simulator. Therefore, it was decided to test the applicability of a new generation simulation tool to address the challenges of the study.

To ensure that the change of simulator would not impact the integrity of the model, rigorous quality checks were performed on the input data. After successful evaluation, the new software was used for the reservoir engineering study.

The decision to apply the new simulator significantly reduced the elapsed time, with some realizations over 20 times faster compared to the original base case. As a result of this speed-up, numerous runs could be carried out to refine the history match. Multiple sensitivities could be used to help understand and reduce the uncertainties in a more comprehensive manner. Moreover, the prediction cases could be optimized to identify the best recovery strategy.

This study has demonstrated the value of reducing simulation run times, to complete the project with greater efficiency and more confidence in the results. In future studies, high performance software tools can also enable use of fine resolution models, to capture detailed heterogeneities and optimize areal and vertical sweep.
FIELD A A New Solution for Marginal Field Development
Authors: Shaipulah Ahmad Adzwan Bin M , Ahmad Mohammad Azharie B , Othman Sy Nafisah Bt Sy , Rahman Ahiruddin B Ab
Published: March 2018

FIELD ‘A’ Project is presented as a low cost development concept for marginal oil field. The development concept consists of wellhead platform with a full well stream evacuation scheme through a flexible flow line to FPSO for further processing and subsequently for export. The unutilized associated gas is flared. As a part of cost reduction strategy and incentive, the Host Authority has approved a new contract model and technological approaches for implementation.

FIELD ‘A’ Project is undertaken and monetized via a new approach of marginal oil field development under the Risk Service Contract (RSC). The uniqueness of the FIELD ‘A’ development concept is the technological introduction of re-locatable type fixed asset using Suction Pile Technology (SPT) for jacket installation thus allowing it to be transported and utilized at other potential marginal field within the asset design life. SPT is a traditional jacket with integrated suction pile foundation, which triggered significant benefit and long term cost reductions in the fabrication and offshore installation.

The 1100 MT jacket is designed using suction pile technology that enables the platform to be relocated to other potential marginal field. SPT is proven to be a highly efficient and very swift concept where the jacket offshore installation campaign can be successfully executed in less than 24 hours as compared to the conventional jacket installation, which require several days of pile driving. Fabrication costs are reduced significantly since no requirement on the pile sleeves, catchers, centralizers, mud mats, and leveling pad eyes. Substantially, SPT jacket is proven to be that of one of the most cost effective in comparison to other re-locatable type offshore mobile facilities such as MOPU and MOAB. SPT is also integrated with scour protection; hence no seabed preparation or rock dumping is required. Therefore, the offshore campaign for SPT would promote lower installation cost, improved schedule and most importantly safety. In conclusion, the jacket with integrated suction pile foundation promotes and accordingly justifies the development of marginal field.

In the current environment of low oil price, developing a new marginal field in such a way is necessary so as to maintain or improve the overall economic of the project. This fit for purpose and hybrid SPT concept with a rigid substructure that can be easily relocated is definitely worth to be implemented.
Approach to Corrosion Management Program and Risk Based Inspection Development for the World's First Floating LNG
Authors: Mohamed Nurul Asni , Mahani Zulkarnain , Razak Liyana Afiqah Abd
Published: March 2018

In performing the Corrosion Management Program (CMP) study for PETRONAS Floating Liquefied Natural Gas Satu (PFLNG1) which is located at the Kumang-Kanowit Gas Field in Sarawak, a total of 59 Process, Utility and Marine units were analysed which resulted in the development of 111 Corrosion Groups (CGs). 17 potential degradation mechanisms are identified, encompassing internal and external corrosion. Anticipating the short term and long term corrosion rates are made possible by leveraging on PETRONAS database. Appropriate corrosion mitigation and monitoring recommendations are made for the control of a few corrosion mechanisms. These are managed through the application of the in-house software, CARAT.

Some challenges were encountered during the PETRONAS Risk Based Inspection (PRBI) assessment. The Plant and Instrument drawings for the shipping industry are not as detailed as that typically used for the oil and gas industry, giving rise to general assumptions for PRBI evaluation. The consequence of failures in the risk assessment are assigned taking into account the available maintenance items onboard and anticipated deployment of items from onshore. Risk analysis helps to identify critical items to be kept onboard. The Inspection Reference Plan developed evaluates the most efficient inspection intervals and the identified CMLs will reflect susceptible as well as accessible areas. CARAT and PRBI are now online and dutifully used by the end user to complement the execution of CMP and PRBI programs.
Engineering Simulation for Loadout of a Tension Leg Platform
Authors: Sinha S. K. , Luquiau Eric , Reddi Satish
Published: March 2018

Accurate prediction of loads on any large offshore structure during loadout and transportation is of utmost importance, not only for the design of the structure but also to predict operational margin and prevent any unwanted damage onto the structure during the process.

The design and engineering of Tension Leg Platforms (TLP) are usually carried out in accordance with the API 2T, MODU Codes and applicable company specifications/requirements. These codes provide extensive guidelines on design of TLP with respect to operational loads but specifics of simulation of loadout are not explicitly mentioned. This paper presents a method to estimate the loadout loads on any large offshore structure, in this case a TLP.

The loadout operation of TLP usually comprises of lifting of the structure, i.e. the hull with its topsides, to transfer the loads from temporary support blocks onto jacks followed by skidding of the structure through a distance to the quayside and then crossing over the structure from the quayside to the Heavy Transport Vessel (HTV) and finally setting down the structure onto the HTV to transfer the loads from the jacks to the skid shoe guide posts and additional support structures, on HTV.

It is the objective of this paper to present an optimized method of grouping the jacking system for safe transfer of loads during the above operation. This paper also talks about simulating and predicting the series of loads on the hull of the TLP during the entire process of loadout, crossover and setting down.
From Resource Extraction to Knowledge Creation: The Promotion of Local R&D through Upstream Regulations
Authors: Lima-de-Oliveira Renato
Published: March 2018

Oil-rich countries have long attempted to maximize its capture of oil wealth, traditionally using the direct production through NOCs or setting a high government take in contracts with IOCs. More recently, contracts and regulations have also focused in localizing manufacturing (local content) and promoting domestic capabilities in R&D. While local content regulations have received more attention in the scholarly literature, regulations to promote R&D, their effectiveness in promoting spillovers and their effect on oil company's strategy is yet an understudied area. This work studies the regulations and practices put in place by oil-rich countries, and particularly Brazil, Mexico, and Malaysia, to promote R&D through contractual obligations, such as levies earmarked to R&D and investments in knowledge institutions. It is based on the analysis of legislations, data on funding for research institutions, and interviews in the three countries with policymakers, regulators, oil company executives, and scientists to answer two questions: a) What policies have been used by oil-rich countries to promote R&D&I in the oil industry?; and b) how these policies influence the strategies of oil companies? This study shows that regulations in the oil industry can effectively contribute to the promotion of local capabilities in R&D, but issues of policy design are crucial to maximize the effectiveness of such policies. As the oil industry, and the offshore in particular, becomes more high-tech and subject to pressures to localize their investment, demands for local R&D are expected to increase. However, the set of policies that can capture wealth from current oil production – maximize government take – differ substantively from the capabilities and institutional complementarities necessary to promote knowledge.
Operating Envelope for Oil Pipelines in Caspian Sea
Authors: Azman Syahida Husna bt , Norpiah Rohaizad b M
Published: March 2018

Flow assurance problems related to flow slugging, hydrates, and wax gelling lead to this study, post two integrated oil pipelines clogged in the Caspian Sea during the winter season. The methods and proposed solutions will be further deliberate, which includes the development of operating envelope to ease implementation. The overall methodology is based on dynamic flow assurance simulation and mathematical analysis, which was adapted depending on the problem being studied. Reduced production and terrain undulations had caused severe slugging in both pipelines which are flowing multiphase fluids. The bifurcation analysis of slug control valve will be discussed to determine the best choke opening that can eliminate slugging. The flow slugging also caused hydrate risk that was made worst during shutdown. Few strategies of hydrate mitigation including implementing extra heat insulation at riser air gap, gas flaring, optimised and overdose injection of mono ethylene glycol (MEG) were considered. Hydrate mass was evaluated for all the mitigations and requirement to inject lean MEG immediately after shutdown or prior start-up was identified. In terms of wax management, lower Flowing Tubing Head Temperature (FTHT) from wells added a challenge with limited facilities capability to operate more than the wax appearance temperature (WAT). Operating envelope of crude oil heater under heating limitation will be clearly shown to avoid operating in wax region. The development of operating envelope had enabled Operations personnel to know the safe condition to operate both pipelines during critical scenarios. The approach has changed the way the company operates, to ensure production is protected and maintained with minimal disruption caused by slugging, hydrate and wax gelling events.
Numerical Simulation of Free Surface Flows Using Overset Mesh
Authors: Khaware Alok , Srikanth Kvss , Gupta Vinay Kumar
Published: March 2018

Overset method is validated for different free surface flow applications to demonstrate its capabilities and benefits over traditional dynamic mesh approach. An overset mesh consists of a set of overlapping component meshes, which allows complex geometries to mesh with lesser effort. Interpolation methods are enforced at internal boundaries to ensure a continuous solution in overlapping component zones. Overset methodology is not perfectly mass conservative by its design. Present study in this regard, demonstrates the benefit of higher order interpolation method on simulation accuracy and mass conservation. The simulation results for various case studies involving static and moving overset meshes are validated against analytical, experimental and equivalent non-overset mesh results using ANSYS Fluent.

Finite volume method (FVM) with pressure based coupled solver is used to solve Reynolds Averaged Navier Stokes equations. Free surface flow is modeled using Volume of Fluid Method (VOF) which capture interfaces between immiscible fluids. Pseudo-transient method is adopted for steady state applications to get better robustness. A pure advection of slotted circle is simulated where its revolution is forced along the static overlapping zone, final shape and position is compared with initial state after one revolution. A non-linear Stokes wave with high steepness is propagated in a numerical wave tank which contains multiple static overlapping zones in the vicinity of free surface, where simulation results of free surface and velocity profiles are verified against analytical profiles. Flow over a bump for subcritical to subcritical and subcritical to supercritical regimes are verified against analytical results. Flow over a submerged hydrofoil using static overset mesh is validated against experimental result for free surface profile. A rotating gear case involving moving overset mesh is compared with sliding mesh results for free surface and pressure profiles. A case involving transient heave oscillation of floating cylinder is validated with theoretical, experimental and equivalent dynamic mesh results.
Floating Hydrocarbon Storage Facility
Authors: Awn Paul Ong Pang , Chai Patrick Yap Gwo
Published: March 2018

Bunkering and oil storage is a growing and important business in Singapore. Driven by land scarcity, NUS and SINTEF are tasked to jointly explore the innovative concept of a Floating Hydrocarbon Storage and Bunkering Facility (FHSBF) off the coast of Singapore. The research collaboration, funded by Land and Livability National Innovative Challenge (L2 NIC) and JTC Corporation, aims to explore new ways to create useable space from sea. The floating facility will add to the current storage capacities of Singapore without the need for land reclamation. The Floating Hydrocarbon Storage Facility is a novel and viable concept to introduce useable space on sea. It allows for a land-scare country like Singapore to increase oil storage capacities without the need for land reclamation. The concept can be relocated and replicated in other locations with similar needs.
Managing Shallow Gas for Offshore Platforms via Fit-for-Purpose Solutions: A Malaysian Case Study
Authors: Huang N. N. , Girsang C. H. , Mansoor M. R.
Published: March 2018

Shallow gas seepage was first spotted at a central processing platform offshore Malaysia in 2010, acknowledged as Platform T in this paper. Frequent monitoring of the gas seepage was performed through ROV baseline survey and a comprehensive geophysical survey was conducted to understand the characteristics of the gas seepage and to ensure that the integrity of the foundation at Platform T was not compromised. The origin of the gas could not be ascertained at that point of time.

A soil investigation campaign was performed in 2016 to study the origin of the gas seepage. Two boreholes were drilled; a composite borehole to 150m below seabed for the purpose of soil sampling and in-situ testing and a pilot hole to 155m below seabed, which was later converted to a fit-for-purpose relief well as an alternate migration path for the gas. During the soil investigation campaign, dissipation tests were performed at several layers which were potentially the source or migration path for the gas. Five soil samples were segregated for headspace test to identify the gas type which subsequently can be used to identify the origin of the gas.

Dissipation tests performed at four depth intervals indicates pore water pressure less than 20% of the vertical effective stress and appear to continue decreasing if the test had not been stopped. It was concluded that a low to negligible amount of excess pore pressure exist in clayey silt layers. Results from headspace test show presence of methane corresponding to the clayey silt layers as reported in the boring logs. The gas most likely comes from biogenic sources, feeding on organic matter in situ over a large depth range.

It is unlikely that there are large pockets of gas in the soil due to its homogeneous clayey nature and the lack of excess pore pressure in other permeable clayey silt layers encountered. Instead, it is more likely that when pore water at certain depth encounters a more permeable path, such as a borehole, it rises up through this path due to the temperature gradient in the soil. As the water rises, the pressure decreases, which could cause gases dissolved in the water to come out of solution and form bubbles. As a result, the gas will have no impact on the integrity of the foundation at Platform T.

The fit-for-purpose relief well design as well as adopting headspace testing can be used to address the shallow gas issue at Platform T in a cost-effective and efficient manner.
Full-Scale Verification of the Hydrodynamic Motions of a Floating Facility
Authors: Zed M. , Milne I. A.
Published: March 2018

Quantifying the hydrodynamic motions of a floating facility is critical for ensuring its safe and efficient operation. The ability to obtain estimates of the motion response charactersitics using a numerical approach to estimate the seastate is particulary attractive for sites in which limited observational wave data are available. Validation of such a numerial approach using full-scale data is however, desirable in order to establish its accuracy and limitations. To this end, this paper presents a case study where numerical estimates of the dynamic motions of a drillship were validated using high quality dynamic motion records acquired during the drilling campaign. The model comprises a hindcast of the directional wave spectra and numerically derived hydrodynamic response characteristics of the ship. The performance of the model is evaluated using a range of selected seastates which were observed during the drilling campaign. It is demonstrated that reliable estimates of the motions of most interest for a drilling operation can generally be obtained, thus providing support to the use of the provided numerical approach for conducting operability assessments for floating facility planning purposes.
A Semi-Analytical Model for Simulating Fluid Flow in Naturally Fractured Reservoirs with Non-Homogeneous Vugs and Fractures
Authors: Wu Yonghui , Cheng Linsong , Huang Shijun , Jia Pin , Fang Sidong , Wang Suran , Xin Jing , Xu Bingxiang
Published: March 2018

Carbonate reservoirs are characterized of fractures, vugs and cavities. These vugs have a large attribution to reserves of oil and gas. And the fractures provide effective paths for fluids flow in the reservoir. Triple porosity model is an effective conceptual method to capturing rock matrix, vugs and micro-fractures connecting them. However, these fractures and vugs are always non-homogeneous. Macro fractures and vugs cannot be handled with continuum for their low density and high conductivity.

In this approach, the triple porosity conceptual model is implemented to characterize rock matrix, micro vugs and fractures. To capture the heterogeneity of fractures and vugs, macro fractures and vugs are represented explicitly with discontinuum model. The boundaries of macro vugs and macro fractures are discretized into several elements. Boundary element method is employed to handle flow into macro fractures and vugs. Finite difference method is applied to handle flow within macro fractures. The flow within macro vugs are assumed to be in pseudo-steady state.

With a simple discretization of the boundaries of macro vugs and macro fractures, the proposed model is shown to efficiently simulate the behavior of fractured carbonate reservoirs with heterogeneity. The computational accuracy is demonstrated using an analytical model. On the basis of the proposed model, the effect of heterogeneity of macro fractures and vugs on pressure transient behavior is analyzed. The results show that macro fractures and vugs cannot be handled with triple-continuum models analytically. There will be several "dips" on the derivative of pressure curve if macro vugs are discretely handled. And discretely handling the fractures and vugs will make the calculated dimensionless pressure and the derivative lower than calculated with tripe continuum models. Increasing the porosity of macro vugs, the pressure and the derivative will go down in the flow regimes dominated by macro vugs. The conductivity of macro fractures has a great impact on almost all the flow regimes except boundary dominated flow regimes.

The novelty of the new model is in the ability to model the transient behavior carbonate reservoirs with non-homogeneous fractures and vugs. Furthermore, it provides an efficient method for characterizing the heterogeneity of multi-scaled fractures and vugs.
Bongkot South Field Multilayer Reservoirs Retrograde Gas Condensate Model
Authors: Charoenniwesnukul Kritsada , Tan See Heow
Published: March 2018

BONGKOT South field is a multilayer retrograde gas condensate reservoirs field. The condensate –gas ratio (CGR) and condensate production forecasts are a major challenge of the field especially with monobore well completion which has limited zonal contribution data. This paper describes how the pressure-based CGR framework with integrated reservoir engineering data analysis is introduced to improve the forecast accuracy and enhance reservoir behavior intuition compared to the existing empirical methodology, CGR versus cumulative production.

The framework adopts the pressure-based CGR correlation which can model the retrograde condensation while maintaining simplicity for practical use. The proposed framework is split into 2 sections. The producing CGR parameters are established through history matching with actual production data using integrated information to enhance intuition on the CGR behavior which improve the accuracy of the CGR matching and forecast. The non-producing CGR is estimated using the established CGR correlations which were constructed based on the sample with CVD analysis and all single reservoir production data. The estimated CGR then apply to the simulator result to get the condensate forecast.

The forecasted field condensate rate during plateau period ranges between 8,000 to 11,000 STBD with single reservoir initial CGR and field average producing CGR varies in range of 15 – 120 STB/MMSCF and 17-28 STB/MMSCF respectively. Field blind test was also performed to validate the framework which shows mismatch in a total condensate volume of less than 3% over a total raw gas volume of 47 BSCF.

Results from various well-level CGR history match show different CGR decline behaviors of retrograde gas condensation and vaporization at lower reservoir pressure. The matching of such behavior can be achieved by the proposed framework which adopts pressure-based correlation while the existing production based correlation cannot.

The proposed framework has demonstrated that BONGKOT South operators can accurately predict well producing CGR for prudent reservoir management and development. Well-structured integrated data analysis during CGR history match provides better intuition into reservoir behavior which could guide engineer to better reservoir management decision. The established CGR trend could also be used by external optimizer module, e.g. LINOPT, as CGR decline input to better optimize the longer-term condensate recovery.
Geomechanical Stability and Overall System Behavior of Sloping Oceanic Accumulations of Hydrates Responding to Dissociation Stimuli
Authors: Moridis George J. , Queiruga Alejandro F. , Reagan Matthew T.
Published: March 2018

The objective of this study is to quantitatively assess the flow, thermal and geomechanical response of sloping oceanic accumulations of hydrates to stimuli that can induce dissociation, such as depressurization-induced gas production activities, with emphasis on the evaluation of the geomechanical stability of the well assembly and of the reservoir. Using numerical simulation, we analyze the coupled flow, thermal, thermodynamic, chemical and geomechanical processes involved in the response of sloping hydrate accumulations exposed to dissociation-inducing stimuli associated with depressurization-based activities for the production of gas from the hydrate-bearing sediments. The study includes a sensitivity analysis of the system behavior to the angle of the slope in order to determine its effect on the system behavior, and cover the system long-term behavior following the cessation of the stimuli.

We determine that gas production from hydrate-bearing media may cause subsidence that increases stresses along the well and reduces gas production, but does not appear to enhance the risk of hillslope stability while production continues. The risk of oceanic landslides increases slightly after the end of gas production as a result of the increase in the pressure in the reservoir where the hydrate (which imparts the bulk of mechanical strength to the unconsolidated oceanic sediments) is depleted or exhausted, but at no time is the system stability compromised for any slope angle.

The paper provides an integrated quantitative analysis of the coupled processes that are involved in dissociating hydrates using themost advanced simulators, and makes significant contributions to the evaluation and risk assessment of potential problems associated with future production from oceanic hydrate deposits, in addition to providing insights that may lead to mitigation of the problems.
New Intelligent Circulating Sub: Cutting-Edge Technology for a Challenging Deepwater Operation
Authors: Balachandran Arun , Eren Sinasi , Abdullah M Zulhilmi , Lai Harni Farihah Bt M Safari , Tahoun Ahmed
Published: March 2018

In any coring job, a common challenge is to maintain good hole cleaning while using a reduced flow rate to prevent washout of the core samples. Without proper hole cleaning, the hole is exposed to cuttings accumulation which may lead to major problems such as induced losses and stuck pipe case. To ensure adequate hole cleaning during the coring operation in a PETRONAS Carigali Sdn Bhd (PCSB) deepwater well, a new multi-cycle circulating sub, Intelligent Circulating while Drilling (iCWD) was utilized.

iCWD was developed primarily to perform losses treatment, isolate hole sections and improve hole cleaning while drilling without the need to pull out of hole, through surface activation. The tool is unique as it does not require a drop ball for activation and can function in a minimum flow rate environment. In a deepwater operation, this is especially useful as the time saved can be translated into significant cost savings. A further advantage with the elimination of ball activation is that the coring operation which also relies on drop ball mechanism is not compromised by ensuring operational efficiency and reducing the risk of losing the core during the recovery.
Smart Communicative Cement: A Step towards the Future of Zonal Isolation
Authors: Melo Ricardo C. B. , Eid Ramy
Published: March 2018

The oil and gas industry, by default, has been pretty conservative when it relates to innovation and drastic changes in mind-set. Mainly focused on the costly drilling and completion steps, some of the "smaller" services have been ignored. As such, we have decided to take a deeper look at nano and micro sensored technologies in other industries and potentially replicate some of this innovation, allowing the industry to take "a step" closer to smarter zonal isolation.

In general, the industry is quite aware of well integrity issues that we face. Be it immediate (whilst drilling/completing), within the life of production or even during the abandonment phase. There are many statistics proving that on a global scale, there is well integrity and sustained casing pressure issues on about 30-60% of all drilled wells. And we can confirm that a majority of these are directly related to well-cementing, creating an immense impact(s), that can negatively influence overall HSE, loss of potential reserves and bottom line dollar-amount.

The ability to take a close look at well cementing has only proven feasible in a laboratory environment, beyond that, the knowledge and prediction of the actual state of the zonal isolation has proven difficult, confusing or costly.

Regardless of the improved best practices, enhanced logging tools or state-of-the-art technological advances in chemicals/systems – we still seem to have that unanswered "gap" – on what actually happened, when it happened and how to avoid it in the future.

This paper describes the background, the thought process and the potential advantage of the proposed well monitoring ideology and current R&D efforts to improve the cement isolation measurements and real time monitoring of its properties and integrity during the well life and after its abandonment, by sensoring it and communicating back to surface.
Simulation-Based Design for Load-Out, Transportation, and Installation of Offshore Topside Modules Based on Flexible Multibody and Collision Dynamics
Authors: Ham Seung-Ho , Roh Myung-Il
Published: March 2018

After an offshore topside module is constructed on land, it is moved to the transportation barge by the load-out operation. Once the module arrives at the field, the floating crane is used to install the module on the sub-structure such as the jacket. For the safe operation, methods for the load-out, transportation, and installation should be analyzed in advance. Flexible multibody dynamics which is theoretically based on ANCF (Absolute Nodal Coordinate Formulation), and collision dynamics which is based on the non-interpenetration constraints are developed for physics-based simulation. By using the developed program, we analyzed dynamic effects during load-out, transportation, and installation of the topside module. For the load-out operation, MTPs (Modular Transporters) are modeled to lift the topside module and to move toward the transportation barge. The transportation barge and the quay are connected by link beams which are modeled by flexible bodies. Finally, during the load-out operation, dynamic loads on the deck and the link beams are calculated. Secondly, during the transportation, dynamic loads due to the wave-induced motion between the barge and the module due to sea fastening are calculated. Thirdly, the motion of the module lifted by the floating crane is checked according to the environmental conditions. As a result, we can evaluate safe environmental conditions and dynamic loads.
Lightning Phenomena - Offshore O&G Facilities Not Immune
Authors: Yasir Ir. M Faudzi b M , Taib M Akmal b A.
Published: March 2018

In general, based world lightning map, Malaysia geographic location is in high density of lightning activities with average of 50 lightning flashes/km square. Lightning has been recorded as one of the factors cause of asset damage, fire and even fatality at offshore installations. A review of applicable lightning protection system requirement for offshore facilities and installations are not fully addressed by codes and standards. This paper describes the underlying basis for guidance of Lightning Protection System Solutions (LPS) for offshore installation from lightning strikes, their induced effects and secondary electromagnetic effects.
Influence of Hydraulic Connection Between the Hydrate Reservoir and Surrounding Rock on the Methane Production
Authors: Xia Yingli , Xu Tianfu , Yuan Yilong , jin Guangrong , Xin Xin
Published: March 2018

Natural gas hydrates (NGH) are considered as a clean energy which widely spread in marine sediments and permafrost regions. Numerical simulation is a convenient and economic way to study methane production from reservoir, a lot of previous simulations treated the hydrate reservoir as homogeneous layers. However, the underground environment is tend to be complexity, there may be a high permeability tub connect reservoir with surrounding rock, and the water of surrounding rock may flow into reservoir along the connection tub. In order to explore the effects of hydraulic connection between reservoir and surrounding rock on gas production, a 3D geological model based on logging data of Shenhu Area of the South China Sea is established. The different strength of connections were realized by constructing varying spatial distributions of permeability and porosity. Results show that in regions of strong hydraulic connection, the hydrate dissociation rate is higher than weak hydraulic connection zones, the relative permeability of gas is higher tan water because the gas saturation is higher relatively So reservoir having strong connection with surrounding rock may not be poured with large amount of water.
Boundary Detection Ahead of the Bit – A Sensitivity Study of Extra Deep Azimuthal Resistivity
Authors: Larsen David Selvåg , Boesing David , Hartmann Andreas , Martakov Sergey , Mumtaz Asim , Skillings Jon , Vianna Armando
Published: March 2018

The opportunity to detect boundaries ahead of the bit has long been a desire within the oil and gas industry as it would allow precise geo-stopping prior to entering unwanted formations and/or fluids. There are solutions already available such as the use of seismic applications. However these are for use on a different resolution scale, the accuracy needed for geo-stopping within meters of a formation boundary is lacking.

Extra Deep Azimuthal Resistivity (EDAR) has been widely used for geosteering and landing applications around the world utilizing the common methodology of looking around and predicting ahead (see, for example, Larsen et. al., 2016). This methodology has been very efficient in a horizontal drilling environment with fairly low dipping layers, typically when incident angles do not exceed 10-15 degrees. In such wells, the environment ahead of the bit is generally not changing abruptly and therefore provides only a minor contribution to tool response compared to the volume around the tool. For higher incident angles, the zone of interest is likely to be ahead of the bit. Here traditional looking around the wellbore and predicting ahead is no longer sufficient. The steep angle of approaching beds requires sensitivity ahead of the bit in order to detect and predict upcoming resistivity boundaries.

In this paper we will study the extended capabilities of the interpretation method currently used only in high angle and horizontal (HA/HZ) well applications. We will present sensitivity analysis of the theoretical capability of detecting ahead of bit with the different key factors determining the capability, such as sensor placement behind bit, formation resistivity and incident angle.

The study will show that the application range of EDAR can be extended from the 15° incident angle range to up to 90° incident angle. The extension allows using the service for low angle geo-stopping applications. The analysis is performed on theoretical data as well as a case study from a well in the Middle East.
Enhancing Operations with Digital Technology to Bring Expertise to Site
Authors: Oliver Philip RF
Published: March 2018

The proposed paper will examine the potential of remote working technology to overcome operational challenges, reduce mobilisation costs and enable collaborative working in real-time by bringing expertise located anywhere in the world to local sites through digital technology. The potential benefits associated with the technology are compared to traditional techniques using recent case study examples.

Following the ‘technology readiness levels’ approach used by NASA and other organisations, Wood took a methodical but expeditious approach to developing and testing remote working technology. Supply chain expertise was leveraged to identify suitable technologies (hardware and software) that met the stringent requirements of deploying such technology to oil and gas facilities. Once these technologies had been selected, initial office-based tests were completed, followed by deployment onshore and offshore for piloting. Valuable lessons were learned from piloting, and the technology refined. The so-called ‘eXpert’ system is now internationally deployed to onshore and offshore facilities and successfully embedded in day-to-day business.

The paper will detail comparative case study examples where this technology has been successfully applied. Key learnings are summarised as follows: The technology has the potential to better connect the workforce with data, processes and systems necessary for safe, efficient and more effective execution. It improves collaboration between colleagues located at different sites, facilities or offices and reduces disconnects and misunderstandings that can occur in distributed organisations. The hardware and software package is easy to use, requiring minimal user training and leading to swift adoption.The remote working technology reduces execution times for specific work scopes by 60%-90%, and significantly reduced mobilisation costs. By reducing the need for personnel mobilisation by helicopter once the technology is deployed to site, travel emissions can also be minimised.The ability to involve experts from anywhere in the world, in real-time, allows faster issue resolution, reduction of risk to personnel safety and avoidance of mobilisation costs.

Remote sites present some of the greatest operational challenges in the energy industry. Effective communication between offices and worksites is crucial to identify issues, diagnose problems and develop solutions. Frequently, teams of engineering specialists and decision makers are required to reach a conclusion, however getting these experts to site can prove difficult in terms of logistics and cost. This technology brings the knowledge and expertise of colleagues to site in a direct, meaningful and efficient manner.