bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of High Pressure High Temperature Condition on Well Design Development in Offshore Vietnam
Authors: Nguyen Truong H. , Bae Wisup , Hoang Nhan T.
Published: March 2016

Two fields are of Hai Thach and Moc Tinh of the Block 5.2 and Block 5.3 in offshore Vietnam have been discovered and exploited of the oil and gas production since the middle 90s. At this time, many contractors will be drilled wells development in the fields with 16 wells by using Tender Assist Drilling (TAD). There are high-temperature, high-pressure (HPHT) in the two fields with the bottom hole temperature range from 140 °C to 175 °C and the bottom hole pressure range from 10,000 psi to 11,500 psi. Through drilling and construction wells have been met many problems related to high pressure high temperature wells. Especially in the discovery well and appraisal wells in high pressure, high temperature reservoir (HPHT), There are a lot of incidents and operating technical problems during drilling. One of the problems during drilling is the gas influx into the wellbore due to the abnormal pore pressure, shallow gas, fluid loss due to the fracture pressure and pore pressure is very narrow margin, stuck down hole equipment in the wellbore due to high differential pressure between hydrostatic pressure and pore pressure and another problem was related to drilling mud and cement. At the stage of wells developemnt, the biggest challenges deal with design HPHT wells, which are required to high efficiency during drilling, construction wells and also require to bottom hole assembly working for a long time and a safe in the reservoir condition of high-pressure, high-temperature. Although the principal design HPHT wells was not different to principal conventional wells, but that well was still potentially risky and very challenging because of the strict design HPHT wells have not much been to choice materials and equipment. This study has been presented in detail the difficulties, solutions, and the effect of high –pressure, high-temperature on wells design development in HPHT conditions such as Casing design and selection grade, the differential pressure between reservoir pressure and fracture pressure is a narrow equivalent circulating density (ECD) management, laboratory the effect of temperature on rheological properties and model behavior of drilling fluid by using V35 fann, selection drilling mud in drilling wells HPHT conditions. Also techniques have been shown the lesson learned to drill and construct wells in high pressure, high temperature condition in offshore Viet Nam.
Technology Qualification for Small Diameter / Thickwall Reelable DSAWL Linepipe
Authors: Hall Stephen , Connelly Martin
Published: March 2016

Tough market conditions have seen the price of oil drop by circa 50% between mid 2014 and early 2015. This drop and subsequent uncertainty have seen the oil and gas industry concentrate on the cost of designing, installing and operating pipelines. A critical process for the industry is the procurement, manufacture and installation of appropriate linepipe. The method of installation is often dictated by the pipe size and the water depth that the pipe is to be laid in, however there are times when the choice of lay method is due to vessel availability and relative costs for each technique.

The industry regularly uses seamless pipe for installations by reel lay, however submerged arc welded linepipe (SAWL) has successfully been manufactured, installed and commissioned via this method and can realise significant cost reductions. SAWL material installed via the reel lay method has not been fully characterised to understand the material properties during the installation process and no formal characterisation program was undertaken for the successfully installed projects. To combat this lack of knowledge a technology qualification following the basic principles of DNV-RP-A203 was carried out to research the strain behaviour of pipes intended for reel-lay installation.

This paper outlines the technology qualification process used to characterise the behaviour of a 406.4mm OD × 22.2mm WT SAWL linepipe material that was subjected to full scale reeling simulation using a fixed end cantilever type reeling simulator. A comprehensive test program was developed and carried out to provide the characterisation of the linepipe base material and longitudinal weld, both before and after full scale simulated straining and ageing. The test program was set up to prove the material properties against DNV-OS-F101 Supplementary Requirement P and the results of these tests are presented hereafter.

The work presented in this paper will provide a basis for future investigations into the strain behaviour of pipes of different sizes and wall thicknesses or different straining cycles intended for reel-lay installation.
Single-Trip Multizone Sand-Control System Deployed on Hydraulic Workover Unit in Offshore Malaysia
Authors: Aripin Izura , Faisalluddin Teuku , Allapitchai M Shahril Majid , Hamidy Hudzaifah Zol , Ghazali Ikmal Hakim , Ab Latif Ahmad Syauki , Govinathan Kesavan , Priatna Oktaf
Published: March 2016

This paper presents a case history in which a single-trip multizone sand control system was successfully deployed in Malaysia using a hydraulic workover (HWO) unit. The well consists of two (2) zones which were both treated and completed in a single-trip gravel pack system. This paper discusses in detail the design selection and operation, which includes the challenges faced and mitigation to overcome the challenges. All operations involved were completed with a significant time and operational cost saving to the operator.

This was the first successful single-trip multizone installation using HWO globally. The sustained prolific oil production from this well affirms the success of the completion and gravel pack treatment method. These positive results highlight the importance of operator technical/operations personnel and service providers working as a team to develop the most appropriate solutions to the technical and operational challenges encountered.
New Development in Wireline Logging Under Activated Pressurised Mud-Cap Drilling Enabled Fractured Carbonates Evaluation
Authors: Kyi Ko Ko , Nathan Kumar , Haddad Sammy , Wa Wee Wei , Lee Andre Ooi Ken , Hui Gabriel Houng Nai
Published: March 2016

Pressurised Mud Cap Drilling (PMCD) is a variation of Managed Pressure Drilling (MPD), that involves drilling with no returns to surface and where an annular fluid column, assisted by surface pressure, is maintained above a formation that is capable of accepting fluid and cuttings. The application of this technology in drilling fractured reservoirs has been long established. However, formation evaluation techniques in such reservoirs are yet to be established due to the challenges that are associated with wireline logging in such a drilling environment.

Concerns related to total loss circulation, potential gas migration, and unsustainable fluid logistics have led to the perception that wireline logging operations during PMCD are impossible or logistically impractical. Apart from that, there are also concerns with regards to data quality due to the uncertainty of borehole conditions. Conveying wireline tools via drill pipe is also ruled out as the Rotating Control Device (RCD) sealing elements are not able to seal on wireline which is outside the drill pipe in Drill Pipe Conveyed logging system.

This work focuses on a new development that allows wireline logging under activated PMCD condition in wells drilled through carbonate gas reservoirs. The main challenges in evaluating such reservoirs are obtaining representative reservoir fluid samples and identifying fluid contacts needed for reserves booking. This paper will present the new developments and procedures on both operational and technical aspects. Field data and work flow will be used to demonstrate how the new development enabled the successful evaluation of fractured Pinnacle Reef carbonate reservoirs under total loss circulation and PMCD activation.

This paper discusses the operational details on wireline logging with activated PMCD, challenges encountered due to borehole conditions as well as acquisition results, lessons learnt, recommendations and conclusions.
Cased-Hole Reservoir Fluid and Rock Evaluation – What Can Be Done if This Was the Only Option Available?
Authors: Kyi K. , Haddad S. , Chouya S. , Ooi A.
Published: March 2016

Reservoir fluid characterisation in cased-hole is often challenging especially in thinly laminated and low permeability formations. Obtaining representative reservoir fluid samples is an important step in verifying fluid type and properties in addition to reserves booking requirements. Downhole fluid analysis (DFA) provides critical information on early confirmation of fluid type, while samples are used in the lab to provide PVT and physical properties of the reservoir fluid.

There are two (2) main ways to obtain fluid samples in cased-hole environment: either through subsurface sampling via wireline downhole sampling tool (WFT) or surface sampling via well testing full term (DST). Depending on the test objective, each method has its pros and cons. Subsurface sampling is normally performed in open hole. However, wellbore conditions and formation characteristics sometimes prohibit logging in open hole, hence sampling can only be performed in cased-hole. This also applies to wells which had been cased earlier than expected due to operational constraints. Conventional DST in cased-hole can be prohibitive due to many factors including cost especially if multiple layers have to be tested, not to mention environmental concerns restricting flaring.

This work depicts the successful fluid sampling strategy based on case studies in East Asia reservoirs. The paper will also discuss a proposed best practice that is supported by field data.
Quality Control for Interpreting Geophysicists of Common Image Gathers and the Velocity Model in Offshore Salt Dome Basins
Authors: MacShane Terry
Published: March 2016

Subsalt imaging is an important process for exploration of offshore basins. These salt basins present a technical challenge for present day imaging methods. Strong lateral velocity variations, irregular salt bodies, and subsalt structure imaging require quality control during the image processing phase. Methodologies and techniques are available for interpreting geophysicists to quality control prestack common image gathers (CIGs) and the velocity model (VM) in depth. The three dimensional (3D) SEG/EAGE Salt Model (Ober et al.,1996) is an ideal dataset to demonstrate the process because it was designed to contain major complex features common to offshore basins.

The SEG/EAGE C3 Narrow Angle Subset Salt Model is used to demonstrate the methodology employed for quality control, CIGs, and the interval velocities in depth used in imaging the data. The methodology involves residual move-out semblance panels based on RHO/percentage (RHO - Greek typography representing percent error) move-out trajectories. Velocity percentages are generated in the image domain to measure the curvature of reflection events on migrated offset image gathers. The curvature of offset image gathers depends strongly on the velocity used in the migration. If the velocity is correct, the reflection events on offset image gathers are horizontally aligned. If the velocity is incorrect, then the reflection events will show depth residual move-out.

Techniques are available for depth imaging that allows the interpreting geophysicist to respect the geologic concepts by controlling the quality control of the CIGs and the VM during the depth imaging processing phase. This includes salt dome basins where the depth imaging technology is most challenged.

Interpreting geophysicists are searching for solutions that balance the divide between turnkey on-time turnaround depth imaging processing and respect of the geology.
BOP Shearing: FEA Modelling with Void Coalescence Ductile Fracture Theory
Authors: (Ted) Cole Edward H.
Published: March 2016

Blow-out preventer (BOP) shearing is a critical element of well control affecting both safety and environment. BOP shear testing traditionally shows a wide range of actual pressures to shear for any given tubular size and grade. Universal predictor formulas are often dramatically conservative in order to cover outlier data in shear testing. The drilling industry needs improved theoretical understanding of the BOP shearing process. A correct constitutive model for material behavior is critical for theoretical modeling. The Extended Mohr-Coulomb (EMC) model is viable in studies of ductile fracture, but determination of the EMC coefficients for particular material can involve extensive specialized material testing. Theoretical work has focused on developing EMC coefficients with an intermediate level of theory involving cell modeling of void coalescence for high triaxiality (tensile dominated) stress conditions. With this method, EMC coefficients can be determined from standard material tensile tests. This method shows promise for practical application to prediction of BOP shearing of drilling and completions tubulars.

Material tests were performed on drill pipe remnants after full-scale BOP shearing tests were performed. This material test data was used with void coalescence theory to determine ECM coefficients which were then used in Finite Element Analysis (FEA) simulations of the full-scale BOP shears. The FEA used an element death technique to simulate pipe fracture and crack growth. In this initial phase of study, comparisons of theoretical predictions of maximum shearing force were mixed, but much was learned about the mechanism of BOP pipe fracture. Variation in properties from multiple material specimens taken from both adjacent locations and remote locations of the same drill pipes also indicated a larger than expected local variation in material properties. This fact, along with comprehension from the FEA that only a small zone of the drill pipe is involved in the shear initiation process suggests the cause of the wide variation which is observed in full-scale BOP shearing even when multiple shears are performed on a single pipe. Extensions of this study plan to investigate sensitivity of the theoretical model to characterization of the plastic strain hardening model, and will explore the use of a new void coalescence theory which has been developed for low-triaxiality (shear and compression dominated) ductile failure.
Multivariable Threshold-Processing Workflow Provides Comprehensive Cement Evaluation for Effective Well-Barrier Assessment in Plug and Abandonment Applications
Authors: Imrie Andrew , Heeley Beverley , Foianini Ivo
Published: March 2016

This paper presents a cement-evaluation workflow that encompasses the use of multiple measurement thresholds, proving that data processing with the use of logical discriminators can determine true cement-bond conditions with the use of conventional diagnostic tools.

The algorithm filters raw and derivative acoustic data through various predetermined thresholds to discriminate well intervals that possess proper cement bond and vertical coverage. Should data associated with a well interval pass through all the chosen logical filters, the interval is flagged as having the necessary cement presence and bond to be considered an isolating annular barrier. The logical thresholds are operator-defined, enabling a customizable assessment of any cement type, regardless of operator standards, legal codes, or environmental regulations.

The service was recently implemented in various wells where the customer required a decisive assessment to determine if a cement bond was minimally present prior to proceeding with abandonment. Their previous experiences with well-integrity diagnostics had resulted in contradictory information, requiring additional intervention work to help ensure zonal isolation. The interpretation workflow was able to indicate the presence of a minimum 11 ft of continuous cement and 100 ft of total cement behind the 7 5/8-in. OD production casing, which was one of the customer's well-integrity standards. The processed acoustic response, acquired with a cement-bond log tool and ultrasonic scanner, is presented in binary form, which clearly distinguished several intervals where annular cement complied with the various technical and legal variables that the client adopted.

By eliminating the inconclusive nature inherent to cement evaluation, the new interpretation solution can rapidly serve operators with a simplified result, enabling faster decision making to determine whether or not remedial work is required. This routine can be especially valuable to asset decommissioning and new well drilling, where more assertive decisions regarding well-barrier integrity can result in operational efficiencies.
Advanced Cryogenic Structural Collapse Analysis CSCA - Part II: Cryogenic Flow and Structural Cooling
Authors: Pujol Joaquim , Kleiveland Rune N. , Lileheie Nils. I. , Holmas Tore , Amdahl Jorgen
Published: March 2016

Floating Liquefied Natural Gas (FLNG) is the term used for producing, processing, storing and offloading natural gas at sea. Cryogenic hazards represent a significant safety risk for assets and personnel, but current methods to estimate the cryogenic risks are still coarse.

Lloyd's Register (LR) has taken the initiative to develop a more advanced approach to Cryogenic Risk and Cryogenic Spill Protection (CSP) Optimization: the Advanced Cryogenic Structural Collapse Analysis (CSCA). The CSCA is a numerical approach that fully couples 3D CFD cryogenic flow modelling with 3D FEM thermal and structural response to prevent structural escalation.

This paper describes the first and second step of the CSCA: the cryogenic flow modelling with CFD and the thermal response of the load bearing structures with FEM to one representative cryogenic load. The CFD solver used is KFX-LNG by ComputIT and the thermal code is FAHTS by USFOS.

The capabilities, tests and state-of-the-art of KFX™-LNG for cryogenic flow modelling are discussed. The paper also describes the capabilities, tests and state-of-the-art of FAHTS for thermal response of main load bearing structures. The paper then concludes with a cryogenic analysis with KFX-LNG and FAHTS of an accidental LNG leak on a realistic offshore module. The CSCA numerical approach to solve the potential structural collapse of the offshore module (non-linear stress-strain analysis) is not described here.
Evaluating Sand Screen Performance Using Improved Sand Retention Test and Numerical Modelling
Authors: Wu B. , Choi S. K. , Feng Y. , Denke R. , Barton T. , Wong C. Y. , Boulanger J. , Yang W. , Lim S. , Zamberi M. , Shaffee S. , Jadid M. B. , Johar Z. , Madon B. B.
Published: March 2016

Sand retention tests have often been used to select optimal screen aperture for standalone sand screen applications. The purpose is to select a sand screen that maximizes hydrocarbon production and minimizes sand production. There are two types of sand retention tests currently used in the industry, i.e., slurry and prepack sand retention tests. The former aims to simulate gradual sand production condition with an open annulus between the sandface and the screen, and the latter to simulate the condition where no such annulus exists. There are, however, no agreed industry standards on how sand retention tests should be performed and test results interpreted.

This paper presents a combined experimental and numerical modelling study on sand screen performance. The objective is to develop an improved methodology for optimal sand screen aperture selection by addressing some of the limitations presented in the existing sand retention tests. A new sand retention test facility has been developed at CSIRO, incorporating a number of improvements into the design and experimental procedure. A key component of the improvements is the ability to separately measure retained screen permeability and sand pack permeability. Correlations have been developed between sand screen performance and key parameters of the sands and screen based on a large number of sand slurry retention tests. Furthermore, the sand retention process was simulated numerically using a 3D fully coupled Discrete Element (DEM) – Computational Fluid Dynamics (CFD) model. Parametric studies have been conducted to assess screen performance and to gain a better understanding of sand retention and production mechanisms.
Sub-Surface Safety Valve (SSSV) Erosion Assessment in HPHT Gas Field - A Case Study
Authors: Toldo Benni , Shuttleworth Andrew , Zabelina Polina
Published: March 2016

The objective of this paper is to discuss a methodology used to assess the erosion risk of well equipment in an HPHT gas field offshore Egypt. Raven is an offshore subsea HPHT wet gas field located in the West Nile Delta region. During the well design phase a few challenges were faced with the erosion assessment of the Sub-Surface Safety Valve (SSSV).

A preliminary erosion study assuming dry gas with no liquids in the tubing showed excessive erosion rates and the potential outcome of having to choke back production. The analysis was performed using different erosion models and empirical formulas and all gave comparable results.

In high rate gas wells the worst case for erosion is in dry gas conditions due to the direct impingement of the produced solids particles with the metal, as there is no liquid to provide ‘cushion’ effect. The metal loss is greatly reduced if there is a liquid film present on the internal surface of the completion equipment, effectively dampening the impact energy of the solid particles with the metal. Produced formation water can help mitigate the erosion rate however it is anticipated that it will be produced only late in field life. The worst case for erosion is experienced at the end-of-plateau conditions, years before water breakthrough.

The next step of the study was then to estimate the amount of condensate dropout in the tubing as a mean of controlling the metal loss. The relatively low expected Condensate Gas Ratio (CGR) of the reservoir fluid implied that the predominant flow regime within the tubing would either be mist or annular flow, but to determine the rate of metal loss it was necessary to quantify the relative velocities of the liquid and gas phases. A black oil retrograde condensate PVT model was generated from a tuned Equation of State (EoS) model and was used in a nodal analysis tool to estimate liquid dropout across the tubing length. The erosion assessment was re-evaluated this time considering the liquid dropout at the SSSV (process conditions) showing an acceptable erosion rate.

This approach can be applied on many high rate gas fields where erosion rate is a threat that could impact the production rates. In our case, demonstrating the presence and quantifying the amount of liquid film in the tubing and the positive effect on reducing erosion, helped define appropriate operating envelopes to deliver the required well potentials.
Effect of Drilling Fluid on Rock Mechanical Properties at Near-Drilling Conditions: An Implication of Fluid Design on Wellbore Stability
Authors: Yadav Prahlad Kumar , Ali Syed Shujath , Tawat Najeeb Ahmed Al , Dhamen Ali Abdullah Al , Jin Guodong
Published: March 2016

Selecting a drilling fluid from the learnings from conventional reservoirs can be a wrong choice when it is used for unconventional formations. Drilling fluid has a chemo-mechanical effect on the reservoir rock during exposure time; this interaction can be abrupt or imperceptible depending on minerals comprising the rock matrix and their chemical sensitivity to the fluid composition. Improper selection of drilling fluid may cause strong shale-fluid interaction and thus result in wellbore instability. This paper presents a comprehensive experimental study examining the effect of various drilling fluids on the mechanical properties of conventional and unconventional rock samples.

Four drilling fluids with varying additives are selected to contact and saturate rock samples at the temperature of 230°F for 16 or 24 hours: Three of them are water-based muds (WBM) and the other one is an oil-based mud (OBM). Rock samples used are from the Berea sandstone, Mancos and Eagle Ford shale formations. For each type of rock, one plug is tested without contacting any drilling fluid and is used as a reference of geomechanical properties. Other samples are contacted and saturated with other drilling fluids before their geomechanical testing. A fluid-saturating process is conducted at a pressurized aging cell. Mechanical testing is performed in a servo-controlled triaxial apparatus in which samples are deformed at a constant confining pressure of 10 MPa and the drained condition.

Experimental results show that drilling fluids have a negligible effect on the peak strength and Young's moduli of Berea sandstone. However, the peak strength of Mancos shales decreases dramatically while their Young's moduli change randomly. For Eagle Ford shales, fluids reduce both peak strength and Young's moduli. For all samples tested, their Poisson's ratios increase after samples are saturated with fluids. Compared to WBM, it is observed that OBM preserves the mechanical properties of Mancos shales much better. After optimizing the design of one high-performance water-based mud (HPWBM1), the new fluid (HPWBM2) has an improved performance (similar to OBM) in preserving shale geomechanical properties.
Comparative Study of Gas to Liquids (GTL) Technology for Monetising Marginal Reserves and Wasted Flared Gas
Authors: Menon Manu
Published: March 2016

This paper provides a comparative study between gas to liquids (GTL) technologies that are targeted at capturing stranded and associated gas. As a result, it should act as a preliminary guide to oil and gas operators who intend to gain an overview of available miniaturised technologies. Subsequently, this would assist operators with decision making regarding potential monetization of stranded and associated gas available in their oilfields. The miniaturised GTL technologies will be compared by collating data published from the companies' website, online publications and journals as well as correspondence between the author and company representatives. The paper examines intrinsic differences between the fundamental chemistry between technologies used to produce synthesis gas in terms of steam methane reforming, autothermal reforming and partial oxidation. Figures shall be used to compare the maturity and commercial readiness of technologies provided by GTL companies. Maturity and commercial readiness will be based on the availability of a pilot plant showcase and activity of the companies in presenting their technology at oil and gas conferences. In addition, the status of the respective companies and their current affiliates will be described. In summary, this paper provides a list of players in the GTL atmosphere who are actively seeking to innovate the GTL process to make it feasible to handle stranded and associated gas; i.e. monetizing small volumes of gas that would otherwise be overlooked or flared.
Combination of Innovative Multi Zone Single Trip Gravel Pack System Aids Cutting Completion Cost in Mahakam Block
Authors: Muryanto B. , Wahyudhi F. , Caillon D. , Styward B. , Sinaga H. A. , Wijaya R. , Risatrio A. A. , Anashkin A. , Jatikusuma R. , Maharanoe M. I.
Published: March 2016

More than 1000 gravel pack zones have been completed using Multi Zone Single Trip Gravel Pack (MZ-STGP) system in Mahakam block, East Kalimantan, Indonesia. The system has been proven to be cost effective solution to produce multi layered sand prone reservoirs. The current challenge is to further cutting completion cost to produce marginal reservoirs which can not be produced even using already established MZ-STGP.

Three areas of improvement are explored based on database of more than 250 wells. The first one is reducing gravel pack pumping operation time. The second option is to extend total gross length of MZ-STGP to complete more reservoirs. Another improvement to be looked at is to replace Gravel Pack (GP) with alternative sand control solution.

Using innovative design of shunt tube, MZ-STGP wells can be completed with more than 700 m gross interval and simultaneously pumping several zones. At the same time, extensive optimizations have been done to extend length coverage of MZ-STGP. One of the improvements is by using fit for purpose single string design. The other alternative is to use alternative sand control methods. Encouraging results were gathered from initial production test from pilot wells. To date, four wells were completed with ceramic screen completion and one well with shaped memory polymer.

The success of initial pilot gives a good base for improving and confirming reduction of completion cost. Industrialization of combined solutions may lead to access to reservoirs previously considered as non economical.
Optimization of Shutdown Valve Weight and Size
Authors: Nair Suresh
Published: March 2016

Automatic Shutdown Valve also referred to as, Actuated Shutdown Valve is designed for automated protection to safeguard personnel, environment and to control hazardous or abnormal operations.

Ball valves are widely used for Shutdown service, fitted with quarter turn actuator. Pneumatic Scotch-Yoke type is the preferred actuator design with single acting and spring return type configurations to meet fail-safe conditions and safety critical functions.

The article stated hereby as Shutdown Valve is a general term used for the complete assembly inclusive of Valve coupled with Actuator for shutdown service. Optimization of the assembly is examined in this article through significiant emphasis on the coupled automatic actuator.

Through marginal changes in the pneumatic system design and usage of appropriate variable factors in actuator torque profile, aims to evaluate optimization techniques for shutdown valve actuator weight and size / dimensions.

An analysis on actuator weight and size affected through actuator design factor is carried out in this article. The details are extended to actuator sizing data, illustrations and comparisons, to outline the approaches currently followed and the possible area of improvement in the pneumatic design and actuator selection.

The paper assesses the advantages on actuators types and the variance between design methods. In addition, the article analyses the air supply to actuator and feasibility for the improvement in design.
Challenges Associated with Developing Foamers for Subsea Producing Fields with Glycol Regeneration
Authors: Suandi Lizman Mat , McRae Alex
Published: March 2016

This paper describes the challenges associated with chemical treatment of liquid loaded, gas condensate in subsea pipelines and the importance, of not only performance but also stability in glycol regeneration processes downstream. Untreated field produced fluids were used in all foamer production formulation and testing. Standard column sparged testing was used as initial screening, followed by a modified method to mimic the response to increase in dosage and concentration of chemical in the fluids to be unloaded. The product was designed to be compatible with capillary string for subsea injection, and with the glycol carrier fluids that it would be injected with. It also had to be thermally stable to withstand the glycol regeneration process that the fluids passed through on the topside process after the pipeline reaches surface. Product formulation on field fluids resulted in a chemical foamer that resulted in thick foam but with quick collapse time and half-life, which limits any possible carry over into the production process. The product was found to be thermally stable at 170°C and would not cause any contamination of the glycol regeneration process. Production application in the field is expected in second quarter of 2016, and all results will be shared in this paper. Product was formulated with blend of sulphonated quaternary ammonium compounds and polymers, in conjunction with high boiling point glycols to withstand high temperatures and function as good foaming agents in mixed water/hydrocarbon systems.
Reduce Project and Life Cycle Cost with TCP Flowline
Authors: Steuten Bart , Onna Martin van
Published: March 2016

Thermoplastic Composite Pipe (TCP) is a spoolable, fully bonded, thermoplastic pipe with glass or carbon fibre reinforcements. The bonded composite pipe has a solid wall, like steel pipe and is able to cope with corrosive environments without being affected. For its lightweight and collapse resistance, TCP is most often associated with deep water. However, it is the combination of the solid wall, spoolability and no corrosion what makes TCP very attractive for production flowline applications, also in shallow water.

Leading TCP manufacturer Airborne Oil & Gas has qualified TCP for a number of applications and companies and has successfully delivered multiple TCP projects. In support of the market implementation, and as a the result of a broad industry JIP with participation of 19 companies, DNVGL has issued a Recommended Practice for Flexible Thermoplastic Composite Pipe. Furthermore, API has established a committee to draft a recommended practice for bonded composite pipe for offshore applications, API 17Z.

The spoolability and the ability to manufacture TCP in long lengths reduces installation cost significantly. This paper describes a shallow water reel laying installation method for TCP and compares the typical project scope with other pipeline options. With corrosion being a major cost driver for operational cost, thanks to the lack of corrosion of TCP, the operational cost for the operator are also reduced significantly in comparison to rigid steel pipe.

Reducing both installation and operational cost offsets the higher material cost for TCP compared to steel pipe and results in a total reduced life-cycle cost of the flowline.
Concept Stage Site Assessments, Deepwater Development Risks, and Long-Term Value Preservation: Why Getting it Right the First Time is More Important Than Ever
Authors: Haneberg William C. , Campbell Kerry J. , Mackenzie Brian
Published: March 2016

Concept stage site assessments based on exploration 3D seismic data and other existing information are critical elements in the deepwater field development sequence. Such assessments help create value by defining site conditions and geohazards that may eventually constrain development, which in turn allows risks to be properly evaluated before significant development decisions are made. Several decades of deepwater development consulting experience, however, have shown that—despite their great value—concept stage site assessments are often not undertaken because 1) decision makers do not know that the assessments should or could be performed, or 2) there is a misconception that money can be saved by skipping steps or executing steps out of sequence in order to fast-track a development. As shown by way of two examples, decisions not to perform concept stage site assessments—even in cases where the necessary data are already available and free of additional cost—can be expensive mistakes that result in project delays if surveys have to be repeated or field layouts changed. In other words, human decision makers become significant and—unlike those associated with geohazards—largely indefinable elements of risk if short-term savings accrued by doing it wrong the first time are prioritized while the potentially more significant costs of having to do it right the second time are marginalized.
The Vertical Tension Anode System: A Cost-Effective Option for Fixed Offshore Platform Cathodic Protection Life Extensions
Authors: Carpenter Ben , Nomanbhoy Juzer
Published: March 2016

The Vertical Tension Anode System (VTA) is an Impressed Current Cathodic Protection (ICCP) system that can be installed without divers or ROV equipment. It is a cost-effective option for the life extension of brown field offshore structures whose original aluminum anodes are depleted. In June of 2013 four large offshore platforms in the Gulf of Mexico, all with low cathodic protection potentials due to depleted aluminum anodes, had VTA systems installed in a single, continuous construction schedule. These structures were in water depths between 68 and 80 meters (225 and 262 feet), with an average cathodic protection current requirement of 1000 amps. Total installation time was only twenty-three days, which included loading, mobilization to each structure, and offloading at the end of the job. Each platform required two VTAs, thus less than three days per VTA was required. A topside crew of 10 men, an inspector, and an experienced VTA installation technician made up the installation crew. The equipment included just a few air winches, a large air compressor, a welding machine, special VTA deployment spool racks, and miscellaneous hand tools. Since the entire system was installed from topside the client was provided great savings over sled type impressed current installations or aluminum anode type systems.
Wave Seed Selection on Irregular Wave Analyses and the Max Extreme Time Windows from 3 Hours Simulations
Authors: Suwarno Gunawan , Lee Choon Hua
Published: March 2016

The recent trends in pipeline installation analyses are using irregular wave spectra because it produces more realistic results, especially when fatigue analyses are required. Although, by adopting irregular wave model analyses will consume more time to produce results than regular wave model. However, with current available computing technology, the required computing time is just becoming lesser and no longer a limitation issue.

Irregular Wave Analyses will require Wave realization which relies on wave Seeds selection. Wave Seed is a random number where every seed number will give different maximum wave rise, maximum wave fall and also the time windows when the peak is occurred in the 3hrs simulations.

The key question is about, How to choose the "correct" wave Seed number? There are few suggestions to address this subject. It is either to pick up several seeds randomly, and choose the average of those results; or choose several random Seeds, up to 20 seeds in fitting those results to Gumbel Distribution to get the extreme maxima, or fitting those results to Weibull distribution to compute the extreme maxima.

This paper will discuss about the effect of wave seed selection base on irregular wave analyses (i.e. maximum wave extreme rise and fall), vessel motions (i.e. Maximum/Minimum Vessel heave, Pitch, Roll at Motion, velocity and acceleration) and also during Pipeline installation analyses. The result discussion is focused on J-lay Installation analyses using reel-lay vessel. On each of the analyses (Wave, Motions and Pipeline Installation) 3hrs simulation is carried out. In the conclusion, Time windows from the motion analyses and Installation Analyses will be compared to show which motion characteristic will influence the Pipelay parameters the most. And based on those time windows, Short simulation analyses will be performed to verify the accuracy of the selected time windows.
Novel Use of Resin Technology for Offshore Pilot Hole Abandonment
Authors: Pardeshi M. , Wilke A. , Jones P. J. , Gillies J. , Jedlitschka V.
Published: March 2016

An operator in the Taranaki Basin, offshore New Zealand, employed resin sealant technology in a recent shelf development to isolate the vertical pilot hole from the production formations. This paper details the success of the operation in which the resin sealant was placed in the pilot hole through the drilling bottomhole assembly (BHA) by using a pump and pull technique without needing to trip out to change the BHA, resulting in time and cost savings.

The operator drilled a pilot hole to gather petrophysical data to assess the geological model and formation pressures of the field. Afterward, the pilot hole was to be permanently abandoned, blocking any flow between the pilot hole and the horizontal production wellbore. Conventional practice would be to pull the drilling BHA to surface and then trip in with a dedicated cementing work string to abandon the pilot hole with a series of cement plugs. In this case, abandonment was executed by placing resin sealant in the pilot hole through the drilling BHA without tripping out and changing the BHA.

The dynamic tools on the BHA were unaffected by the resin and drilling continued without incident. When the BHA was pulled out and examined, there was no evidence of the resin within the drilling/placement BHA string. The operator commenced drilling in the main wellbore, and set a 9 5/8-in casing at 3055 m measured depth (MD). The well has since been completed, and the lack of any observed pressure in the production string annulus indicates that full isolation was achieved in both the pilot and main production wellbores. This approach has since been adopted by the operator as the standard procedure for the remainder of the wells in the program.

Using resin technology to abandon a pilot hole through the drilling BHA allowed the operator to avoid tripping in with a dedicated cementing work string, resulting in reduction of both time and overall cost.
Safe LNG Loading of Conventional LNG Carriers in Severe Open Sea Environments
Authors: Paquet S. , Lamourette C. , Auburtin E. , Hellesmark S. B. , Thorsen T. B.
Published: March 2016

FLNG (Floating Liquefied Natural Gas) as a means of monetizing offshore gas is now a reality with Technip being involved in the first two major projects. Both these projects incorporate side-by-side offloading of LNG from the FLNG to the LNGC (LNG Carrier) using loading arm technology. As FLNGs move into more severe environments, the side-by-side operation is no longer applicable and a solution providing greater environmental thresholds is required. Several tandem LNG offloading systems are proposed by the industry. They provide great safety separation distance between the vessels and high environmental thresholds, but they require the use of a dedicated LNGC fleet with Bow Loading Systems or the deployment of at least three floating LNG flexible lines of sufficient length, more than 300 meters, to reach the midship manifold of conventional LNGCs.

Since early 2015, Technip has worked with HiLoad LNG AS to develop a LNG loading system that combines the advantages of tandem stern-to-bow and side-by-side offloading solutions. The system is based on already proven or qualified technologies, allows a vessel separation greater than 100 m, high environmental thresholds and minimum length of LNG transfer lines without any modification to the LNGC. The system uses the HiLoad LNG DP (dynamically positioned) vessel for the position keeping of the LNGC parallel to the FLNG and Technip's cryogenic flexible pipes for the transfer of LNG and vapor.

The main focus areas in the studies have been the risk assessment of the parallel loading configuration and the assessment of the DP station keeping capabilities within predefined operating sectors, with the system being exposed to both steady and dynamic/changing environmental conditions. Black-out scenarios have also been investigated as part of the simulation work. The HiLoad DP system was able to keep the LNGC inside a tight operating ‘green' envelope during all investigated challenging metocean conditions. The HiLoad LNG Parallel Loading System has been concluded as a feasible, well suited solution, enabling a safe and robust LNG loading method with use of conventional LNGCs.
Active Heated Pipe Technologies for Field Development Optimisation
Authors: Louvet E , Giraudbit S. , Seguin B. , Sathananthan R.
Published: March 2016

Active heated pipe technologies are enabling solutions for field developments allowing cost effective management of flow assurance to overcome specific challenges like longer distance tie-backs and greater water depths.

This paper introduces wax and hydrate issues and conventional approaches to manage them. It highlights the need for other approaches, such as active heating technologies, to reach longer tie-back distances and greater water depths.

It reviews Direct Electrical Heating (DEH), Electrically Heat-Traced Flowline (EHTF), and active heated flowline bundles comprising Hot Water Circulation (HWC) and EHTF in bundle. A general presentation of these systems is given, including design, fabrication and installation methods, as well as the maturity of the technology. Typical field architecture is proposed to illustrate the benefits of each active heating technology in terms of field development optimisation.

This paper provides global information and an understanding of different available solutions for active heating pipeline systems, with technical and economic perspectives, and concludes with elements for selection of optimised field architecture.

Wet DEH is a field proven technology with large track record that has already been installed on a 43km pipeline in 1070m water depth. It fits production fields not requiring high thermal insulation performances and thus allowing wet insulated pipe (U-Value =2W/m2.K). The system presents high electrical power requirement (50-150W/m). Therefore, infrastructure capacities in terms of footprint and power supply available have to be checked against specific project power requirements.

EHTF fits production fields requiring high thermal insulation performance provided by Pipe-in-pipe (down to U-Value < 0.5W/m2.K). Thanks to its high efficiency, the system has low power requirement (typically below 50W/m). Therefore, it can also be an alternative to DEH when topsides capacities cannot meet footprint and power supply requirements. Pipeline heat tracing is a known technology for onshore plants and by extension applicable for subsea applications. The implementation of EHTF is completing qualification of this technology for deepwater applications.

HWC within bundle is a field proven technology. It fits production fields requiring high thermal insulation performance provided by bundle arrangement (down to U-Value < 0.5W/m2.K). The technology requires power and equipment to heat water thus impacting topsides space. These requirements vary considering project specific needs and selection of direct or indirect heating. For example, re-use of the produced water as an indirect heating medium can highly limit required power generation.