bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stop Erosion at the Well Head on Fractured Wells
Authors: Dreher Trina , Biley Alex , Tuckett Phillip 
Published: February 2015

Shale gas and other wells commonly suffer from severe erosion caused by frac sand and other residual solids that routinely appear at the well head and due to their abrasiveness can cause severe erosion in well-head equipment. In particular, it is not uncommon for well head let-down valves (flow line chokes) to require replacement after only a few months of service. In addition to erosion issues, the solids accumulate in downstream flow-lines and process equipment and cause blockages and other operation problems until the solids are removed.
This paper describes how Todd Energy stopped their well head sand accumulation and potential choke and pipework erosion by installing a custom designed Well Head Desander directly at the well head. Before installation Todd Energy had a duplex sand filter that required significant manual intervention to switch filters and empty.
Todd Energy approached Process Group for a long-term solution. Process Group custom designed a Well Head Desander to withstand the highly abrasive environment experienced at the well head so that the solids could be removed from the well fluids upstream of the flow-line choke valve. The custom designed package included a solids accumulation vessel to allow the captured solids to be collected and stored for batch dumping for disposal at regular intervals without stopping the gas flow from the well.
Plant data shows that the Well Head Desander Unit consistently removes frac sand (typically &gt;0.5 mm diameter) and other solids that are produced from the well. The Desander remains in continuous operation and biannual maintenance inspections confirm no erosion issues either in the Desander or with downstream equipment.
Horizontal Appraisal Well Placement Best Practices to Develop New Oil Prospects in Clastic Reservoir of Cuu Long Basin
Authors: Duy C.L. , Phong L.D. , Pottier X. , Anh T.T. , Permanasari D. , Yusuf N. , Thanh P.N. , Santoso G.I. , Fulton C.L. , Miguel D.L. 
Published: February 2015

Initially, oil production in the Cuu Long Prospect field within Cuu Long Basin, comes from the primary fractured basement reservoir target and secondary targets in the overlaying Oligocene and Lower Miocene thick clastic reservoirs. Currently the field production is rapidly declining over the years. To reverse the trend, minor reservoir pay zones in the Lower Miocene and Upper Oligocene have been identified as new oil prospects to be appraised and developed. This paper presents three case studies of drilling horizontal appraisal wells with fit-for-purpose geosteering methods to address the challenges in different oil prospects while reducing the number of pilot holes. The lessons learnt and best practices from the earlier drilled well such as well design, technology selection, real-time geosteering data monitoring and communication process were applied in the subsequent wells to improve the result.
Geostopping technique during landing with resistivity-at-the-bit measurement was used to land the well precisely at the top reservoir with minimum sand penetration and avoid pilot hole. Proactive well placement method using deep directional measurements and boundary mapping capability was applied to optimize the lateral length in the sand. An integrated project team involving geosteering specialists, sub-surface team, drilling engineers, and well-site personnel were brought together to ensure efficient decision making process. As a result, production rate from each of the three wells was more than 50% above the anticipated rate with zero water cut and the number of pilot holes was reduced to one out of potentially three. After these well placement successes, more horizontal wells targeting the undeveloped oil prospects are being planned for future development in the field.
High Strength Low Alloy Steel for HPHT Wells
Authors: Cancio Maria Jose , Giacomel Eloff Bruno , Kissner Gustavo , Valdez Martin , Vouilloz Francisco 
Published: February 2015

Carbon OCTG selection for HPHT wells has become a very challenging task for well design engineers, due to combination of high pressure with H2S requiring the use of high strength material to achieve the required safety factors avoiding Sulphide Stress Cracking (SSC) at the same time. This requirement prompted a study based on proprietary laboratory testing data in correlation with existing normative systems (API 5C3 and NACE 15156) for selection of high yield strength material in H2S HPHT wells.
With the information provided, the design engineer could better link existing normative systems with proprietary testing to define the best applicable window of high strength material in H2S wells for HPHT environments.
The paper summarizes the public studies done so far by the industry for the material selection of carbon OCTG for HPHT wells comparing with typical ISO 15156 guidelines. Detail explanations of the characteristics of each testing method are also included; the paper also contains additional study of high strength Sour Service material under different testing conditions to define the Sulphide Stress Cracking (SSC) behavior compared to ISO 15156 material selection guidelines. Two steel grades were tested: Sour Service 110ksi and Sour Service 125ksi, the SSC limits were defined using NACE TM0177 Tensile Tests and DCB Tests.
The paper intends to provide supplementary guidelines to help the well design engineer on the material selection process by expanding API 5C3 fracture mechanics formulas and concepts to address H2S selection concepts, explanation of NACE 15156 for high strength materials for Region 1–2–3, and clarification of different methods used to test materials with H2S as per NACE 15156.
Well Test Characterization of Naturally Fractured Vuggy Reservoirs, with a Global Optimization Method
Authors: Gomez S. , Camacho R. , Vasquez M. , Ramos G. , del Castillo N. , Mesejo J.A. 
Published: February 2015

Description:
The implementation of well testing models for dynamic characterization of Naturally Fractured Vuggy Reservoirs (NFVR) commonly involves inverse modeling. Thus, this work introduces new results about dynamic description of NFVR by using a triple porosity-dual permeability model. The values of the inter-porosity flow parameters, storativity ratios, permeability ratio between fractures and vugs, wellbore storage coefficient, skin and total permeability, are automatically identified in Laplace Space by using a gradient Newton-type global optimization method named The Tunneling. This method offers more reliable results in comparison to the local optimization methods commonly used in parameters estimations. Applications: The precision and computational efficiency of the Tunneling Method are demonstrated through the reliable results obtained from the automatic analysis of synthetic examples, where a very comprehensive and large set of synthetic noisy data was used. In all cases, the Tunneling Method obtained optimal solutions. Likewise, the analysis of several field well test data cases recorded in NFVR are shown to confirm the benefits above mentioned. Results, Observations, and Conclusions: The parameters determination in the problem here addressed is non-unique due to the ill-posedness problem forcing the local optimization methods to stop in non-optimal solutions. Likewise, local methods require many realizations until converge into an optimal solution. Thus, the superiority of the Tunneling Method for overcoming these challenges is demonstrated through the reliable analysis of several synthetic and field data cases. Performing the optimization in the Laplace space makes the procedure very efficient in computing time. To moderate or eliminate the non-uniqueness problem, information about storativity ratios obtained from core or well log analysis, can be used through the optimization process. Significance of Subject Matter: Currently, the well test data analysis is the only available procedure to estimate the dynamic parameters which characterize NFVRs. Likewise, the approach introduced in this work allows obtaining more reliable estimations of these parameters than local optimization methods.
Calculation and Analysis of Operability Envelopes for Deepwater Drilling Riser System
Authors: Chang Yuanjiang , Chen Guoming , Zhang Lei , Liu Xiuquan , Liu Kang 
Published: February 2015

This article focuses on calculation and analysis of operability envelopes for deepwater drilling risers system. A solver is developed by modeling the drilling riser as a finite number of beam elements based on finite element method, and it is capable of performing static analysis to obtain connection operability envelopes, hang off operability envelopes and running/retrieval operability envelopes of the drilling riser system.
A practical example of 1500m drilling riser system in south China sea is presented to illustrate the application of the proposed method.
The main conclusions are:By modeling the drilling riser as a finite number of beam elements, the stiffness matrix, mass matrix, damping matrix, and load matrix in the static and dynamic governing equation are derived. A solver is developed by using direct stiffness method to model and calculate the operability envelopes of deepwater drilling riser system.For connection operation, the normal drilling envelope is determined by the LFJ and UFJ angle limit. When surface velocity is small it is affected by LFJ angle, and it is affected by UFJ angle when surface velocity is large, while the connected non-drilling and disconnection envelopes are determined by allowable stress of the conductor and the bending capacity of the wellhead.Hang-off and deployment/retrieval operability envelopes of the drilling riser are determined by the heave RAO and wave height in the analysis. Generally, the hang-off envelope is larger than the deployment/retrieval envelope because of the BOP being involved in the analysis model, which increase the weight of the suspended riser column, and therefore increase the stress level of the riser during the heave motion of the vessel.
The related methods and conclusions have been put into drilling practice in south China sea in 2012, such as LW6-1-1, LH26-2-1, LH29-2-1 et al, those wells have been drilled successfully.
Successful Application of Platform Based Hydraulic Fracturing in High-Pressure/High-Temperature Tight Gas Sand in North Malay Basin
Authors: Abdelaziz Sherif , Ogueri Chidi , Armentrout Leslie Jane , Salleh Zaimi , Fernandez Mariano , Ward Brian 
Published: February 2015

During 2012, a single zone low permeability sand in an offshore HPHT gas well in the North Malay Basin was succesfully stimulated with hydraulic fracturing treatment utilizing skid mounted hysdraulic fracturing equipment from a supply vessel. This is the first offshore Malaysia HPHT frac operation peforming treatment from a supply vessel combining with the use of wellhead isolation tool and high temperature hydraulic fracturing fluid. Historical offshore Malaysia fracture treatments were performed with a drilling rig present.
The zone is a dry gas sandstone reservoir, 30% CO2, pore pressure of 0.87 psi/ft, fracure gradient of 0.92 psi/ft, permeability of 0.1-0.5 md and temperatures approaching 400 deg. F at 10,000ft TVDSS. The wellhead isolation tool, fracturing fluids were designed to safely establish the viability of HPHT hydraulic fracturing in the North Malaysia Joint Development Area.
The intent of the project was to provide proof of economic concept for development of single stacked tight gas sandstone pay intervals with platform based HPHT hydraulic fracturing through a combination of industry standard tchnologies used in other areas of the world, but rarely in Malaysia. Single zone production rates will allow economic development of additional low permeability zones in this well as well as additional wells that were previously deemed marginally economical to develop. While significant uncertainty still exists with regard to the drainage radius and productivity of the single zone, initial results have proven that hydraulic fracturing has connected multiple channels as seen on the log. This has improved the well capacity above productivity established through pre-frac well test and pressure buildup analysis.
Using Riser Technology in a Mooring Connector
Authors: Shield John 
Published: February 2015

With floating facilities increasing in size and tending to deeper and harsher locations; the mooring system design for environmental loading becomes ever more challenging. Higher average line tensions and fatigue loads can present uncertainty when assessing the capacity and qualification of the individual components.
In 2011 and in response to a client request, SRP investigated the availability of compact subsea mooring connectors with high bending and tension fatigue capacity. An absence of results led SRP to explore the potential of cross-pollinating the technology from deepwater drilling and production riser systems to mooring systems. The reasoning being that steel risers can be subject to very high combined loading; weight limitations and fatigue life often motivate the designer to use high strength steels and efficient, fatigue resistant connections.
This paper discusses the process and design considerations arising from adaptation of an existing and proven technology from one application (wellhead connectors) to a new application (subsea mooring connectors).
The design verification and qualification test program being carried out in 2012 and 2013 are detailed as an example of a design team's interpretation of riser, mooring and new technology standards. The results of the qualification test program, including static and fatigue testing, will also be presented as an indicator of technical success of the strategy.
Smart Gas Lift Valves Eliminate Multiple Slickline Trips in Gas Lift Operations
Authors: Xu Zhiyue , Richard Bennett M. , Kritzler James H. 
Published: February 2015

In many gas lift systems, dummy valves are loaded in side-pocket mandrels to isolate the annulus from the tubing where pressurization is required to test the tubing, test the annulus, set a hydraulic packer, or activate an isolation device. If the well then requires gas lift to unload the completion fluid or to assist the well to flow, slickline intervention would be required to remove the dummy valves and install the live gas lift string. This can be a long, cumbersome process and can pose risks to existing infrastructure. Production is also delayed while a new live valve unit is installed.
This paper presents a smart gas lift valve with disintegrable nanostructured composite material technology. The valve is installed in the well to function as a dummy valve during completion operations. It is converted from a dummy valve to a live valve through in-situ disintegration of the nanostructured composite plug in brine during the cleanup process. This eliminates multiple slickline trips or well intervention after the completion, and enables unloading and immediate production of these wells under optimized gas lift conditions.
The nanostructured composite material for the smart plug is lighter than aluminum but as strong as some mild steels. The smart plug has pressure rating of 5,000 psi or higher and will disintegrate in sea water within 12 to 50 hours, making it an ideal tool for offshore gas lift applications. So far, more than 1,000 gas lift valves equipped with disintegrable nanostructured composite plugs have been installed in gas lift wells producing offshore Southeast Asia. The nanostructured composite material, the valve design, the lab test data and a successful field case history will be presented.
Design, Fabrication, Delivery and Installation of TLP Tendons for South East Asia
Authors: Tekumalla Vithal R. , Yang CK 
Published: February 2015

The tendons are the critical components to keep TLP's on station. The design of the tendons takes into account platform weight, payload, displacement, required pre-tension, water depth, and the metocean data.
The tendons are long seam-welded tubulars joined together by girth welds. Tendon segments are joint together through threaded type intermediate connectors.
This paper examines the key aspects of the design of the TLP tendons to incorporate the effects of axial tension, hydrostatic collapse, bending, VIV, fatigue and fracture mechanics considerations. The interfaces to the TLP and the foundation pile will be detailed. The tension and bending loads of the tendons need to be monitored and the requirements of a robust tension monitoring system will be highlighted.
The key aspect of the fabrication of tendons including the weld procedure qualification, dimensional control/fit-up and NDT will be examined.
The transportation of tendons from the fabrication site to the installation site needs to address the aspects of logistics.
The requirements of the tendon installation will be examined with respect to the Tendon Support Buoys (TSB's). The TSB sizing and the design considerations will be examined for a typical TLP project.
The installation of tendons and the lock-off of TLP and tendons will be examined.
The Risk of Cryogenic Liquid Exposure Could Have Been a Show Stopper for FLNG (Floating Liquified Natural Gas Production and Storage) Projects : How Did the Industry Respond?
Authors: Wade Robin 
Published: February 2015

Liquid natural gas (LNG) at atmospheric pressures, remains as a liquid at -162°C. As the temperature increases, gas is evolved which is flammable and under certain mixtures with air is explosive when in the presence of an ignition source.
As designers have looked more at the risks posed by accidental release of Cryogenic Liquids onboard FLNG assets, it has become more apparent that the steel structures used for these facilities could be prone to brittle fracture. This could potentially lead to structural failure. If fire ensues soon after this cryogenic release then further escalation may occur, particularly if the passive fire protection does not function as expected.
The need for effective, tried and tested solutions to mitigate the risks posed by cryogenic liquid gas exposure was identified nearly 20 years ago. In the last 10 years, as the FLNG industry has accelerated, development has intensified for cryogenic spill protection (CSP) systems. Indeed construction of a leading FLNG asset was nearly stopped due to the lack of an effective solution. In response, the owner initiated studies into the most effective CSP materials to ensure progression of the project.
Since then, the industry has developed a better understanding of the risks posed by these LNG liquefaction assets and the consequences of not addressing these risks appropriately. Working closely with owners and design engineers to address these project specific risks and to develop robust solutions, has therefore become of paramount importance in developing this appropriate response.
This paper covers the initial requirements of protection against cryogenic spill. It considers the solutions developed to meet all the industry standards and describes those finally adopted by the first FLNGs under construction.
Design and Optimisation of Riser Configuration Base on the Project EnPing 24-2
Authors: Qi Xiaoliang , Xie Yi , Luo Yong , Zhu Weiquan , Gao Wei , Shen Hui 
Published: February 2015

En Ping 24–2 oil field is located in the Pearl River Mouth Basin in the South China Sea En Ping Sag, about 200 kilometers south of Hong Kong in water depth of about 86-96 m. The development of En Ping 24–2 oil field includes a newly built eight-legged drilling and production platform (DPP) with drilling rig, living quarters, sewage treatment facility, utility systems etc. and 2.2km apart, a newly build 150,000 DWT FPSO with power plant, oil and gas treatment facilities, utility system and living quarters etc. The FPSO is kept in station by a single point mooring system of internal turret type. The single point mooing system and riser system design for the FPSO become the key issues in the project because both systems have to face new challenges, such as shallow water depth, wild environments and high fluid pressure.
The paper presents the key design parameters of riser system, and addresses the evaluation of riser configurations to suit the Enping development. The evaluation focuses on the technical aspects in terms of system feasibility in the presence of harsh Enping environment. With respect to the suspended dynamic riser, several widely used configurations are evaluated and conduct the dynamic analysis in order to obtain riser responses such as effective tension, bend radius, contact clearance and seabed touch. Finally the key conclusions are reached.
Concept Evaluation of Concrete Floating Liquefied Natural Gas (FLNG)
Authors: Nezamian A. , Morgan P. 
Published: February 2015

The world has a quarter of its natural gas reserves (approximately 2 billion TCF) undeveloped or "Stranded" in offshore fields. Many gas fields were discovered decades ago, but until just recently these reserves were considered to be commercially and technically non-viable. Floating Liquefied Natural Gas, or FLNG, is now seen as a potentially viable solution to monetize these reserves. Technology developments in offshore Liquefied Natural Gas (LNG) liquefaction, containment and transfer have made offshore FLNG production commercially viable.
Although land-based LNG and offshore FPSOs are each successfully proven in operations, combining the two technologies into a FLNG is complicated and faces various technical challenges. These include safety, ship motion, topside processing, hull & containment, offloading, integration and operation. One of the critical aspects of a FLNG facility are the space constraints inherent in any floater.. A concrete hull structure can be a good answer to these challenges. It can provide a floater with larger deck area and high built-in load-bearing capacity. Concrete has excellent durability in marine environments, is not subject to fatigue, and offers far better insulation properties than steel.
This paper serves to highlight the benefits of a proposed concrete hull structure for FLNG production facility. The proposed concrete monohull concept benefits from significant flexibility with regards to topsides weight, equipment lay-out, simplification of operations and maintenance. Concrete has better fire resistance and corrosive resistance than steel structures and it is not susceptible to brittle fracture in the case of an LNG spill. These are considered to be of major importance for a FLNG production vessel. Building cost and time-scale are competitive.