bluuebunny/crossref_metadata_2025 huggingface dataset:
Application and Study of Permeability Testing Method of High Rank Coal Bed Methane
Authors: Zha X. , Lai X. , Zhao X. , Feng J. , Huang W. , Hui B.
Published: February 2015

Because of the four characteristics: low gas saturation, weak permeability, low reservoir pressure, and scarce resource abundance of CBM(coalbed methane)in China, the mining of CBM still has not good progress. The permeability of coal is usually less than 1mD (1mD=1×10−3μm2), and is general 0.001~0.1mD in high rank coal reservoirs which are existed widely in China. Under super low permeability conditions, production practice of coal bed adsorption methane is obviously different from conventional gas. Different permeability of coal bed generates a considerable variance in the optimum condition for drilling and well completion and development technology. Therefore, permeability determination plays a very important role in CBM development. When the coal core permeability is lower than 0.01mD, conventional permeability test method is difficult to obtain accurate permeability measurement values. A permeability measuring instrument basing on the principle of pressure oscillation is designed in view of this difficulty. The coal sample is first stabilized at certain pore pressure, then a specific sinusoidal pressure wave is applied to the upstream side of the sample, and the pressure response at the downstream side is recorded. Permeability is deduced from the attenuation and phase variation of the downstream signal as it pass through a sample under test. The diameter range of sample is 50±0.5mm, which can better react the heterogeneous reservoir characteristics. The instrument which is equipped with drilling fluid pollution system can simulate downhole conditions and changes in permeability by drilling fluid pollution. The lowest permeability could reach 1×10−7mD. The permeability of coal samples which are from Sihe /Shanxi Province, Wu'an /Hebei province and Gerick coal mine is measured with this instrument. Multiple experiment results show that the instrument can be in accordance with repeatability accuracy requirement of permeability test in super low permeability coal reservoir. The study provides the basis for the reserves evaluation and drilling and well completion technological design.
Finite Element Studies for Assessment of Collapse Modelling Methodologies for Unbonded Flexible Pipes
Authors: Edmans Ben
Published: February 2015

Unbonded flexible pipes are a key technology in subsea production systems.

Procedures for the assessment of dents and imperfections in steel pipeline are well established and incorporated into industry codes; however, equivalent methods for the assessment of flexible pipes have not been developed. Considering the trend towards production in greater depths and the introduction of novel designs, it is valuable to develop more powerful tools to evaluate the consequences of the presence of defects in flexible pipe due to clashing, dropped objects and other operational damage.

In this article, a finite element model for the assessment of the residual collapse capacity of dented pipes is demonstrated. In distinction to other collapse models, this model allows the complex shape of the carcass layer to be modelled exactly. Based on previous studies and observations of dent types, the indentation process is simulated with different indenter types. The model also incorporates the effects of ovalisation, pipe axial load and static curvature. A parametric model generator and batch job scheduler is included in the model. Validation of the undented model against other assessment methods for flexible pipes is shown. Studies are carried out investigating indenter shape and load and the effects of axial force and pipe curvature on the limit collapse load. Results showing the sensitivity of flexible pipes to dents and imperfections are presented.

This article describes a validated model suitable for assessing damaged flexible pipes under combinations of damage types and loading conditions of use for defect assessment and life extension and provides a tool for developing future guidelines for flexible pipes.
Lazy Wave SCR versus Conventional and Bottom Wetted SCRs for Tying Back to a Spar Tube
Authors: Yu Alan , Stanton Paul , Caldwell James
Published: February 2015

Since developed in early 90's for the Shell Auger TLP project in nearly 3,000 ft of water, the number of steel catenary riser (SCR) installations has outnumbered other types of risers for deepwater field development. For water depths over 2,000 ft, the application of SCRs for importing and exporting oil and gas and for water injection on TLPs, Spars, Semis, and FPSOs seems to be unlimited.

This paper illustrates the development of a steel lazy wave riser (SLWR) designed to interface with an existing "I" tube of a Spar hull. It compares the SLWR with a conventional SCR on the basis of their strength and fatigue performance and interference performances with the adjacent vertical risers. The SLWR also was simulated through the installation steps. A successful installation campaign carried out in the Gulf of Mexico in a record 14-month EPCI project provides an example of SLWRs

Application

Import risers for existing Spars

Results, Observations, and Conclusions

SLWRs are viable alternatives to SCRs and flexible pipe risers for tying back subsea wells to Spars that do not have available porches or J-tubes for that purpose.

Significance of Subject Matter

SLWRs can be enabling technology for tying back subsea wells to existing Spars or for outfitting new Spars for future tie backs.

Area of Interest

Riser Systems
Special Challenges Designing and Installing Pipelines in Asia-Pacific with Emphasis on Seabed Geomorphology, Routing and Span Rectification
Authors: Brunning P. , Vennemann O.
Published: February 2015

The offshorepipeline market remains a large segment of oil and gas expenditure inAsia-Pacific and is forecast to continue apace. Design and installation ofpipelines in Asia and Australia is generally no more arduous than usual butthere are some distinctive characteristics of the continental margins withinthis region that are not commonly found in other oil and gas producing areas. In particular, the continental margins of the South China Sea and NW Australiaare much wider, and can be far more topographically uneven than those found elsewhere. This has a profound impact on pipeline design and integrity with specificrespect to spans. Of interest tothis study are: the underlying causes of on-bottom roughness, pipeline routing, critical span predictions and, from an installation perspective, spanrectification measures. It is not uncommon for on-bottom roughness and spananalyses to significantly over-predict quantities of critical spans in theearly design stages. Many of these will be marginal and in all likelihood neverappear once the pipeline is laid. Effort to eliminate these at the earliestpossible stage is worthwhile. This paper firstfocusses on the physical features of the continental margin that give rise toon-bottom roughness to help understand what are the particular soils and seabedfeatures that cause the spans which is information vital to the selection andapplication of span mitigation measures. The study then considers how thenumber of predicted spans can be reduced through a process of preliminary routeoptimisation and other measures including recommendations for optimisationsthat can be applied to input parameters used in span analyses. Lastly the paperconsiders the challenges of remedial work in the field. There are many spanrectification methods available but none are appropriate for all circumstances. The technology is reviewed and a matrix is presented assigning levels ofsuitability to each method depending on seabedconditions and water depth. Bothpre-lay and post-lay rectification measures are considered. Improvements in pipelinerouting and span analysis should result in more reliable predictions of therectification required and provide more realistic scopes of works for planningand costing.
Centrifuge and Numerical Modelling of Reaming as a Mitigation Measure for Spudcan-Footprint Interaction
Authors: Hartono Hartono , Tho K.K. , Leung C.F. , Chow Y.K.
Published: February 2015

Re-installation of jack-up close to footprints created by previous spudcan installations can be problematic. Instead of purely vertical loading during normal installation, the spudcan footing is subjected to eccentric and inclined loading arising from the combined effect of uneven seabed and shear strength variation in the vicinity of the footprint. Several mitigation measures have been proposed to alleviate this problem but so far only limited study has been conducted to investigate the effectiveness of these measures.

Reaming, otherwise known as leg-working or leg reciprocation, is the mitigation measure considered in this paper. Very limited information is available in literature regarding the procedure of reaming. This paper will present the results from centrifuge model tests and large deformation finite element analysis in an attempt to systematically investigate the efficacy of reaming technique for jack-up re-installation close to existing footprint in normally consolidated clay.

Several reaming strategies involving different amplitudes of leg penetration-extraction cycles were investigated. The induced vertical, horizontal and moment forces during reaming were compared with that of a generic spudcan re-installation. It is found that for reaming technique to be effective, reaming should be executed with small amplitude of penetration-extraction cycle. Moreover, the number of cycles for a particular leg penetration-extraction increment does not appear to play an important role in increasing the reaming effectiveness against footprint interaction. Back analysis using three-dimensional large deformation finite element analysis reveals a good agreement with centrifuge test data.

This study using centrifuge model coupled with large deformation finite element analysis provides insightful information pertaining the mechanisms and efficacy of reaming as a mitigation measure for re-installation of jack-up close to existing footprints.
Subsurface Containment Assurance Program - Key Element Overview and Best Practice Examples
Authors: Schultz Richard A. , Summers Laine E. , Lynch Keith W. , Bouchard Andre J.
Published: February 2015

The goal of Subsurface Containment Assurance (SCA) is to ensure that no adverse environmental impact, damage to operated assets, or impacts on well operations (drilling or production) occur due to leakage of production or injection fluids from reservoir intervals. Subsurface Containment Assurance involves the integrated efforts of subsurface (reservoir and overburden characterization), wells (planning, construction, well integrity and abandonment), operations (process safety and well operations and management of change) and HSE (health, safety and environment) teams. Disciplines must act together to develop and implement a surveillance plan to proactively monitor containment during well and injection operations in offshore fields.

The paper will describe the elements of a Subsurface Containment Assurance Program (SCAP) that are required for business units operating offshore across the entire life cycle from exploration to mature developments. The program is designed to be comprehensive, yet flexible; and focuses on the critical elements and risks for individual operating units. A consistent framework needs to be created and implemented that draws from existing tools for reservoir and overburden characterization and field management, and combines these tools to reduce the risk of unintended subsurface fluid containment loss. Specific assessment criteria and ranking approaches and tools for qualitative and quantitative estimation of containment risks will be discussed. Finally, surveillance programs focusing on containment using both direct and indirect measurements will be highlighted with a focus on offshore data gathering.

Loss of containment puts the environment, operating equipment and personnel at risk. Proactively identifying and mitigating containment risks is critical to operate safely. Containment assurance, particularly offshore, needs to be a key element of any asset and subsurface management plans.
Improving Reliability of Multi-Zone Fracturing Treatments While Optimising Efficiency
Authors: Carrejo N. , Wibowo H. , Salinas B.J. , Xu Z. , Gaudette S.L.
Published: February 2015

As conventional wells become scarce, unconventional wells have become a leading focus of the industry. Multi-zone hydraulic fracturing is an unconventional method of gaining access to tight, hydrocarbon-bearing shale basins. This alternative method has become highly effective and necessary as the demands increase to satisfy the energy needs of a developing world. Current technology has enabled these multi-zone fracturing systems to offer over 40 zones. This technology requires the use of a ball-seat system that utilizes one tripping ball per zone to actuate a sleeve, and expose ports to deliver the fracturing treatment. Each zone can require up to an hour of pumping for delivery of fracture treatments. Advancements in technology have led to the development of high-strength corrodible materials (HSCM), and its incorporation within a high-impacting telescoping port (HITP). The high-impacting telescoping port eliminates the need to actuate the sleeve to expose ports when delivering the fracture treatment. The HITP makes contact with the formation at 3,000 psi before delivering the fracture treatment. This new technology enables one tripping ball to fracture up to five zones at the same time, while the HITP ensures efficient delivery of the fracture treatment to the formation. This paper will explore the development and reliability of this new technology.
The Tethered Catenary Riser Concept Application to Deepwater Fields in Asia
Authors: Legras Jean-Luc , Neel Nicolas
Published: February 2015

Description

A new concept isproposed by Subsea7: the Tethered Catenary Riser (TCR). The concept consists ofa number of steel catenary risers supported by a subsurface buoy which istethered to the sea-bed by means of an empty single pipe tendon and anchored bya suction pile; flexible jumpers make the connection between the Floatingproduction Unit (FPU) and the buoy. The paper focuses on application of the TCRin deep-water fields of Asia.

Applications

Risers are de-coupledfrom the FPU. The riser system is thus efficient for FPUs with large motions: theflexible jumpers effectively absorb the platform motions, thereby the rigidrisers have very small dynamic motions, which improves both strength and fatigueperformance. The system can be installed before FPU arrival on site, whichimproves the time before first oil. The riser system is best designed for anumber of risers between 4 and 8 in addition to umbilicals, thus convenient forone or two drilling centres. The space used by a TCR on the field lay-out isrelatively small, thus allowing several units to be placed around the FPU inbetween mooring lines.

Results

The TCR system usesonly presently qualified material and technology. The components are all fieldproven as they are used in existing riser systems. Analyses have shown that, with adequate geometry of the buoy, the latter is sufficient stable to induceacceptable tilt when different arrangements of SCRs and flexible jumpers areinstalled, and under variation of the fluid weight distribution in risers. As a result ofinstallation studies, a method very similar to the one commonly used by subea7 for Single Hybrid Risers has been selected for the buoy and tether system. Placement of rigid risers, jumpers and umbilicals is as done by Subsea7 for theBSRs.

Significance

The TCR concept is a credible alternative option for use inincreasingly harsh environments or from host platforms with large motions. Asall components are fully qualified and the installation method well proven, theTCR system is cost effective and ready for project application.
The Effect of Appurtenances on the VIM Performance of a TLP for Southeast Asia
Authors: Tan J.H. , Teng Y. , Magee A.R. , Ly B.T.
Published: February 2015

In Southeast Asia, the characteristic operating environment is strong and persistent currents with small to moderate waves, which encourages vortex induced motion (VIM) in floating platforms. Scaled model tests have been used by the industry to predict VIM in floating platforms. Numerical methods such as Computational Fluid Dynamics (CFD) analysis have the potential to complement model tests for predicting VIM. Hull appurtenances such as tendon porches, SCR porches, caissons, pipes, chains, fairleads and anodes interact with the boundary layer and affect the point of flow separation along the columns which controls the vortex shedding pattern of the hull. In this study, the effect of appurtenances on the VIM performance of a Tension Leg Platform (TLP) for Southeast Asian environment is investigated using a series of model tests and CFD analysis.

The findings from this study may be used as a reference to properly account for the effect of VIM. The measured/calculated amplitude of VIM may be used as input for additional load conditions to be considered in the design of the tendon mooring and riser systems.

Previous studies by others on the same subject were carried out for spars. Multi-column floating platforms do not have strakes on the columns unlike spars. Thus, significant difference in VIM behaviors between multi-column floating platforms and spars is expected. The wake is expected to remain turbulent in both full scale and model scale. For smooth cylinders, the separation point along the columns is scale-dependent and this may affect the VIM response. If the flow separates from a sharp appurtenance like a pipe, the VIM behaviors should be similar in full scale and in model scale. The results from CFD analysis generally agree with those from model test. The differences in the results from the two methods are discussed and areas for further investigation suggested.

Significant VIM can adversely impact the platform mooring and riser systems in terms of both strength and fatigue life requirement and has to be properly accounted for in the platform design. Left unchecked, VIM can lead to loss of production due to unplanned repairs of the risers.
Development and Application of Type Curves for Pressure Transient Analysis of Multiple Fractured Horizontal Wells in Shale Gas Reservoirs
Authors: Kim T.H. , Lee S.J. , Lee K.S.
Published: February 2015

Horizontal drilling and hydraulic fracturing is necessary to reach economically success in shale gas reservoirs. PTA for shale gas reservoirs requires comprehensive understanding related to nonlinear gas flow process as well as hydraulic fracture properties. Even though significant progresses made in the past few years, there appears to be a lack of information regarding the characterization of shale gas formations. A major purpose of this study is to demonstrate how this issue may be addressed by pressure transient analysis for multiple fractured horizontal wells in shale gas reservoirs. Extensive numerical simulations were conducted to model transient pressure behavior of a fractured horizontal well and applied the results to well test analysis in shale gas reservoirs. The pressure transient response for a horizontal well with transverse multiple fractures is controlled by many of important fracture properties and nonlinear flow processes. This paper presents a comprehensive reservoir simulation model to investigate the characteristics of pressure transient responses under the influences of hydraulic fracture properties and nonlinear gas flow mechanism. Factors considered in this study include the number of hydraulic fractures, fracture half-length, fracture spacing, non-Darcy flow, and adsorption under reservoir flow condition as well as skin effect.

The numerical simulations for nonlinear gas flow provided various type curves in terms of dimensionless pseudopressure and time for transient pressure responses in fractured horizontal production wells. Results from type-curve matching for synthetic pressure data in shale gas reservoirs demonstrate that the conventional analysis approach may still be applicable for analysis of shale gas reservoirs. The results can be used for quantitative studies of transient gas flow behavior and determination of formation properties.
Successful Coil Tubing Based Selective Stimulation of a Remote Well in Challenging Offshore Environment - A Case Study
Authors: Anand Saurabh , Parasher Arunabh , Singh Alok Kumar , Kale Sagar , Gupta Karan
Published: February 2015

Well XX-1 is a newly drilled producer well in offshore west coast of India. The well has a deviation of 65 Deg and is completed with 3–1/2" screens with 2.31" SSD's in 6" open hole. Post production line-up, the well PI was found to be very low (<1). Thick viscous debris in the lower completion made access to the screen SSD's using slickline conveyed tools difficult and inconclusive - Hi Tech Downhole Camera runs confirmed that the lower completion was filled with mud. Tidal and current conditions ruled out any kind of Barge and Catenary based CT operation. Further, the platform had helideck as the working deck having a limited load handling capacity & crane load rating.

To remediate the poor well performance, a platform based coil tubing stimulation operation utilizing a modular and compact unit was proposed. A 20 T modular crane was installed on the platform and a detailed platform structural load analysis was carried out for spotting the CT unit and auxiliary equipment. Chemical & compositional analysis of the debris & formation cuttings was done to determine the appropriate stimulant recipe as no stimulation history for the field was available. CT conveyed Inflatable packer was used to isolate the lower section of the completion. Advanced flow activated downhole tools like double ended shifting tool & Impact hammers were utilized to selectively manipulate and stimulate all the desired zones in one run.

Post stimulation there was a 10 fold improvement in well PI with the well production increasing to 2600 BOPD from an initial rate of 300 BOPD.

The technique & setup has a huge cost implication as the cost of Catenary and barge is eliminated. The same technique is now planned to be applied to stimulate other wells in the field with logistical & technical constraints.
Well Test Analysis of Gas Condensate Reservoirs from Pressure Build Up and Draw Down Tests
Authors: Khosravi V. , Ketabi S.
Published: February 2015

Condensate drops out around the wellbore in the gas condensate reservoirs when the well bottomhole pressure falls below the dew-point. In these reservoirs interchanges in fluid from single phase to multiphase in the near-wellbore region, causes three different mobility regions in the reservoir. At the outer region, Away from the well, pressure is still above the dew-point with initial liquid saturation and there is only gas existed (Region 3). Next, there is an intermediate region in which the pressure is below the dew-point with increasing in liquid saturation and the condensate drops out of the gas phase (regions 2). Finally, increasing in the liquid saturation reaches above critical value and both gas and condensate are mobile and flow together into the wellbore (region1).

This paper presents well test challenges on the gas condensate reservoirs. It demonstrates phase redistribution, double porosity, capillary number effects, partial penetration or composite behaviors. Many reservoirs in all around the world are affected by gas condensate behavior. For example, the Karachaganak field in Kazakhstan, the Cupiagua field in Colombia, the North Field in Qatar and the South Pars field in Iran. Consequently, many researches have been conducted since the 1950's to understand the behavior of the gas condensate reservoirs below the dew point pressure to determine the main controlling parameters.

To sum up, the draw down flow periods are extremely complex to interpret. Hence, it shows that the condensate banking effect can be removed completely with an excellent fracturing job in place, even though the well is depleted below the reservoir's dew point pressure. Along increasing the skin; it is important to note that the composite behavior is represented. Our studies have been performed mainly on build-up data, because draw down data depends on flow rate fluctuations due to noise; especially in the gas condensate wells. Before the final radial flow stabilization, Humping skin effect is observed and the dual porosity does not disappear immediately.
Integrated Dielectric and NMR Measurements in a Solution Workflow to Meet Fluid Typing Challenges in Clastic Reservoirs Drilled Using Synthetic Oil-Based Mud: A Case Study from the Malay Basin
Authors: Kyi Ko Ko , Dahlan Nur Athirah , Quirein John Andrew , Nejm Ehab , Roy Dipanka Behari , Sillapasert Kriangakmon
Published: February 2015

Characterization of conventional clastic reservoirs can be very challenging because of issues related to the nature of the reservoir, logging environment, and/or the production enhancement projects being performed in the field. In the subject reservoir, the major challenge was typifying not only the hydrocarbon, in terms of gas or oil, in a well drilled using synthetic oil-based mud (SOBM) but also in a relatively fresh formation water bearing reservoir in which a water flooding project was being performed. Furthermore, the shaly and silty nature of the reservoir, and the uncertainty of the Rw value and other saturation equation parameters, added to the complexity of this task. Another challenge was to calculate residual oil saturation in one zone with the presence of SOBM-filtrate that contained a 20% water phase and incomplete information about the saturation exponent, n, in the imbibition process because of water injection in the field. To meet such a challenging reservoir situation, nuclear magnetic resonance (NMR), in multi-Te activation, and dielectric logs were acquired along with quad-combo, WFT, and oil-based mud imaging (OBMI). As a normal practice, formation evaluation was performed using the NMR T2D technique and dielectric complex refractive index modeling (CRIM) along with quad-combo and WFT for 1) mineralogy and porosity calculations, 2) fluid typing and quantification, and 3) permeability estimation. A slight viscosity difference between the formation oil and SOBM-filtrate was evident on the T2D map, and differentiating the various oils and quantifying residual oil was possible. Dielectric shallow resistivity, water filled porosity, and the estimated cementation exponent, m, played a major role in supporting the NMR T2D processing, especially when restricted diffusion was experienced and to fill gaps across intervals where NMR was not acquired. This paper discusses the reservoir challenges experienced and the solution workflow, with emphasis on the pros and cons of the different techniques used and recommendations for future projects. Data used in this study were acquired from a well in offshore Peninsular Malaysia.
Global Ultimate Strength Assessment of Existing Offshore Jacket Structures
Authors: Ayob M.S. , Kajuputra A.E. , Mukherjee K. , Wong B.S.
Published: February 2015

There are increasing numbers of ageing offshore structures in the water of South China Sea which come along with various types underwater structure anomaly, such as joint crack, member flooding, shallow gas and subsidence. This phenomenon brings an immediate attention to the Asset Owner to rectify the anomalies through various Strengthening, Modification and Repair (SMR) options. However, execution of SMR option is often a very costly operation. Optimum mitigation measure shall be established through proper structural re-assessment work with in-depth understanding of structural failure mechanism.

The present paper will focus on the established re-assessment methodologies in evaluating the structural global strength requirement. The re-assessment methodologies formed a step-wise evaluation process encompassing determining Risk Level Assessment, Design Level Assessment and Global Ultimate Strength Assessment (GUSA)

The risk level assessment considered all factors influences the likelihood of failure and consequence of failure of the structure to be determined to enable the establishment of its Risk Level. Next, the type of analysis which required to be performed under Design Level Assessment is similar to those analyses undertaken during Detailed Design Phase i.e. static in-place analysis, fatigue analysis, and dynamic analysis. Output generated from design level assessment to be feed into Global Ultimate Level Assessment (GUSA) if the structure fail to comply with the design level requirement.

GUSA comprises of three (3) integrated analyses which are Non-linear Plastic Collapse Analysis, Member Importance Analysis and Structural Reliability Analysis. These analyses will assist in quantifying the ultimate strength of the structure through Reserve Strength Ratio (RSR) and Probability of Failure (Pof). The outcome from the analysis can efficiently assist in understanding the structure failure mechanism and correctly defining type of mitigation required.

A few case studies is presented to give an insight on how this assessment is undertaken to demonstrate fitness for purpose of the structure and define the optimum mitigation measure.
Advanced Well Performance Analysis and Monitoring on Al Shaheen Field
Authors: Malakhov Denis , Gunningham Michael , Al-sadah Abdulla , Al-Suwaidi Abdulla
Published: February 2015

An opportunity to establish a certain level of confidence in the well models by analysing entire production history or even performing analysis in real time becomes a reality of today. This paper is intended to describe an engineering approach to the analysis that was tailored to the Al Shaheen field to better understand the well performance, gain confidence in the models and identify various well issues and opportunities.

The challenge of understanding how wells perform is always associated with comprehensive data mining and significant time spent on analysis and calculations. However the data available is always limited and often requires quite a few assumptions to be made by an engineer when building a representative and reliable well model.

All industry standard software packages utilise same or similar well-known concepts and types of analysis from simple equations to more comprehensive algorithms. These are like pieces of the puzzle that can be assembled together to help petroleum engineer to get an idea of how the well should perform in particular circumstances. The way petroleum engineers applying these concepts on daily basis may vary depending on the nature of the problem they are facing and the amount of data they have available. Quite often the fact that the model does not match the reality is used to invalidate existing data and an opportunity to understand that something is happening in the well that is not captured by the model is overlooked. Reasons for this may include an existence of a particular purpose of the well model, level of engineer's experience, skills or imagination, lack of required data or at the end an inability to process the entire production data in an efficient way. The last becomes a real challenge on the fields with large amount of wells and extensive production history.

Synergy between adopted analysis and the technology has allowed engineers to gain a much better understanding of the well performance, identify various issues and opportunities and enabled them to keep focus on making decisions as to which wells to optimise and those to troubleshoot to maximise potential of the existing well stock.
Riser and Pipeline Corrosion Risk Assessment
Authors: Carr Peter
Published: February 2015

When new tie-ins are made to existing infrastructure, corroded pipelines and risers may be subject to higher operating pressures than in their recent past. In order to help make informed decisions on whether such corroded components can be safely used at increased pressures, it is necessary to have a means of estimating their failure probability on introduction of the proposed higher operating pressure. A methodology has been developed to predict the probability of failure of a corroded pipeline or riser in the event of such an increase in operating pressure.

The application of the methodology to a 30-year old riser system containing several thousand corrosion clusters is described. The riser system comprised topside piping and a subsea tie-in spool as well as the vertical riser pipe. The analysis computed the probability of bursting if the pressure were to be elevated to a proposed new value. Using estimates of future corrosion rates, the analysis also estimated the remaining life of the system. The burst capacity model of DNV-RP-F101 was used, with allowance for the sizing accuracy of the inline inspection tool and for parameter and modeling uncertainties.

Two methods of computing the failure probability were explored:First Order/Second Order Reliability Method (FORM/SORM) andMonte Carlo Simulation (MCS). FORM and SORM are approximate methods, but very fast. MCS is an accurate method, but run times can be lengthy, particularly when the defect failure probabilities are low and when there are thousands of defects to analyze, as in the example case. As an exploratory exercise, FORM and SORM were tested against the MCS approach and found to have poor accuracy for this particular model. It was therefore decided to use MCS. The challenge in applying the MCS approach was then how to efficiently handle the analysis of thousands of corrosion clusters, each of which makes a small contribution to the overall failure probability.The paper describes how the MCS method was efficiently implemented and how the finished program was used to investigate sensitivity of the analysis results to different modeling assumptions, such as whether variables are treated as independent or correlated.
Rigless Stimulation in Deepwater Field - Case History: Jubilee Field
Authors: Rodriguez Jonathan , Hayford George , Kros Hans , Mancini Christopher , Bartlett Shawn
Published: February 2015

One the most common methods for well stimulation includes the use of mobile offshore drilling units (MODU) to pump fluids into the well with the main objective of restoring production or injection. A rig-based well stimulation is an expensive operation and in some cases a separate stimulation vessel is used to store and pump fluids. Economics to justify a stimulation operation may require a number of wells (depending on well productivity) to make the project economically viable. New industry developments in the last few years have made the use of special intervention techniques from vessels relatively popular. However, a riser based system remains the preferred method to intervene/stimulate deepwater wells. Riserless systems are becoming more and more popular but their applications vary from region to region based on water depths, sea conditions, equipment and technical personnel availability.

Since start of production from the Jubilee field, several oil producers had experienced gradual productivity decline with a significant reduction in flowing bottom hole pressure, despite an aggressive pressure maintenance program with water and gas injection. Following the success of previous acid stimulation work carried out off the rig in an attempt to restore productivity, a rigless acid stimulation treatment on the impaired Jubilee wells wasproposed. An initial feasibility study was conducted, whichindicated that a Rigless stimulation operations using a Multi Purpose Supply Vessel (MPSV) was considered to be a commercially and technically feasible operation. While the primary objective of the rigless stimulation campaign was to increase production, this work also demonstrated that the rigless intervention from the MPSV is a cost effective and technically feasible option for a long term campaign. The operation was successfully conducted using two vessels. Fluids where pumpd into the well using 4 × coiled tubing strings deployed in 1,600 m water depth. This paper explains the methodology used for the development of a rigless stimulation campaign in the Jubilee field, offshore Ghana.
High-Definition Resistivity Imaging of Low-Resistivity Formations Drilled with Nonconductive Mud Systems for Near-Wellbore Geological and Petrophysical Reservoir Evaluation
Authors: Le F. , Bal A.A. , Bespalov A. , Corley B. , Forgang S. , Gold R. , Itskovich G. , Gaafar G.R.
Published: February 2015

A new wire-line formation resistivity imaging instrument employing a ‘two-electrode’ measurement configuration has been developed for application in low-resistivity formations drilled with non-conductive (oil-based) mud. A detailed explanation of the instrument and measurement principles is provided. Modeled synthetic responses and field examples are shown.

The high-spatial resolution of a ‘two-electrode’ arrangement has been well documented for nearly 25 years. The lower formation resistivity limit in oil-based mud boreholes for prior devices often precluded realizing their benefits in many important offshore deep water plays, such as Malaysia, Gulf of Mexico and elsewhere. The new instrument employs multi-frequency impedance measurements to overcome this limitation.

The impedance measurements produce two image logs: a real-part impedance image that is calibrated to yield formation resistivity and an imaginary-part impedance image that conveys information about image quality. The instrument employs six individually-articulated pads each containing ten sensor electrodes that provide a 75% surface coverage in an 8½ inch borehole. Typical spatial-resolution is better than one-half-inch vertically and one-eighth inch azimuthally. Pad-to-pad depth off-set is less than 6 inches, assisting to maintain borehole coverage in the presence of common instrument rotation during logging.

Field examples from typical logging environments found in offshore Malaysia are presented. Detailed geologic features such as thin-beds, slumping, cross-bedding, faulting and fracturing in low resistivity depositional environments are clearly resolved.
Corrosion in Formate Brines - 20 Years of Laboratory Testing and Field Experience
Authors: Howard Siv , Chrenowski Marcin
Published: February 2015

This paper contains a thorough analysis of all available corrosion test results of formate brines combined with an extensive compilation of experience form 20 years of use of formate brines as completion and drilling fluids from hundreds of HPHT applications.

Formate brines were successfully introduced into the field as high pressure high temperature drilling and completion fluids in the early 90's. Today they are used in Extreme and Ultra HPHT applications worldwide. As they are the only group of non-hazardous brines that can reach the highest density requirements, they have been pushed to the extreme both when it comes to exposure temperature and exposure time. One of the biggest concerns when leaving completion brines downhole under extreme HPHT conditions is the compatibility with downhole materials.

The biggest corrosion concerns in completion brines are localized pitting corrosion and stress corrosion cracking (SCC) of the production tubing. C-steel casing material can suffer from pitting corrosion and sulfate stress cracking (SSC) and certain high nickel alloys can suffer from hydrogen embrittlement (HE) after extensive exposure to oilfield brines followed by sudden cooling of the material. Extensive laboratory testing of martensitic stainless steel has shown that this material can suffer from SCC in all oilfield brines. For formate brines, failures have typically been seen in long-term tests when very high yield stress has been applied and the pH buffer has been overwhelmed by CO2. 20 years of field experience at temperatures up to the upper recommended temperature limit of this material has shown an unbeatable track record of zero SCC failures of martensitic stainless steel. Duplex stainless steel tubing material has also never failed from SCC in formate brines.

Material compatibility is an increasing concern in future HPHT wells where downhole material is being exposed to even higher temperatures. All operators are cautious about challenging the temperature limits of completion brines and downhole materials. This review will be a useful tool for operators worldwide who are considering using formate brines for the first time in their future Extreme and Ultra HPHT applications.
Study on Deepwater Drilling Riser Wear
Authors: Liu Xiuquan , Chen Guoming , Chang Yuanjiang , Zhang Lei , Liu Kang
Published: February 2015

Several riser wear accidents have occurred in offshore oil industry, which threaten offshore drilling safety and cause huge human, economy and environment losses. In 2012 and 2013, several deepwater exploration wells were accomplished in the South China Sea by CNOOC as the operator with the deepwater drilling unit HYSY981. And the assessment and management of deepwater drilling riser wear are problems to be solved urgently. Analysis method of multi-tube coupled system was studied and mechanical analysis models of riser and drillstring were established in this paper. Riser wear of an exploration well in the South China Sea was calculated according to proposed methods. The influence of drilling platform displacement, riser top tension and rotational stiffness of lower flex joint on riser wear was also studied. The results show that the contact between riser and drillstring is interval distribution. The maximum contact force occurs at lower flex joint. The contact force near mudline between casing and drillstring is also large while contact forces of other positions are little. Analysis result of riser-drillstring contact is good agreement with actual phenomena. Drilling platform displacement, riser top tension and rotational stiffness of lower flex joint are important factors influencing riser wear. Riser wear is closely related to flex joint angle, and proper drilling platform displacement leads to small flex joint angle and little riser wear. Riser wear can also be reduced by increasing riser top tension and rotational stiffness of lower flex joint. The related results and conclusions in this paper provide reference for offshore drilling and guide inspection, monitoring and maintenance of riser wear. Then riser integrity and offshore drilling safety can be guaranteed.
The Floating Liquefied Natural Gas Production, Storage and Offloading Technology Research
Authors: Xie Bin , Liu Xiao , Yu Xichong , Wang Chunsheng , Zhu Xiaosong
Published: February 2015

The current status of the FLNG research project is introduced in this paper. Primary focus is placed on the six key technical areas which have been addressed in the phase I of this project, i.e. liquefaction process, LNG tank sloshing, single point mooring system, LNG tank selection and arrangement, LNG offloading and FLNG risk assessment. Firstly, the selection and design of liquefaction process is presented. Based on the result of comparison with other liquefaction process, an optimized and patented propane pre-cooled nitrogen two-expander cycle process is proposed. Secondly, LNG tank sloshing is considered through numerical simulation and model test. Thirdly, single point mooring system is discussed and considered the impact of different ballast types of FLNG, Both internal turret and external turret are analyzed. Fourthly, a comparison of three commonly used types of LNG containment system is performed considering of both the system characteristics and technical competence in China. In addition, the arrangement of LNG tank is also considered in this paper. Fifthly, both side by side offloading and tandem offloading are discussed. It is pointed out that both types of offloading should be deeply studied in further for applicability for the specified environment condition in South China Sea. Finally, the FLNG risk assessment process and framework is established. Furthermore, a full scale quantitative risk analysis covering all the major hazards of FLNG will be studied in the phase II of the project. In addition to the six key technical areas, future works during phase II of this project in the next five years from 2011 are also proposed.
Case Evaluating Acid Stimulated Multilayered Well Performance in Offshore Carbonate Reservoir: Bombay High
Authors: Rawat A. , Tripathi A. , Gupta C.
Published: February 2015

Production trends in the carbonate reservoir systems vary due to a wide array of complexities: substantial reservoir heterogeneity produced fluid type, fluid driving mechanism and other factors that affect hydrocarbon flow through the reservoir to the well bore. Due to these complexities, stimulation techniques achieving diversion to increase the coverage are inculcated to optimize the production and recovery.

The paper provides case study of the offshore Bombay High Oil Field carbonate reservoir with multilayered lithology which possesses a permeability range of 5–500mD, temperatures that reach 116°C and an interval length of 26m perforating three pay zones, characterized by dual porosity and permeability, vugs and open fractures of varying apertures affecting the flow type and increased maturity of the fields causing a decrease in the reservoir pressure which gradually declined the well's productivity affecting recovery optimization.

Significant multiphase acid stimulation was designed with Viscoelastic Diverting Acid (VDA) technique for higher injecting rate operations based on rheological behavior in accordance with the complex porosity/permeability profile obtained by LWD measurements and images. The paper includes the pre- and post- Viscoelastic Diverting Acid treatment plots of the field along with the production performance data with Productivity Indices (PI) of the well calculated showing consequential results in the reservoir performances in affect with the stimulation.

The objective of the paper is to compare the percentage change in pre- and post- stimulated performance of the well covering the lithological complexities of the field, design and post treatment evaluation and showcase other critical areas of acid stimulation In multilayered well.
Multiple Identification in Surface Seismic Data through VSP Multiple Analyses: A Case Study
Authors: Human Tertius , Kunaifi Sunawar , Surasky Alan
Published: February 2015

Both surface and interbed-generated multiples are an integral part of surface seismic datasets, and several techniques are used to identify and remove them. Unfortunately, there is not a single technique that can accurately identify and remove every multiple in a dataset, so interpreters often work with datasets that contain several multiples.

A vertical seismic profile (VSP) has a unique geometry in that the receivers are in the subsurface and can, therefore, record both a down-going and up-going wave field. The down-going wave field is used for deterministic deconvolution and can successfully identify and remove all multiples. The resultant corridor stack is multiple free and can then be compared to the surface seismic. Several techniques can then be used to identify any residual multiples in the surface seismic data, including information about the origin.

This paper presents a case study to identify multiples in the surface seismic data of a field in the Asia Pacific region. The paper will show how the VSP data is processed to produce a corridor stack that is multiple free, a corridor stack that contains both primaries and multiples, and a stack that contains only multiples. These are then merged with the surface seismic data to accurately identify any residual multiples. The residual multiples can then be removed through further processing