In this study, fully coupled poro-thermo-elastic geomechanics modeling of wellbore stability was conducted on high pressure and high temperature (HPHT) wells in Hai Thach field offshore Vietnam. The drilling environment is extremely challenging with formation pore pressure gradient of more than 17.0 ppg and formation temperature above 170°C near TD. Post-mortem analyses of drilled wells were carried out using an analytical poro-thermo-elastic wellbore stability simulator, taking into account the coupled time-dependent evolution of pore pressure, temperature, and stresses around the wellbore. The analyses revealed very narrow time-dependent safe mud weight windows that became narrower as time progressed. The HPHT environment created very challenging drilling situations. During drilling and hole cleaning, the flowing mud cools off rock formations, inducing tensile thermal stresses, and therefore reducing effective compressive stresses around the wellbore. As a consequence, the fracturing pressure is reduced when the ECD is higher due to circulation, increasing the chances of mud losses. On the other hand, during static mud condition the formations retain their very high temperature and compressive stresses, which require higher mud weight to prevent wellbore collapse while the mud pressure only equals the static mud weight, increasing the chances of shear failure. This study highlights the importance of accurate prediction of safe mud weight window before drilling as well as timely updates to the mud weight window during drilling. Furthermore, guidelines of good mud weight management practices to drill the HPHT zones with very narrow mud weight windows are also given. For example, when the safe mud weight window is too narrow and shrinks with time, a higher static mud weight might be required during openhole logging to combat borehole collapse. On the other hand, during hole cleaning with increased mud circulation rate and increased ECD, a lower static mud weight might be required to mitigate mud losses. Moreover, with the time-dependent safe mud window available, the drilling and logging program can be optimized to minimize exposure time and mitigate the damaging thermal effects on the mechanical stability of the drilled borehole.
The Sarawak Integrated Gas Network is one of the largest and arguably most complicated offshore gas networks in the world due to its intricate physical layout comprising of more than 20 fields producing with total capacity of more than 4000 MMscf/d, supplying to 3 LNG plants. As there are various operators in the network operating different Production Sharing Contracts (PSCs) and Gas Sales Agreements (GSA), commercial arrangements are essential to govern the production policy of the network to ensure PSC and GSA obligations and/or entitlements are honoured. Gas quality management by blending of gas is another aspect to be considered as each of the 3 LNG plants have constraints on contaminants such as CO2 and H2S and each field has varying contaminant levels. Integrated Production Systems Model (IPSM) is used extensively for the production forecast of integrated gas networks as pressure interaction via surface network between the different wells have a significant impact on the reservoir performance. However, due to the combination of physical and commercial constraints of the Sarawak Gas Network and the additional complexity due to contaminants management, generic IPSM models are unable to accurately handle both physical and commercial requirements. As such, the traditional workflow for Sarawak Gas Network required a workaround where IPSM models are used in combination with post processing spreadsheet to manually tweak production forecasts in order to honour commercial and gas quality constraints. This was cumbersome and also negated the real benefits of IPSM. The recent rebuild of the Sarawak IPSM model with the Shell proprietary tool, "Hydrocarbon Field Planning Tool" (HFPT), addresses this challenge by incorporating the commercial arrangements within the model. This is made possible as HFPT allows for flexible scripting which enables asset specific functionality to be modeled. The approach is essentially a 2 step approach within HFPT, where field capacity is derived based on physical constraints (as per generic IPSM models) and a second step where production nomination is managed with a series of rules designed to mimic operational practices to align production nomination with commercial arrangements and for gas quality management. The Sarawak HFPT model has been used extensively for Business Planning and resource reporting exercises to ensure the production forecasts are robust and credible. With this novel approach, the revamped Sarawak IPSM model is capable of generating production forecasts which integrates both commercial and physical constraints as well as contaminants management without the need to evaluate the commercial arrangements as a post processing step.
Bilge keels are commonly installed on commercial ships and FPSO/FLNG units to effectively mitigate roll motions. Accurate predictions of the roll damping and hydrodynamic loads are critical for the structural design of the bilge keels. In this paper, model tests and Computational Fluid Dynamics (CFD) are employed to investigate the nonlinear roll damping and hydrodynamic loads on the bilge keels. Roll decay tests and CFD simulations are carried out for a FPSO vessel to estimate the roll damping and drag coefficients of the bilge keels with extended depths. Also seakeeping model tests and CFD simulations are carried out to estimate the hydrodynamic loads on the bilge keels in regular beam waves. From this study, it is found that the drag coefficients of the
Ambiguity and pitfalls in amplitude interpretation to determine the hydrocarbon prospects is the most challenging problem in oil and gas industry, including in the Malay Basin Field. These pitfalls are caused by a dualism of the lithological and pore fluid effect on seismic amplitude. Many techniques have been proposed to solve the problem. However, the optimum separation of that ambiguity is still difficult to be achieved. The objective of this paper is to demonstrate new attributes derived from seismic attenuation - rock physics approximation as an alternative technique for lithology and pore fluid discrimination.
New attributes namely SQp and SQs have been developed based on seismic attenuation-rock physics approximation. Testing on model and real data sets from Malay Basin have been conducted.
The results show that the SQs attribute is sensitive to the water saturation changes, while the SQp is sensitive to the lithology changes. In well log, the SQs attribute has the highest coefficient correlation with water saturation compared with other existing fluid indicators, while SQp attribute has the highest correlation with gamma ray log. The cross plotting of these attributes show that the lithology and pore fluid effect are separated orthogonally to each other. The lithology differences are distinguished in the SQp attribute, while the fluid types are distinguished in SQs attribute. The gas sand is separable from shale background and wet sand easily. Furthermore, the coal effect can be distinguished clearly from gas sand. The implementation of those attributes on inversion result shows that SQs attribute is able to delineate the gas sand from wet sand that cannot be done by SQp attribute. Meanwhile, the SQp attribute can capture all the sand formations including gas sand and wet sand which is distinguished from shale background.
Coiled tubing (CT) services in India are positioned as highly tailored services with operations such as cleanout, nitrogen kickoff, and matrix stimulation in vertical or slightly deviated well. With the advent of horizontal wells in India, the scope of CT applications has increased considerably, especially for multistage fracturing in tight reservoirs.
This paper deals with well performance optimization in a tight gas reservoir in the Cambay basin situated along the western coast of India. Most of the reservoirs in the basin are very low permeability, and hydraulic fracturing may be the only way to achieve economic production from the reservoirs in most cases. The successful execution implied tapping into the unconventional gas reservoirs in India, which are expected to account for 75% of gas production in India by 2035. The plan was to fracture stimulate eight zones in four stages and later mill the isolation plugs to put the well into production from all eight zones. An innovative perforation technique of using dual firing head guns—an electronic firing head and circulation ball drop-activated firing (CBF)—in the same run to selectively perforate two clusters was used.
The presence of gas in the CT-tubing annulus while perforating the upper formations and the adequate isolation through the flow-through plug to provide appropriate pressure differential for the CBF were the major challenges faced whilst perforating. Previous failure in the offset well was carefully analyzed to identify the root cause and come up with appropriate job design and operating procedures. The job was designed to keep backpressure in a balanced condition to the reservoir pressure to prevent any inflow of gas through plug, and the electronic firing head was optimally programmed above the cushion reference pressure. A rise in the wellhead pressure and shock at the wellhead were the surface indications observed for both the electronic and CBF firing heads while the latter also exhibited sudden rise and then drop in circulation pressures.
The project was executed in a defined timeline as per client expectations. The well was completed with eight fractures in four stages placing the designed amount of proppant. Initial production estimates have been very encouraging, with increased Oil Gas Ratio (OGR) leading to 20% greater production than forecast. This operation has opened new possibilities for the use of CT services in horizontal wells in the same formation.
In 2014 Asia Pacific, McDermott International, Inc (NYSE: MDR) completed installation of its first pipein-pipe (PIP) flowline system in water depths in the range of 1200m to 1500m by reel-lay using its reel Lay Vessel North Ocean LV105. During spooling onto the installation vessel and offshore installation, the pipeline is reeled, unreeled, straightened and deployed to the seabed. These operations subject the pipe to cyclic plastic deformation and induce significant residual ovality in the pipe after reeling and straightening. An accurate prediction of this residual ovality is a key parameter for deep water pipe collapse checking and is a dimensional requirement to determine expected welding hi-lo during offshore tie-in welding.
An empirical design formula for ovality prediction has been provided in DNV-OS-F101 [
This paper tackles the prediction of ovality for reeling and straightening processes using the finite element simulation software ABAQUS [
A new empirical formula for predicting ovality under pure bending has been formulated based on curve fitting results from FEA simulation of pipeline pure bending and a novel approach has been developed to estimate the on-reel ovality for actual reeling. It started with estimating the pure bending ovality using the newly developed formula as mentioned above, followed by another newly developed formula that accounts for the effect of contact load on reel. This contact load ovality empirical formula is developed considering the pipe stiffness definition used in buried pipe design for plastic pipe [
Finally, a new simplified approach for estimating as-laid ovality has been developed. This new approach is based on the above mentioned newly created on-reel empirical formula together with reduction factors based on in-house data.
Wada, R. (Department of Ocean Technology, Policy and Environment, University of Tokyo) | Mondal, R. (Department of Ocean Technology, Policy and Environment, University of Tokyo) | Kamizawa, K. (Department of Ocean Technology, Policy and Environment, University of Tokyo) | Takagi, K. (Department of Ocean Technology, Policy and Environment, University of Tokyo)
In the present study, concept of a floating logistic terminal (FLT) is evolved using three floats. Emphasis is given on the best configuration of the structures and the reduction of motion of the floating terminal. We present the preliminary numerical and experimental studies of response amplitude operator (RAO) for heave, roll and pitch. The analysis is executed for three different configurations of the floating structures. Though, the application area is for shallow water, however the deep water case is also studied. The motion characteristics are studied for head waves as well as oblique waves. The results obtained from two different methods are compared.
In Subsea Production System design, the effect of equipment design on flow and vice versa may not be sufficiently considered by the design engineers. Historically, rules-of-thumb and piping design guidelines have been adopted leading to overly conservative design or conversely poor performance. This paper discusses some of common design practices with regard to equipment sizing, sensor placement and thermal design and attempts to promote a better understanding of the impact of flow on equipment design.
The vertical-lift performance curves are often generated with the aid of computer software for creating well models of producing oil and gas wells. These models are used as tools for optimizing fluid production, generation of production forecast and well problem diagnosis. The well models are further used to plan for future requirement of artificial lift assistance.
One of the important components for development of representative well models is the Vertical Lift performance and Inflow Performance curve matching. The vertical lift performance curve is generated separately using well test data using various correlations and the best matching correlation to actual well pressure gradient is selected for VLP-IPR matching. The VLP depends on various factors such as tubing size, gas-liquid ratio, wellhead pressure, etc.
The producing oil wells having higher paraffin content tend to deposit paraffin wax inside the production tubing reducing the flow area and increasing the pressure drop. The deposition generally occurs near the surface and at greater depths the tubing is free from deposition due to higher temperature because of the geothermal gradient. Due to this an error is induced as the effective inside diameter of tubing is less than the actual diameter entered by the user, this leads to variation in the actual and calculated pressure drop ultimately leading to deviation by more than 10% in many cases.
This paper describes implementation of method to enter the severity of paraffin deposition in a particular length of tubing and dividing the total length of tubing into sections having different internal diameters. The estimation of deposition can be done by carrying out mechanical scraping operation in which the wax is cut mechanically using paraffin cutters of various sizes starting with the smallest and gradually increasing to higher sizes of cutters. The restriction due to wax is evident at the surface by monitoring the weight loss in the wireline weight indicator.
By using this method an accurate well model can be created which will represent the actual behavior of the producing well thereby increasing the accuracy of any further predictions.
Afizza, I. M. (Petronas Carigali Sdn Bhd) | Muhd-Faizul, H. A. H. (Malaysian Energy Chemical & Services Sdn Bhd) | Mohd-Fadly, Y. (Malaysian Energy Chemical & Services Sdn Bhd) | Ngau-Uvang, J. (Petronas Carigali Sdn Bhd) | Mohd-Hazriq, S. I. S. (Petronas Carigali Sdn Bhd)
Continuous & effective bio-corrosion monitoring task is highly critical for fast & direct detection of microbial-induce corrosion growth risk pattern within an upstream processing system. This might due to changes in fluid characteristic by time. Failure in detecting such risk changes might trigger for occurrences of serious corrosion-related issue. This study incorporated new detection using AccucountTM energy-based detection kits into monitoring task along with conventional API RB38 SRB test vials & Kitagawa Hydrogen Sulfide gas test. Besides focusing on pipeline microbial growth risk, the monitoring are extended throughout the processing stages to identify the potential & direct microbial risk. The test are carried out at three different sampling time frame; one week after previous treatment, two weeks after treatment & after newly established treatment. The results offer valuable information on the weak point of established treatment program which has previously been overlooked by conventional methods; medium-risk growth in stagnant point, medium risk well-pools & potential solid sedimentation in stagnant point. Time kill test shows high effectiveness of current biocide that been applied into system. Besides, internal corrosion inspection of production separator identified twelve pitting formations. Developing microbial controlling strategy for offshore platform may varies by locations. Accurate and rapid process monitoring leads to correct and well-targeted solutions to potentially detrimental problem. A complete assessment with different set of viewpoints are highly critical in order for a cost effectiveness and further optimize the mitigation method.