Contreras Perez, David Rafael (OMV E&P GmbH - Abu Dhabi) | Al Zaabi, Ruqaya Abdulla (ADNOC Offshore - GUL) | Viratno, Bernato (OMV E&P GmbH - Abu Dhabi) | Sellar, Christopher (OMV E&P GmbH - Abu Dhabi) | Susanto, Maria Indriaty (OMV E&P GmbH - Abu Dhabi)
The rationale of structural uncertainty analysis in reservoir modeling is to quantify the range of probable Gross Rock Volume (GRV) s and searchfor the means to reduce this range as much as possible. This task considers running different scenarios and/or structural configurations based on the observed mismatch between structural depth estimation from seismic mapping and stratigraphic tops derived from well data. Integrated multi-disciplinary teams can collaboratively eliminate reservoir uncertainties at the well location, however uncertainty remains in the interwell area. The challenge for any reservoir characterization team is to share expertise across disciplines in order to mitigate the lack of information with scientific reasoning. In this way the range of uncertainties impacting business decisions, development scenarios or data acquisition plans are minimised. The workflow summarized here is an example of how to utilize structural elements from existing wells to quantify intrinsic GRV uncertainty while building static models. Offshore Field developments usually have a bigger horizontal well count than the ideal vertical penetrations and this case study is no exception in this case study. The ultimate goal of this publication is to generate the inputs required for a more realistic set of structural realizations that fulfil all of the current understanding from horizontal well placement and their intrinsic structural uncertainty.
We investigated the method of estimating porosity/permeability using X-ray CT, a non-destructive method. Using X-ray CT, a method of estimating the porosity/permeability is particularly developed in sandstone. However, for the carbonate rocks, the internal structure is complicated due to biological origin. This is difficult to recognize the pore space, therefore a method of estimating the porosity/permeability using X-ray CT has not been studied. This study is based on
Based on the 3D modeling of the X-ray CT, two rudist families (Radiolitidae and Ichthyosarcolites) were identified through their morphological characteristics such as inner diameter and shell thickness. A porosity of slab core around 50 feet is about 18% from CCA (Conventional Core Analysis). This slab core is made up of small rudist populations (length and wide size is 15-10mm), inside core confirmed 3D modeling (surface rendering and volume rendering), and calculated porosity is 0.89% from RCM (Reverse Coupling method). It is understood that this difference is dependent on matrix porosity and further investigation in the future is required in order to measure matrix porosity using thin section and micro X-ray CT. With regards to reservoir properties, the porosity is higher in the lower part than the upper part in the core interval. The size of the Radiolitidae could be dependent on the environment and its vertical variation suggests the change of depositional environment. Larger Radiolitidae, which appeared from 80 to 200 feet below the C-T (Cenomanian-Turonian) boundary, suggests a relatively strong wave influence. From a sedimentological point of view, the coarser matrix grain size supports the interpretation of depositional setting. On the other hand, from 30 to 80 feet below C-T boundary, smaller Radiolitidae is dominated. It was assumed that small Radiolitidae could be due to high physical stress under a restricted environment.
This study shows the advantage of X-ray CT image in rudist recognition, based on interpretation of depositional environment and understanding the reservoir property. The result of this study suggests the strong correlation between porosity/permeability and depositional environment (accommodation space) inferred from rudist fossil.
This paper discusses on the methods of the installation of Corrosion Resistant Alloy (CRA) pipeline for High Pressure High Temperature (HPHT) including its challenges and the subsequent mitigations.
The experience is based on the successful installation of Anjung Gas Development Project which consists of 18" diameter X 8km length of CRA Full Well Stream (FWS) pipeline installed utilizing the (Dynamic Positioning) DP-2 pipelay vessel. The methodology applied in the installation is via typical S-lay utilizing automatic welding system (for the pipelaying) and stalk-on (for the risers at both sides of the platforms). Additionally, Zero Radius Lay (ZRL) method was utilized at buckle triggers. On the existing KAKG-A platform, the riser installation is via suck-in method to avoid removal and reinstatement of the existing riser guard. Two (2) numbers of anode sleds were utilized for cathodic protection. The scope for pre-commissioning performed was flooding the pipeline with fresh water, cleaning, gauging, hydrotesting, air drying, nitrogen purging and packing.
Multiple Concrete Weight Coating (CWC) thicknesses was used to cater for anchoring of pipeline walking. One (1) set of tensioner shoe pads was moulded to suit all CWC thicknesses in order to mitigate the issue of maintaining two (2) tensioners holding the pipeline during pipelaying. The other two (2) tensioners onboard the Main Work Barge (MWB) were installed with sets of tensioner shoe pads suitable for different thickness of CWC. Although with various weld defects experienced, mitigations that were executed proved that the layrate could be improved and finally achieved the target layrate. A wet buckle procedure including its equipments was prepared as a contingency plan. However, due to no wet or dry buckle, this procedure and equipment were not utilized. The project completed successfully with zero Loss Time Injury (LTI) and no major issues. Hence, it is an achievement for PETRONAS. It sets as a standard in moving forward in any new technologies that is developing.
The overall schedule was improved by approximately 20% and cost was reduced by approximately 15% due to the above mitigations. The impact of the successfulness of this pipeline installation is a basis for PETRONAS future CRA pipeline installation as this is the first HPHT CRA pipeline installed by PETRONAS Carigali Sdn. Bhd. (PCSB). This proves one of PETRONAS' 5 Quality Principles, Right Things Right Every Time. The challenges including the mitigations are a good lesson learnt for any future CRA pipeline installation projects that the industry will be undertaking.
In this project, the PETRONAS Technical Standard (PTS) 193004 Installation of Offshore Pipelines and Risers (Amendments/Supplements to ASME B31.8, ASME 31.4 AND DNV OS F101) and API 5LD is the basis for the installation.
Thin turbidity siliciclastic reservoir is a challenging deep-water environment for modeling. In a deep off-shore field in West Africa, sedimentological characterization of these reservoir suggests typical turbiditic sandstones: Arenites with medium granulometry and normal gradation over imposed by plane-parallel sand laminations intercalated by shaly levels (late stage turbidity sandstone beds - characterization by
These sands are defined in the reservoir model by curves of petrophysical properties, log facies, characterization of thin bedded intervals and a volume of seismic inversion.
Tuning analysis suggest the potential seismic resolution is 16 meters. Seismic inversion was processed to generate a higher resolution driver for modelling.
Formation evaluation uses high-resolution logs within "Thin Layer Analysis and Characterization" (e-tlac™) method (
High-resolution logs were acquired only in three wells over twelve drilled in the field. For this reason, a re-calibration of all conventional CPIs including the "e-tlac" output results was necessary to better control the reservoir property distribution all over the grid.
This methodology increased capability estimating pay volume close to real value avoiding underestimation of Net Sand and Water Saturation overestimation.
The solution to model thin turbiditic sands within the static 3D model is integrating all the above data inputs (stratigraphical environment, seismic inversion volume and "e-tlac" output). Reservoir cores was the input for the sedimentological study; the seismic inversion volume was background for reservoir facies distribution and "e-tlac™" formation evaluation output to assign unbiased reservoir properties to sand and thin layer facies at the well position.
As lesson learned, the acquisition of triaxial induction, high-resolution dielectric or image is the key to better characterize the inter-bedded thin levels that are present in similar deep-water environment.
Structural characterization of faults and fractures is a key component of reservoir description, however, data consolidation often does not allow decisions on modelling or explanation of fluid flow anomalies. For the task of assessing fracture modelling need, data has often not been gathered systematically. Most carbonate fields’ models in the area require permeability modification/enhancement but where do these sit with regard to K multiplier modifications versus DFN models, for example? A key conundrum i s that most conventional UAE hydrocarbon fields would, according to the
Building conceptual models involves collaborative structural geology to develop a concept, including static and dynamic data relevant to the structural components present at all scales (faults, fracture corridors, layer-related mechanical fractures). The concept may include fault character and temporal evolution, along with dynamic data for understanding connected flow paths as much as possible. Once built, variants can be generated around the base case, reflecting uncertainty of structural aspects or specific sub-zone nuances. A series of conceptual models considers the variation between different stacked reservoirs and end-member variants for a given single reservoir within different structural domains or different traps. Comparing the conceptual models with standard ‘fractured field’ classifications allows determination of the type of reservoir (
Assessing the level of deformation, as a bulk strain within a carbonate reservoir, provides a ‘relative deformation volume’. Proportionally, this is the volume of rock within the reservoir that contains visible or mapped deformation, as per conceptual model features, where at least a component of fluid flow would be controlled by such discontinuities. Assessment can be for an entire field, for specific reservoir(s), or for a specific geologically defined flow domain, and offers unhindered comparisons. Analysis of a series of different stacked reservoirs, with varying matrix properties, in the same field, are ranked according to deformed volume, which shows relationships with (a) dominance of fractured layers and (b) water cut evolution and hence future field development options. Visual assessment of the conceptual model allows differences between reservoirs and variants within a reservoir that reflect different effects of structure (e.g. trap shape, fault-proximal effects) to be compared. Using conceptual models with relative deformation levels, the appropriate need and means of fracture modelling can be quickly established.
Rafiq, Shahid (ADNOC Gas Processing) | Locharla, Haribabu (ADNOC Gas Processing) | Al Awadhi, Ibrahim (ADNOC Gas Processing) | Al Ahmad, Alya (ADNOC Gas Processing) | Miranda, Robert (ADNOC Gas Processing) | Al Braiki, Ahmed (ADNOC Gas Processing) | Al Qaydi, Alya (ADNOC Gas Processing)
Piping systems having service temperatures lower than ambient present a challenge for the pipe support design. Pipe supports for these cold piping systems are different from normal type of supports on pipes with service temperatures above ambient. Normally hot insulated piping systems have shoe type of supports directly welded to the pipe. In this case there is no relative movement between pipe support i.e. shoe and pipe while the pipe displaces due to changes in fluid service temperature inside the pipe. As the pipe expands when temperatures rise inside pipe, it displaces from its mean position of structural support. The shoe having been welded to pipe moves along with the pipe.
On the other hand, shoe type supports on cold service pipes are not directly and permanently connected to pipe. This is due to the fact that the pipe insulation on cold service piping is designed to be seal tight so that outside air cannot get inside the insulation and reach pipe surface where it starts condensation. The condensation in turn causes corrosion issues. To avoid this moist air ingress inside the insulation, the shoes are made of clamp types and are placed outside the insulation cladding. This causes problem of clamp type shoe slippage on cladding and total displacement of pipe shoe from its structural support. This paper presents an engineering study of a piping system with cold fluid service (propane) where multiple supports had fallen from the structural supports or had dislocated considerably. At few support locations, cladding was found to be damaged and ice formation was noticed. In addition, many clamped shoes had rotated as shown in
A comprehensive study was conducted to identify the root cause of piping supports dislocation, displacement and rotation. The static/dynamic stress analysis of the piping system was carried out. The results revealed that the displacements in the piping system were not so high to cause the supports dislocation or high displacements of shoes. In addition, the stresses on the piping system due to the contraction of pipe upon cooling were within allowable limits. Rotated and dislocated Clamp support on Cold Service Pipes
Rotated and dislocated Clamp support on Cold Service Pipes
As a part of study process, operation was enquired if any upset had happened which might have caused the dislocation and abnormal movement of pipe and hence transferred to its supports. Operations informed that there was no such incident and the line had been operating normally without any trouble.
The process study including review of hydraulics, verification of line size and surge was performed to identify the root cause of piping abnormal movement. The process study concluded that line size was adequate and no surge scenario was identified for the line's concerned portion.
So following reasons which could cause abnormal pipe movements and dislocation of supports were ruled out based on above study: Operation upset in the piping system (such as sudden opening or closing of a valve or sudden starting/stopping of a pump), Line sizing or surge flow, Contraction of line due to cooling of piping system or piping configuration.
Operation upset in the piping system (such as sudden opening or closing of a valve or sudden starting/stopping of a pump),
Line sizing or surge flow,
Contraction of line due to cooling of piping system or piping configuration.
The next step in the study was to review the support configuration in detail. Study found basic design problem with the support configuration that was the cause of supports dislocation, excessive movement and rotation of clamped supports.
ENSURING IMPROVED ASSET INTEGRITY by Realtime Corrosion Monitoring and Steam Trap Monitoring
Monitoring of corrosion in a process pipelines have always been of paramount importance to ensure the integrity of plant assets. Similarly, steam traps play a very important role in ensuring steam quality, thereby the integrity of critical assets in the plant. It is common observation that many of the steamtraps become non-functional over a period of time and, more importantly, dangerously go unnoticed. While these are vital in ensuring asset integrity, and need continuous monitoring, it is also a highly demanding and challenging activity in the field, and a dream of many Integrity engineers to perform such asset monitoring remotely, that too, in realtime. Many vendors have been researching on this, and focusing on devising improved technology to ease the burden on such asset monitoring.
This paper intends to touch upon these two aspects of monitoring Asset Integrity – Realtime Corrosion monitoring and Realtime Steam Trap monitoring – as implemented in ADNOC-LNG. The paper shall highlight the importance of digitalization in the Asset Integrity Management - Pipeline Corrosion and Steam Trap monitoring - by means of implementing wireless technology and making the data available in remote workstations in realtime.
Corrosion Monitoring: to move ahead from the conventional Corrosion management to the Wireless Ultrasonic Thickness gauging technology
Steam Trap Monitoring: to remotely monitor the healthiness of Steam Traps with a combination acoustic and temperature instruments.
Corrosion Monitoring: The installation at ADNOC-LNG covers 20 locations in OAG unit (Offshore Associated Gas unit, which has been identified as highly corrosion prone). The procedure involves installing UT sensors at the identified CMLs (Corrosion Monitoring Locations). These are easily installable onto the piping, and each sensor has a measurement footprint of about 1-2 cm2, which is similar to the manual ultrasound inspection method. The technology of ultrasound is well proven and has been used by Integrity engineers for manual inspections. These sensors employ wireless communication, and are powered by battery packs, which last through turnarounds. Doing away with the needs of power and signal cable, simplifies the installation process.
Steam trap monitoring system (20 locations identified in LNG Train-3 Utilities) also employs wireless acoustic and temperature sensors, which are installed on the steam trap piping. From the acoustics and based on the skin temperature measurements, the system identifies the health of the steam traps and determines which are Failed shut, or blow through.
Corrosion Sensors: These UT sensors continue to give the wall thickness measurements of the exactly same point, over a period of time, which can help analyze the early onset of corrosion; unlike the manual UT measurements, where the repeatability and reproducibility of the readings are a challenge, as it is highly unlikely that the consecutive measurements taken after a gap of several months are exactly at the same location, and also it is highly person dependent. The corrosion data is transmitted over wireless, and made available to the desktop workstations of the Integrity Engineers.
Steam traps: Even though steam traps are audited in the plants on a regular basis, such surveys give the performance of the traps for that brief period of time (snapshot information), whereas, continuous steam trap monitoring provides information on the health of the traps on a continuous basis, that too, made available to the desktop workstations of the Operations/Maintenance engineers. It thus enables them to take early decision, and avoid costly failures of equipment/piping etc., and also, the avoid the loss of precious energy by ensuring timely maintenance.
Wireless technology is easily scalable and hence, further additional sensors can be installed across the plant, without much capital outgo. With the thrust on Digitalization, our efforts should be focused on leveraging the benefits of technology.
Building accurate reservoir models can be quite challenging, especially highly stratified thick intervals in hydraulic communication in reservoir. Presented methodology is based on comprehensive Interval and Interference Pressure Transient Testing (IIPTT) for classified reservoir types with a systematic approach. Classification of reservoir types is based on layering, thickness, and hydraulic communication of layers in the reservoir. The methodology describes building more accurate anisotropic reservoir models, providing well performance assessment based on integrated comprehensive IIPTT solving with efficient nonlinear parameter estimation and modeling with numerical simulation for different reservoir types. The number distributed IIPTTs are optimized to ensure to achieve coverage across total thickness depending on the reservoir type. It is demonstrated that high resolution accurate reservoir models can be built for relatively thick highly layered reservoirs in a feasible manner.
Poreddiwar, Nitesh (National Petroleum Construction Company, UAE) | Singh, Bhupinder (National Petroleum Construction Company, UAE) | Singh, Harendra (National Petroleum Construction Company, UAE) | Kamal, Faris Ragheb (National Petroleum Construction Company, UAE) | Takieddine, Oussama (National Petroleum Construction Company, UAE)
In Oil & Gas facilities, emergency depressurization is a prime mitigation to reduce risk to personnel/assets during fire and avoids catastrophic failure. The conventional approach considers standard criteria for vessels/pipes for establishing depressurization rates without assessing dynamic stress changes due to actual material properties/thicknesses. The paper discusses latest API approach of Fire Response Analysis (FRA), which evaluates rupture possibility, consequences and mitigation to ensure the integrity of process/flare system and establishes more accurate depressurization rates.
The conventional approach considers depressurization to 50%/100 psig in 15 minutes for material thicknesses one inch & above and faster depressurization for thicknesses below one inch. As standard engineering practice, depressurization of facilities in 15 minutes is normally followed irrespective of material thickness. Latest API approach determines depressurization rate based on FRA, which accounts transient thermo-physical properties along with heat transfer and consider reduction in material strength when exposed to fire. FRA is an exhaustive study requiring detailed inputs such as type of fire, fire duration, heat flux, rupture acceptance criteria, in addition to inputs considered in conventional approach.
Emergency depressurization rate in FRA Study is established based on adequacy of ultimate material tensile strength against the stresses developed under fire scenario. In house case studies compare the results of emergency depressurization rates based on FRA Study and conventional approach for various isolatable system of process complex. Emergency depressurization rates in FRA Study are found to be dependent on material thickness as well as tensile strength and usually results in lower or higher than 15 minutes to ensure vessel/pipe survivability.
FRA Study follows a multi-discipline approach to conclude depressurization rates based on various parameters such as acceptability of facility rupture consequences, search/rescue time of field personnel. If rupture criterion is not acceptable from Safety Risk Analysis, FRA study re-establishes the emergency depressurization rates by accelerating the depressurization rates and/or increasing vessel/pipe thickness and/or providing Passive Fire Protection (PFP).
FRA study results are utilized to finalize emergency depressurization / blowdown line sizes including Restriction Orifice (RO) size, flare headers sizes and flare system design capacity. RO sizes per FRA Study are utilized to finalize the non-fire case blowdown and minimum metal design temperature of facilities.
NPCC has executed many Oil & Gas projects involving flare system. This paper discusses the challenges and "Lessons Learned" by EPC Contractor in applying new FRA approach to ensure integrity of safety critical systems through case studies from recent project. The paper also highlights the benefits of FRA study including effective utilization of existing flare spare capacity and proposes way forward to assist Operators in decision making process for up-gradation of existing facilities.
Zohr subsea production system (Accelerated Start Up Phase) is made by 6 wells connected via individual rigid production infield flowlines to two chained Main Subsea Structures. Gas is exported to onshore El Gamil plant through a piggable export sealine connected to the one of the two Main Subsea Structures.
In total 218 km of pipes 30inch to Zohr onshore plant El Gamil pipeline. Pipeline material and dimension combination required for the Zohr project is unique in its kind and the combination of requirements has not been produced before, with demanding mechanical and corrosion tests and a new limit for pipeline exposed to sour service.
A certain number of Buckle arrestors (107 pieces) have been used along pipeline installation. The BAA are around 12 m long and are integrated by three sections; The central sections of thickness (75.8, 66.0 and 54.0mm) are seamless forged pieces produced with ASTM A707 Grade L5 Modified steel in quenched and tempered condition with mechanical properties equivalent to API 5L L415QS / L415QO material. The pup pieces are API 5L LSAW pipes Grade L415MS / L415MO.
During Manufacturing Process Qualification Testing (MPQT) Sulphide Stress Cracking Corrosion Test (SSC) have shown some cracks of test specimens. The specimen fails and SSC cracks were found in the post test analysis, i.e., by sectioning and performing metallography at X100. These specimens were tested in NACE TM0177 type A solution with 5% NaCl and 0.5% acetic acid, saturated with 1 bar H2S at an initial pH of 2.7. Exposure duration was 720 hours and the load to be applied was 90%. No indications or defects were assessed by NDT magnetic particle inspections on all the tested specimens.
Weld overlay of buckle arrestors assemblies (BAA) with alloy N06625 (nominal thickness 3 mm) cover the full length of the central section plus the circumferential welds (that are ground flush) and extending 100 mm on each side of the girth welds into the pup pieces.
It was a challenge to overcome these defect of these pipes considering the stringent requirements in the project specifications and the tight project schedule to achieve the installation campaign without any delay on project schedule.
The Optimized Ramp-Up phase envisages an extension of the Accelerated Start Up subsea system with four (4) additional wells, a new Main Subsea Structure (MSS3), a new Subsea Distribution Unit (SDU) and a piggable export pipeline (30" OD), parallel to the 26" Accelerated Start Up Phase (ASU) export line.