Facility designs consider common acid gas flare for multiple plants operating in the complex, based on cost optimization considerations. Such designs involve common Flare KOD, which is difficult to maintain, as multiple plant shutdowns are not feasible during shutdown planning. Common stand-by Flare KOD with suitable isolation provisions from different plants’acid gas headers ensures timely maintenance and thus enhances the sustainability of the Acid Gas Flare Operations.
Due to presence of high levels of acid gases with moisture, acid gas flare streams tend to be highly corrosive. This poses safety threat to operating personnel, by loss of containment of toxic gas from vessel rupture or possible toxic gas leaks through KOD flanges. This situation was encountered in one of the GASCO operating complexes, where 2 existing plants shared a common flare KOD and a third existing plant via a different KOD was connected to the same acid gas flare.
Original design envisaged maintenance of the acid gas flare by inter-connection with one of the existing hydrocarbon flares but safe inspection of the acid gas flare KODs could not be conducted. Non-intrusive ultrasonic scanning indicated severe corrosion in one of the existing KODs at various positions. However, due to absence of proper isolation facilities, internal inspection / replacement of the existing KODs was not possible without a total shut-down, which was not permissible.
To overcome the problem, a standby flare system was studied to improve operational and maintenance flexibility, but was not implemented due to costs that were considered excessive. Instead, a more cost-effective solution based on installation of a standby KOD was implemented to address the critical Process safety issue. For installation of the new facility without any plant shutdown, several hot taps were required on the flare header.
Implementation of the Standby KOD costed less than USD 8 Million, substantially less than the estimated cost of around USD 100 Million for Standby Flare project, while providing the desired level of operational and maintenance flexibility.
Also, subsequent to the installation of the Standby KOD, an existing flare KOD, experiencing severe wall thinning due to corrosion, could be replaced without any plant shutdown. Reliability of existing acid gas flare KODs to resist toxic gas leaks has now improved with routine internal inspections.
Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Lavenu, Arthur P. C. (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Hinkley, Richard (Halliburton) | Crockett, Steven (Halliburton) | Bedewi, Mahmoud (Halliburton)
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex logderived saturation distribution.
Singh, Sunil Kumar (Kuwait Oil Company) | Nath, Prabir Kumar (Kuwait Oil Company) | Al-Ajmi, Afrah Saleh (Kuwait Oil Company) | Bonin, Aurélie (Badley Ashton and Associates Ltd) | de Periere, Matthieu Deville (Badley Ashton and Associates Ltd) | Hirani, Jesal (Badley Ashton and Associates Ltd) | Dey, Arun Kanti (Kuwait Oil Company) | Al-Khandari, Eman Mohammed (Kuwait Oil Company)
The Lower Cretaceous Minagish Formation forms one of the most prolific oil reservoirs in onshore Kuwait, with key reservoir units located in thick oolitic grainstones forming the lower half of the Middle Minagish Member. Within the central and eastern part of Kuwait, the upper part of the Middle Minagish consists of inner ramp skeletal packstones, that are variably cemented, for which the reservoir potential is poor. Following exploration campaigns carried out by KOC in the unexplored southwestern area of Kuwait, unusual oil staining has been observed in the uppermost part of the Middle Minagish Member highlighting a potential new hydrocarbon play. As part of a multiwell study investigating the Middle and lowermost Upper Minagish Members cored in southwestern Kuwait, this work focuses on understanding the occurrence of hydrocarbon stained deposits within the uppermost Middle Minagish and assesses their extent. The study aims to characterise the sedimentological makeup and analyse the field-scale depositional organisation to assist in the prediction of reservoir architecture. A facies analysis has been carried out and has resulted in the interpretation of the depositional environments. The key surfaces characterised in core along with openhole log data have helped in the interpretation of a sequence stratigraphic framework across both the reservoir and non-reservoir units. The facies analysis and vertical facies evolution across the cored Minagish succession suggest deposition in an intertidal to marginal/proximal mid-ramp setting, with the development of oolitic geobodies both in a marginal shoal corridor and sand bars formed in a more landward position on the inner ramp. The more proximal sand bars are typically recorded in the southwest Kuwait area and are not present further towards the east (e.g.
Processing associated and non-associated gas, GASCO operates 3 desert plants for gas processing and natural gas liquids (NGL) extraction, a Natural Gas Liquids Fractionation facility and a pipeline distribution network. GASCO plays a strategic role in the ADNOC and UAE hydrocarbon chain, which makes it a vital enabler of industrial and economic progress of UAE. Gas yields substantial revenues from exports and is key for the country's electricity generation and water desalination. In a carbon constrained world, interest in its use is growing rapidly by all users, whether residential, commercial or industrial. As GASCO delivers on its responsibility as an economical and sustainable supplier of gas and related products, it seeks to drive operational excellence by focusing on people, performance, profitability and efficiency.
Over the past several decades, ADNOC has adopted increasingly strict clean air regulations. ADNOC Code of Practice (CoP) stipulates that the Sulphur dioxide (SO2) and carbon monoxide (CO) emissions limits from Sulphur Recovery Units (SRU) (categorized as material producing industry) is restricted to 2000 mg/Nm3 (700 ppmv) and 500 mg/Nm3 (400 ppmv) respectively.
GASCO Habshan plant existing SRUs are not designed to meet the current ADNOC CoP emissions requirements.
This paper explores all possible options for SO2 and CO emission reduction from Habshan complex SRUs along with cost associated with each option.
Habshan Complex SRU's Licensors (B&V and Jacobs) and an independent third party consultant were approached to identify the all possible options for SO2 and CO emission reduction.
Sulphur Recovery Efficiency (SRE) of above 99.5% is required to achieve SO2 emission of 2000 mg/Nm3 (700 ppmv). This can be achieved only by installation of either Amine based TGTU or Caustic Scrubbing Unit. Estimated Capital Cost for installation of such units is approx. US$ 230 MM for all the SRU's in Habshan i.e. U-52/53/54/57/58/59/152/153 (except U-50/51). Also, as sulphur recovery efficiency increases, the energy required to remove each additional kilogram of sulphur escalates. As energy consumption increases, so too do CO2 emissions, which is an undesirable outcome.
Similarly, CO emission levels can be achieved by 1) Operating the incinerator at higher temperature or 2) by Installation of hydrogenation reactor upstream of incinerator for tail gas treatment or 3) by Incinerator modification/replacement.
Operating Incinerator at higher temperature will lead to increase in fuel gas consumption and consequently increased CO2 release from stack. Estimated increase in operating cost for incinerator operation at Higher Temperature is approx. US$ 3 MM/yr (at current capacity).
Installation of Hydrogenation rector will incur significant capital cost. Estimated Capital Cost for installation of hydrogenation reactor is approx. US$ 45 MM for all the SRU's in Habshan i.e. U-52/53/54/57/58/59/152/153 (except U-50/51).
Incinerator modification / replacement will cost approx. US$ 4-5 MM for each incinerator.
This paper explores all possible options for SO2 and CO emission reduction from Habshan complex SRUs along with cost associated with each option. It also investigates energy consumption and associated CO2 footprint with each option.
Taking into consideration ADNOC's strategic areas on performance, profitability, efficiency and people, one of GASCO's focus is to optimize and improve the efficiency of the existing equipment, particularly to those of more than 20 years in operation. Among these equipment are two trains of 3-stage Claus Sulphur Recovery Units in Habshan-0 Plant, considered to be the oldest, in which a study was conducted to explore different possible upgrading options.
Units-50 and 51 are two units among eight other SRUs in Habshan Complex. These units are a 3-stage Claus SRUs in Habshan-0 Plant having a maximum recovery efficiency of around 97% and are a major source of excessive SO2 emissions.
A study was carried out to identify the units' requirement and to upgrade the recovery level to a minimum of 99.0% for future use. The study identified the required modifications (equipment, piping, instrumentation, etc.) and its impact on the existing equipment and facilities for the options considered: (1) Conversion of the third catalytic Claus stage in each SRU train to a Selective Oxidation Stage (2) Addition of a new Selective Oxidation Stage in each SRU and (3) Addition of a new Selective Oxidation Stage common for both SRU-50 & 51.
The three options were studied for revamping of SRUs-50 & 51 from Claus to SuperClaus. Several factors were considered in studying each option such as the plot space available in Habshan-0, operating capacity, complexity with respect to safeguarding and maintenance, utilities requirements inside SRU, additional equipment, required CAPEX, etc.
Due to a high CAPEX requirement, option 3 was not further evaluated and considered to be non- feasible. Options-1 and 2 were further evaluated; detailed investigation of option-1 resulted in a lower expected Sulphur Recovery Efficiency (SRE) in comparison with that of option 2, consequently it was withdrawn as it does not meet GASCO's requirement for a minimum 99.0% SRE.
Option-2 (Addition of a new Selective Oxidation Stage in each SRU) on the other hand provided the expected SRE of 99.15% (guarantee is 99.0%) Start of Run (SOR) / 98.94% (guarantee is 98.9.0%) End of Run (EOR) hence proved to be the best techno-economical feasible solution for upgrading the SRUs.
Cadours, Renaud (Abu Dhabi Gas Industry Ltd) | Al Katheeri, Sara (Abu Dhabi Gas Industry Ltd) | Al Matroushi, Mohamed Salem (Abu Dhabi Gas Industry Ltd) | Ghazaly, Ayman (Abu Dhabi Gas Industry Ltd) | Sayegh, Salem (Abu Dhabi Gas Industry Ltd)
The GASCO industrial complex is constructed to process Natural Gas Liquids (NGL) from associated and natural gas. The liquids collected from Asab, Bu-Hasa and Habshan plants is transfer by pipeline to the Ruwais plant for further fractionation before supply to local end-users or other customers. The sweetening processes are critical steps in the GASCO complex to guarantee plant and operators safety, to comply with customers’ specification and to minimize the industrial impact on the environment. In this way, GASCO is continuously considering improvement of the processing plants, especially to minimize the sulphur emissions in the environment.
A significant part of the sulphur emission from the Ruwais plant are resulting from the operation of the molecular sieves used for mercaptans removal from propane and butane products. During regeneration step of these molecular sieves, the adsorbed mercaptans are concentrated in the regeneration gas. Combustion of this gas without treatment is resulting in a significant part of the sulphur emission.
This papers presents a detailed review of the best available technologies for mercaptans removal. Two options are discussed: treatment of the molecular sieves regeneration gas and mercaptan removal at upstream NGL extraction plants. Molecular sieves and hybrid solvent technologies are considered. The paper presents pro and cons of all the alternatives, considering the constraints of the existing GASCO industrial complex: units’ configuration, disposal or recycle of the mercaptan.
This paper presents an independent review of technologies for mercaptans removal, from the GASCO operational point of view. It summarizes the benefit and the constraints of each technology, and their impact when implemented in an existing complex.
The Habshan 5 Process Plant (H5PP) is one of the four packages that constitute the GASCO Integrated Gas Development (IGD) Scheme. The JGC-Tecnimont Joint Venture was awarded the EPC phase. The project was completed on schedule within 50 months, and the plant was successfully handed over in September 2013. One of the key contributions to the smooth plant commissioning and start-up is the choice made by the JGC-Tecnimont JV and GASCO for fluid contamination control. In the form of liquid aerosols and solid particles, contamination in process gases and liquids represents a major contributor to operation issues in gas processing units, such as foaming. A strategy for fluid cleanliness control was implemented to keep fluids clean: supported by PALL from the design phase, the specification and the selection of filter and coalescer technologies at critical contaminant-challenged locations were made carefully. Appropriate activities during prefabrication, precommissioning and commissioning phases were implemented to minimize contamination from installed equipment. Performance tests carried out at start-up on the main coalescer and filter equipment confirmed that clean process fluids were delivered and compliant separation efficiencies were achieved.
In 1997-99, Abu Dhabi Company for Onshore Oil Operation (ADCO) acquired and processed a 96-fold 3D seismic land survey over one of its giant onshore oil fields. Subsequent interpretation work highlighted the need to improve seismic data quality to better image fault corridors that were identified and mapped across the field. Attenuation of multiples and other types of coherent and incoherent noise and mitigation of the impact of the near-surface layer on statics and amplitudes were identified as key areas for improvement. Consequently, the 1999 3D seismic survey was reprocessed in 2009 with the aim of improving the signal to noise ratio and enhancing resolution of the reservoir interval with a special focus on strike-slip faults and related features such as fault displacements. Advanced and careful processing, including elastic modeling and adaptive subtraction of surface waves, wavelet processing, several iterations of static solutions, and surface-related multiple attenuation helped achieve optimum quality of the final seismic image. Additional seismic outputs such as angle stacks, image gathers and azimuthal stacks were also produced for the purpose of performing advanced geophysical interpretation work such as seismic anisotropy analysis, inversion and AVO. Preliminary analysis of azimuthal volumes in a pilot area gave indications of seismic anisotropy related to the main directions of faulting trending N75W and N45W. Seismic reprocessing sharpened the imaging of strike-slip faults and clarified depositional features in the southern part of the field. Coherency extractions were also successful in imaging strike-slip fault extensions. The new seismic images were of substantial benefit to ADCO's program of drilling horizontal wells targeting thin reservoir intervals of 10 feet thickness or less. Prediction of potential faults and their associated throws was critical to ensuring correct well placement during the design and drilling phases.
Wireline formation pressure testing has been routinely used as a valuable reservoir characterization tool and its results are generally well regarded. On the other hand, LWD formation pressure testing, initially introduced primarily as a drilling safety and ECD optimization tool, has yet to fully prove its effectiveness in reservoir evaluation, due to perceived data acquisition challenges. Today, re-entry drilling is used in many aging oil and gas fields to target the remaining hydrocarbon. Formation pressure, fluid gradients and the determination of whether or not compartments are in communication are important information when analyzing such a reservoirs in real time for optimum wellbore placement. The cost efficiencies of acquiring formation pressure data while drilling are becoming more influential in the operator’s technology selection process, but should not come at the cost of reduced data accuracy or usability.
This paper discusses new techniques and technologies that facilitate gaining a better understanding of the subsurface while drilling. These include a smart test function, which reduces formation shock while pressure testing in microDarcy formations and avoids sanding in highly unconsolidated formations. Performing optimized test sequences improve the accuracy of the pressure and mobility data and lead to higher operating efficiency. Also, LWD pressure testing on wired pipe yields a data density previously only found on wireline. The introduction of extended test times of up to 40 minutes increases the scope of LWD pressure testing into traditional formation pressure testing applications, such as compartmentalization evaluation or fluid gradient analysis. Longer test times and testing on wired pipe precede future fluid sampling while drilling. Benefits for drilling and subsurface teams are equally important and the reason why LWD formation testing has become a cross-functional discipline. Case Histories from the United Arab Emirates (UAE) and Asia Pacific will be used to highlight the recent technology advances and applications.
Dubai Petroleum Establishment (DPE) was initiated in 2007 when some of the very first oil field concessions were handed back to the government of Dubai. The first concession was obtained and held by Dubai Petroleum Company (DPC) in 1961. ConocoPhillips, Total, Repsol YPF, RWE Dea and Wintershall also operated the fields in subsequent concessions and helped building the new Dubai. After a development and production period lasting more than 40 years, fields like Rashid and Falah were still producing effectively and economically. For future production plans, formation pressure is an important tool in calibrating the reservoir model, and the obtained mobility is a good indication of whether the formation matrix has potential for producibility of the fluids. The present use of a Formation Pressure testing LWD tool is mainly to identify depleted reservoir packages, and reservoir continuity. The ability to do this while drilling greatly reduces the costs and risks of the operation.
The carbonate reservoirs in offshore Dubai are characterized by complex textural heterogeneity. This leads to a permeability variation that is the controlling factor in reservoir production.