Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
Wang, Cynthia (Keppel Offshore & Marine Technology Centre) | Quah, Matthew (Keppel Offshore & Marine Technology Centre) | Noble, Peter G. (ConocoPhillips) | Shafer, Randall (ConocoPhillips) | Soofi, Khalid A. (ConocoPhillips) | Alvord, Chip (ConocoPhillips Alaska Inc.) | Brassfield, Tom (ConocoPhillips Alaska Inc.)
Jack-up drilling units have been used in Arctic open water seasons and areaswith icebergs. They have not been used in areas where significant sea ice canmove in with high concentrations. These areas have typically been drilled usinga floating mobile offshore drilling unit (MODU) although the water depths aretypically less than 50 meters. Floating MODUs in shallow water depths can havesignificant downtime due to the limited offset in shallow water and typicallyrequire placing the well control equipment in a seabed cellar. In these areas,jack-ups can improve both operational safety and efficiency as they havelimited weather related downtime.
Several studies were carried out to determine the feasibility of using amodern high capacity jack-up MODUs for exploratory drilling in these areas.This paper will review the studies including structural analysis, icemanagement approaches, and well control considerations. It will also review thefurther potential of jack-ups in the Arctic.
Studies showed that using a jack-up drilling unit is feasible in shallowArctic seas such as the Chukchi Sea when coupled with an effective icemanagement system. The jack-up unit has sufficient ice resistance to withstandinteraction with thin early winter ice. Specific designs of jack-ups arecapable of taking impact forces from thicker ice floes that may occur during anice incursion event during the open water season. The maximum floe size duringan ice incursion is limited and controlled by the associated icemanagement system.
An ice management system was developed using a combination of satelliteimagery, ice management vessels, and ice alert procedures. This system wasdetermined as effective in managing ice to allow the jack-up to operate in theChukchi Sea area.
Environmental and personnel safety is enhanced by the use of aPre-positioned Capping Device, an in place source control device. The device isindependent from the rig's well control system and provides another level ofprotection in additional to the jack-up's BOP.
The conclusion, based on structural and ice management studies, is thatmodern high capacity jack-up drilling units can be an effective way to drillwells during the open water season in shallow waters of Arctic seas includingareas in to which sea ice can move. The studies also show that there ispotential for use in other areas.
The number of azimuth thrusters configured for ice conditions is constantlyincreasing. This is due to the common tendency of widening the range ofoperation of a particular ship in terms of weather conditions, operating modesand geographical areas to achieve more business opportunities throughout theoperating life of the ship. The other major factor is the large potential foroil and gas in the arctic waters. It is also estimated that the number oficebreakers using azimuth propulsion will increase in the near future as theexisting fleet will be modernized and new vessels are built.
The new PC rules have recently been introduced and that has changed theclassification process significantly. Although being clearly more accurate, thenew rules require much more calculation work and have several parametersrelated to the thruster itself.
A first Azimuth thruster has now been classified according to the new PCrules. The thruster, type UUC 505, was originally classified according to DetNorske Veritas Ice-10 ice class which represents an ice class (at the lighterend) for arctic conditions. The thruster was then subsequently classifiedaccording to Det Norske Veritas PC4 ice rules.
The purpose of this presentation is to highlight the practical issues andthe increased workload that the new PC rules have brought on to theclassification process. Also it will highlight some points in the rules whereclarification is needed.
The traffic volumes in arctic waters are expected to grow rapidly in thenear future. New fleets of oil and LNG carriers as well as ice classeddrillships and offshore supply vessels and icebreakers with high ice-class areneeded for the transportation and oil exploration. The recent growth inactivities in the Arctic region has materialized in several projects, whereAzipod propulsion system is playing an important role in making the projectstechnically possible and economically feasible. Azipod propulsion offers a veryattractive and efficient propulsion solution for most of these vessels.However, there is an evident need for azimuthing propulsion units with power inexcess of 15 MW with highest ice classes, such as the "new" IACS PC1.
In response to the market demand ABB Marine has recently developed an Azipodpropulsion concept with high power to meet the requirements of the high arcticice classes.
This paper will outline some important design considerations during thedevelopment work, such as:
-different ice class rule requirements
-need for overload / overtorque capacity of the electric propulsion motor inice
-utilisation of measurements from full-scale ice trials with poddedpropulsion
High power Azipod propulsion systems help the shipowners to accessopportunities in the Arctic areas by providing safe and reliable operation inthe region. With ABB electric propulsion and Azipod units, the shipowner getsequipment designed to meet the demanding Arctic requirements and which isproven to be reliable in ensuring safe navigation in the sensitive Arcticseas.
In light of the recent increasing interest in the oil and gas developmentsin the arctic region, Huisman Equipment B.V. has developed a Mobile OffshoreDrilling Unit (MODU) named JBF Arctic suited for arctic condition. The stationkeeping in ice is one of the crucial factors determining the feasibility of thedesign. As one of the first steps of the design process ice model tests wereperformed at the Krylov Shipbuilding Research Institute (KSRI) to gain insightin the ice forces acting on the unit. During the model tests the model of theJBF Arctic was retained in a fixed position while being towed through the ice.In reality the station keeping of the unit will be ensured by a mooring system,which has certain flexibility compared to the rigid constrains in the modeltests. This paper elaborates on the creation of a numerical model that canperform time-domain simulations of the dynamic interaction between the vesseland the ice-loads. Using these simulations the mooring system is optimized inorder to cope with the ice loads corresponding to unbroken level ice withthickness up to 3.1m. Several important conclusions were drawn. One is the factthat no dominating frequencies of the ice failing could be identified from themodel tests. This can be explained by a large ratio between the diameter of theunit and the ice thickness. So the ice failure mechanism has a chaoticcharacter. Another conclusion is that the unit does not exhibit significantdynamic behavior. This means that a quasi-static approach can be generally usedfor initial design of the mooring system.
Keywords: ice model test, dynamic ice-structure interaction, ice loadingmodel, mooring system optimization, Arctic MODU.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger)
The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen?? and "lower inter-bedded kerogen-carbonate?? in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.
A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.
No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf?? geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.
The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
Reliable sonic and density logs are needed for calibration of seismic data for use in reservoir characterization, and for specialized AVO and 4-D analysis. Due to the small depths of investigation of sonic and density logging tools, measured logs are affected by borehole washout and mud filtrate invasion. In many wells, particularly older ones, density and shear sonic logs were acquired within limited depth sections, or not at all. To address these various log quality issues and make the logs suitable for use with seismic data, appropriate log editing must be done, and missing logs or log sections must be synthesized. In addition, complex waveforms measured by modern sonic logging tools must be processed before they can be used for geophysical analysis, a step often ignored by geophysicists.
Our paper presents a sequential workflow to address sonic and density well log quality issues for approximately one hundred wells penetrating multiple carbonate reservoirs within a supergiant field from the Middle East. Borehole washout problems are frequent in the shales that overlie the main reservoir of the field, resulting in poor sonic and density log measurements. Within the reservoirs, high salinity filtrate invasion that displaces light oil affects both sonic and density log measurements. To address these issues, we developed a well log conditioning workflow that involves the following steps:
- Processing of sonic logs from wells with dipole sonic measurement
- QC of all well data, and selection of wells with optimal logs for building a training data base
- Generation of missing data using multi-variate statistical analysis
- Correction of borehole-related anomalies
- Correction for invasion effects
- Validation against VSP and seismic data.
Results of log conditioning have improved well-seismic ties. In many cases these ties confirm the presence of residual interbed multiples within the 3D seismic data that covers the field. Modeling of fluid effects during invasion correction shows acoustic impedance to be sensitive to both porosity and fluid effects: up to 9% change occurs in acoustic impedance due to invasion-related saturation changes. Such saturation-related effects suggest the feasibility of 4D seismic as a surveillance tool in future FDP of the carbonate reservoirs in this field.
The safe loading/unloading of LNG tankers depends on high integrity communications links between the tanker and shore systems to ensure the fail-safe operation of a two way shut-down signal.
The most common existing system is fiber optic cable-based and was developed in the 1980s. While it has the advantage of simplicity and reasonable reliability, it fails to meet the changing requirements of LNG tanker operations. A more flexible system is overdue.
Our company in cooperation with international telecommunications solutions providers is developing a microwave-based system that addresses the shortcoming of the existing system. Importantly, by having the potential to shave a few hours off loading and unloading times, more shipments can be delivered from existing terminals.
The proposed system utilizes the same standards-based fiber optic multiplexing equipment currently popular with LNG plants, integrates it with carrier-grade microwave radios and automatic antennae alignment units to allow automatic connectivity while the tanker is approaching the jetty. The advantages of this approach are,
Transformers are important components of the High Voltage electrical grid and electrical power installation in industrial plants such as the petroleum industry.
In case of an unexpected failure the possibility to reduce the outage time is usually of prime importance. It allows the plant manager to minimize financial impact due to loss of production.
In this paper we will describe transformer condition assessment methodologies as well as on-site repair solutions as means to increase both the reliability and availability of transformers.
Over the last decade there has been an increasing interest in transformer life evaluation and monitoring. The main reason is that a large number of the transformers world population is approaching its expected end-of-life and the need increases for better methods to see whether the transformers are still fit for use or need to be retrofitted or replaced.
The diagnosis of the transformer condition is used to recommend maintenance actions and identify defects even before un-tanking the transformer. It allows therefore to reduce unexpected failures and anticipate to reduce repair time especially when transformers are repaired at site.
Repairing at site usually allows bringing transformers back in service within a shorter time by avoiding transportation from the site to the factory and return. Also it reduces costs and risks associated with heavy transport.
To date more than 400 transformers including utility, industrial, HVDC transformers and reactors have been successfully repaired on site. In many cases transformers were upgraded to provide an increased rating.
Al Marzouqi, Ayesha Rahman (Abu Dhabi Co. Onshore Oil Opn.) | Keshka, Ashraf Al-saiid (Abu Dhabi Co. Onshore Oil Opn.) | Bahamaish, Jamal Nasir (Abu Dhabi Co. Onshore Oil Opn.) | Aslanyan, Arthur (TGT Oil & Gas Services) | Aslanyan, Irina (TGT Oil & Gas Services) | Filenev, Maxim (Kazan State University) | Andreev, Alexey (TGT Oil & Gas Services) | Sudakov, Vladislav (TGT Oil Co.) | Farakhova, Rushana (ADCO Producing Co. Inc.) | Barghouti, Jamal | Al Junaibi, Tariq Abdulla
Today, geological and hydrodynamic models are widely used for efficient development and monitoring of oil and gas fields. These models are designed to handle a wide range of tasks. Their reliability directly affects the quality of results and any uncertainties should, therefore, be minimised. The use of additional techniques can enhance the reliability and predictive ability of the models and minimise risks. This paper describes how integrating accurate description of flow geometry with reservoir properties and reservoir models to achieve this objective and, to generate a more reliable picture of the reservoir performance. The study included running HPT-PLT-SNL high precision logging tools, and covered a pilot area with five wells in a Cretaceous carbonate reservoir. The wells were completed in the lower and tighter Sub-reservoirs units F1 and F2 and the objective of this pilot is to identify the flow geometry in wells' neighborhood, particularly identify channeling, fracture flows or other types of communication. The objective of the associated simulations and study is to correlate the acquired and interpreted data with those suggested by simulations and come up with consistent description of reservoir flow geometry within the pilot pattern.
The most challenging point of this flooding campaign is the complexity of the reservoir in this area. The flooding pilot sets the targets for tight Sub-reservoir carbonates Unit F1 and Unit F2. It's important to know if the flow ensues exactly within these units and does not communicate with other reservoirs with better permeability.
The subject study, Abu Dhabi's Cretaceous carbonate reservoir is combined of five sub reservoirs and they are as shown in figure 1 below, Units F5, F4, F3, F2 and F1. All five sub-reservoirs are of different characteristics in terms of permeability, porosity, rock type, etc. (As shown in Table 1 and Fig. 1). Those sub-reservoirs are lying on top of each others almost without any barriers between them; accordingly, this might provoke the water/gas to cone/slump to/from the concerned reservoirs.
A project is in progress to decide on the development of the tight reservoir (F1+F2) to further improve the poor sweep efficiency, increase the oil recovery in both reservoirs, water slumping, inefficient flank pressure support, vertical permeability between sub-reservoirs, assess the impact of injecting in Units F1+F2 on fluxes across Units F3, F4, F5 and F1 and F2, determine pressure support due to injection in Units F1 and F2, and overlying units.