At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
Hassan, Hany Mohamed (Petroleum Development Oman) | Al-hattali, Ahmed Salim (Petroleum Development Oman) | Al Nabhani, Salim Hamed (Petroleum Development Oman) | Al Kalbani, Ammar (Petroleum Development Oman) | Al Hattali, Ahmed (Petroleum Development Oman) | Rubaiey, Faisal (Petroleum Development Oman) | Al Marhoon, Nadhal Omar (Petroleum Development Oman) | Al-Hashami, Ahmed (Petroleum Deveopment Oman)
A cluster area "H" consists of 4 carbonate gas fields producing dry gas from N-A reservoir in the Northern area of Oman. These fields are producing with different maturity levels since 1968. An FDP study was done in 2006 which proposed drilling of 7 additional vertical wells beside the already existing 5 wells to develop the reserves and enhance gas production from the fields. The FDP well planning was based on a seismic amplitude "QI" study that recommended drilling the areas with high amplitudes as an indication for gas presence, and it ignored the low amplitude areas even if it is structurally high. A follow up study was conducted in 2010 for "H" area fields using the same seismic data and the well data drilled post FDP. The new static and dynamic work revealed the wrong aspect of the 2006 QI study, and proved with evidence from well logs and production data that low seismic amplitudes in high structural areas have sweet spots of good reservoir quality rock. This has led to changing the old appraisal strategy and planning more wells in low amplitude areas with high structure and hence discovering new blocks that increased the reserves of the fields.
Furthermore, water production in these fields started much earlier than FDP expectation. The subsurface team have integrated deeply with the operation team and started a project to find new solutions to handle the water production and enhance the gas rate. The subsurface team also started drilling horizontal wells in the fields to increase the UR, delay the water production and also reduce the wells total CAPEX by drilling less horizontal wells compared to many vertical as they have higher production and recovery. These subsurface and surface activities have successfully helped to stabilize and increase the production of "H" area cluster by developing more reserves and handling the water production.
Heavy crude oils and diluted Bitumen ( DilBit ) continue to be a challenge to dehydrate and desalt for the Oil & Gas Industry. These challenges include reduced crude oil / formation water density difference, higher crude oil viscosity and often smaller water droplets due the production techniques used for heavy crude oil production.
The traditional remedy to the above challenges often leads to high operating temperatures, large dosages of demulsifier chemicals, equipment fouling, production upsets and use of very large treaters. This leads to both higher operating expenditure ( OPEX ) as well as higher capital expenditure ( CAPEX ).
Other challenges include higher crude oil conductivity and increased crude oil emulsion viscosity formed by higher water cuts. Typically crude oil dehydration vessels use heat, retention time and AC type electrostatic dehydration technology. The AC technology produces limited voltage gradients and is not efficient for treating conductive crude oils, leading to the use of very large vessels and power units. For AC technology, the use of lower voltage gradient may be preferred.
The use of combined AC / DC electrostatic technologies provides high bulk water removal efficicency in the weaker AC field combined with higher removal efficiency of small water droplets in the stronger DC field. Further improvements include amplitude modulated electrostatic fields, high frequency AC fields, improved electrode configurations as well as improved fluid distribution inside the electrostatic treaters.
More efficient dehydration and desalting processes provide potential for operating the treaters and desalters at lower operating temperatures and reduced dosage of demulsifier chemicals, in addition to the potential for using smaller treaters.
This paper describes potential lowered OPEX for crude oil dehydration and desalting processes, using advanced electrostatic dehydration technologies, efficient test methods for optimized use of production chemicals and selection of electrostatic technologies, including case studies.
The significance of exploring deep and ultra-deep wells is increasing rapidly to meet the increased global demands on oil and gas. Drilling at such depth introduces a wide range of difficult challenges and issues. One of the challenges is the negative impact on the drilling fluids rheological properties when exposed to high pressure high temperature (HPHT) conditions and/or becoming contaminated with salts, which are common in deep drilling or in offshore operations.
The drilling engineer must have a good estimate for the values of rheological characteristics of a drilling fluid, such as viscosity, yield point and gel strength, and that is extremely important for a successful drilling operation. In this research work, experiments were conducted on water-based muds with different salinity contents, from ambient conditions up to very elevated pressures and temperatures.
In these experiments, water based drilling fluids containing different types of salt (NaCl and KCl) and at different concentrations were tested by a state-of-the-art high pressure high temperature viscometer. In this paper, the effect of different electrolysis (NaCl and KCl) at elevated pressures (up to 35,000 psi) and elevated temperatures (up to 450 ºF) on the viscosity of water based mud has been presented.
The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap.
In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.
Gadd, Peter E. (Coastal Frontiers Corporation) | Leidersdorf, Craig B. (Coastal Frontiers Corporation) | Hearon, Greg E. (Coastal Frontiers Corporation) | McDougal, William G. (Oregan State University)
Eighteen artificial (man-made) islands have been constructed in the AlaskanBeaufort Sea to support oil exploration and production. The first islands,constructed in the late 1970s, were in shallow nearshore waters where wave andice conditions are relatively benign. By the early 1980s, island constructionhad ventured to more exposed sites with water depths approaching 15 m.Innovative slope protection systems and construction methods were developed toaddress the remote Arctic locations, short construction seasons, scarce localresources, and the challenging, yet poorly defined, offshore wave and iceclimate. This paper provides an overview of the history of island developmentin the Alaskan Arctic and discusses design evolution, construction, andperformance.
There is a growing interest in seismic surveys in arctic areas. Normally 2Dsurveys can be carried out with limited risk, as long as the area is reasonablyfree of ice. However, 3D seismic surveys are an essential tool for explorationin order to de-risk prospective areas ahead of expensive and challengingdrilling operations. Acquisition of 3D surveys, with multiple streamers, is farmore difficult than single streamer 2D surveys, as the amount of in-seaequipment is an order of magnitude higher and the data density for a given areacovered is far greater: the physical footprint of a 3D equipment spread beingtowed behind a vessel can be about a kilometer wide by several kilometers long.This significantly increases the risk of equipment damage due to ice. Thispaper summarizes experiences from several 3D surveys in the Arctic, andaddresses how the use of new equipment and techniques can reduce such risks toacceptable levels.
Ilyas, Muhammad (Mari Gas Company Limited) | Sadiq, Nauman (Dowell Schlumberger Western S.A.) | Mughal, Muhammad Ali (Mari Gas Company Limited) | Pardawalla, Hassan (Dowell Schlumberger Western S.A.) | Noor, Sameer Mustafa (Dowell Schlumberger Western S.A.)
This research work "Improvement of Cementing in Deep Wells" was carried out with the collaboration of Mari Gas Company Limited (MGCL), Pakistan and Schlumberger Pakistan, to recommend the designs and practices by which future cementing operations for zonal isolation in deep Wells may be improved.
Mari Gas Company Limited had successfully drilled, tested and completed Halini Well - 1 (Total Depth = 5350 m) in the Karak Block. The Karak Block is located in Northern Region of Pakistan which is known for its challenges, such as high pressure water influxes and weak zones, which led to a number of cementing challenges in this Well. The Cementing related problems that were faced on this Well were:
1- Sustained Casing Annulus Pressure in 13 3/8" x 9 5/8" Casing Annulus
2- Poor CBL-VDL results in 13 3/8" and 9 5/8" Casing
The scope of the project was to investigate the root cause of cementing challenges faced at Halini Well-1 and to propose recommendations for improving future cementing in deep Wells.
s to the above, the cementing of Halini Well- 1 was thoroughly analyzed along with similar case histories and problems in offset fields. On the basis of observations made, various recommendations have been proposed, mostly related to areas of fluid rheology, fluid contamination, fluid channeling, density and friction pressure hierarchy between fluids, fluid loss, temperature differential, and setting of casing slips etc. The idea for this project is to serve as a guideline for cementing the future deep Wells.
Primary Cementing is the process of placing cement between casing and the formations exposed to wellbore . The objective is to provide Zonal Isolation by creating a hydraulic seal thereby preventing the flow of wellbore fluids like oil, water or gas between formations or to surface. The life of the Well is directly dependent on the quality of this hydraulic seal, making cementing job a vital operation.
Incomplete zonal isolation can prevent either the Well from being completed at all to a loss of a producing well. The importance of cementing operation can be magnified by the fact that the cement has to survive the complete life of the Well that could vary anywhere between a year to fifty or more years.
Successful cementing operation would include a good casing to cement bond, good cement to formation bond and the ability of the cement placed itself to prevent any flow through it. In the event of this hydraulic seal being ineffective, it can allow fluids to migrate and channel through in the annulus and potentially even flow to the surface. This destroys the integrity of the Well. Any remedial job is extremely difficult to plan, execute and usually carries very low chances of success.
Nakazawa, N. (Systems Engineering Associates, Inc.) | Ono, J. (National Institute of Polar Research) | Yamaguchi, H. (University of Tokyo) | Ohshima, K.I. (Hokkaido University) | Kurokawa, A. (The Engineering Advancement Association of Japan)
This report describes an updated version of the numerical prediction systemfor oil spilled under sea-ice conditions in the Sea of Okhotsk that wasdeveloped by the authors and presented at ATC 2011 (Paper Number: OTC 22123).Our previous version enabled the computation of high resolution predictions ofthe ice-spilled-oil behavior using only PCs; a one-week forecast of spilled oilbehavior could be computed in a few hours. This previous method computed thebehavior prediction serially: first step, computation of sea-ice behavior forthe entire Okhotsk Sea (grid size of 16 km x 16 km); second, higher resolutioncomputations (grid sizes of 4 km x 4 km or 2 km x 2 km) using the dataresulting from the first step such as ice concentrations and velocities asboundary conditions; third, final computation of predicted sea-ice andspilled-oil behavior; and fourth, processing and displaying the results in agraphical interface. Since shorter computation times would be advantageous foroil-spill cleanup procedures, we modified the previous serial method to enableparallel computation not only to shorten the processing time but also todisplay spilled-oil/sea-ice images as the computation progressed. This paperincludes an example of computed predictions that model the behavior of spilledoil under three conditions, namely, in open water, in water at the margins ofice-covered water, and in ice-covered water, all located near Soya Strait.
Synthetic aperture radar (SAR) has been extensively used for the derivationof valuable information regarding sea ice properties and conditions. This workfocuses on the use of RADARSAT-2 ScanSAR Wide images (500x500 km swaths with50x50 meter pixels) to provide sea ice information for operations support inthe Arctic. Our developed processes generate several products that supportnavigation and operations in ice infested waters: i) Sea ice images, i.e.delineating and mapping sea ice relative to the open water, ii) Seasonal trendcharts of sea ice over an area of interest and, iii) Automated ice featuretracking and pressure zone mapping.
Using the RADARSAT-2 dual-polarization images and automated techniques, seaice maps are generated to identify regions of open water and of sea ice. Fromthe sea ice maps, total ice concentration is derived and combined withhistorical concentration maps. The output seasonal trend charts can be used toassist in monitoring Arctic sea ice extent and sea ice identification to aidwith navigational safety operations. Finally, we develop an automated icefeature tracking that can track moving ice and from which pressure and driftzones are identified. Future work will involve the development of theprediction of movement of ice floes and packs, using the ice feature trackingtechnique as the foundation.