Oil Field In Oman Research Articles

Field Application of Evaluation Model for Development Effect on Horizontal Waterflooding in Thin Low-permeability Carbonate Reservoirs

Abstract Low-permeability carbonate reservoirs with layered characteristics generally exist in Middle East district. The reservoirs achieved low recovery efficiency using vertical well by depletion mode in the early stage, and low horizontal and vertical sweep efficiency by vertical waterflooding due to high permeability streak and interlayer. Some oilfields in the district has successively implemented horizontal waterflooding technology and achieved good development results. Feasible and effective report has not been provided yet on the problem that the range of recoverable reserves and recovery efficiency can be increased by horizontal waterflooding. Considering some oilfields accomplished horizontal waterflooding in quick succession and some oilfields were just developed by horizontal waterflooding, practical resolution should be recommended such as the corresponding evaluation model for enhancing recovery efficiency range of the technology. The paper put forward an evaluation model for enhancing recovery reserves and recovery efficiency of horizontal waterflooding based on production decline model and waterflooding curve model. The resolution can also provide an evaluation basis of enhancing recovery efficiency for optimization and adjustment of horizontal water flooding. Applications of these concepts are illustrated with D oilfield in Oman. Results indicated that recovery efficiency by horizontal waterflooding after natural depletion development may be increased around 25% and about 4% by the optimization and adjustment process. The evaluation model will be used effectively to predict IOR effect of the similar reservoirs in Middle East oilfields.

Enhancing oil recovery by electric current impulses well treatment: A case of marginal field from Oman

Electro-enhanced oil recovery (EEOR) methods have the smallest carbon footprint, among which the electric current impulses method is the most economic. Its performance requires minimal surface facilities, no auxiliary equipment, downhole tools or hazardous materials. Stopping oil production or pulling the tubing out of the well for placing the downhole tools are not required either. The period of treatment session is short (12–24 h). The electricity consumption of 150–200 kW is lower than for any other methods.Prior to the abandonment of an oil field in Oman, treatment with the electric current impulses was applied to marginal wells to clean up the near borehole zone and improve well production characteristics. 7 wells were treated in pairs as cathode and anode in two successive electrical treatments, which were carried out with a difference of 4 months. In the period after the second electrical treatment, only five wells were in operation. Two of them, wells 5 and 12 were treated in both electrical treatments.The results of electrical treatments were thoroughly analysed due to the overlap of simultaneous operations that could mask the effect of electrical treatment. The incremental oil production compared to the forecast was evaluated using reservoir simulation and decline curve analysis. In wells after the second electrical treatment, the increase in oil production rate (OPR) by 36% was in Well 5 and by 25% in Well 1. There was no noticeable effect in Well 12, probably because it was located at the very edge of the reservoir structure. The effect of electrical treatment was also observed in untreated nearby wells. An increase of 11% in OPR was observed in Well 23 and 64% in Well 7. The effect of the electrical treatment was also observed in the form of heavy oil and wax flowing in slugs from three treated wells, which increased the total consumption of demulsifier from 12 to 20 L per day. It has been demonstrated that this method has great potential for cleaning the near wellbore space and increasing oil production.

A NEW OIL SEEPAGE IN THE OMAN MOUNTAINS AND ITS GEOLOGICAL, GEOCHEMICAL AND PETROLEUM SYSTEMS CONTEXT

A minor natural oil seepage is described from an unlikely setting in the Oman Mountains. The host rocks are fractured pelagic limestones of the lower member of the Triassic – Lower Jurassic Matbat Formation of the Hamrat Duru Group in the lower part of the allochthonous Hawasina Complex. This paper summarises Oman's established oil families and documents previously recorded oil seepages as context for describing the new seepage, its geochemistry, and possible source rock. The seep oil is different to those known from Oman's oil fields and probably derived from a poor quality, Mesozoic clastic source rock containing a mix of terrigenous and marine organic matter. The most likely source appears to be the Toarcian turbiditic upper member of the Matbat Formation, equivalent to the clastic Mafraq Formation of the Arabian Platform. The occurrence of source rocks in the allochthonous sediments of the NeoTethyan Hawasina Basin has been suspected previously, though their commercial significance remains to be established.

Microbial-Enhanced Heavy Oil Recovery under Laboratory Conditions by Bacillus firmus BG4 and Bacillus halodurans BG5 Isolated from Heavy Oil Fields

Microbial Enhanced Oil Recovery (MEOR) is one of the tertiary recovery methods. The high viscosity and low flow characteristics of heavy oil makes it difficult for the extraction from oil reservoirs. Many spore-forming bacteria were isolated from Oman oil fields, which can biotransform heavy crude oil by changing its viscosity by converting heavier components into lighter ones. Two of the isolates, Bacillus firmus BG4 and Bacillus halodurans BG5, which showed maximum growth in higher concentrations of heavy crude oil were selected for the study. Gas chromatography analysis of the heavy crude oil treated with the isolates for nine days showed 81.4% biotransformation for B. firmus and 81.9% for B. halodurans. In both cases, it was found that the aromatic components in the heavy crude oil were utilized by the isolates, converting them to aliphatic species. Core flooding experiments conducted at 50 °C, mimicking reservoir conditions to prove the efficiency of the isolates in MEOR, resulted in 10.4% and 7.7% for B. firmus and B. halodurans, respectively, after the nine-day shut-in period. These investigations demonstrated the potential of B. firmus BG4 and B. halodurans BG5 as an environmentally attractive approach for heavy oil recovery.

Visco-elastic and Dielectric Relaxation Studies of Crude Oil

Temperature-dependent dielectric and viscosity studies have been carried out in two samples of crude oils procured from different wells of Oman oil fields. The dielectric permittivity is found to decrease linearly with increasing temperature for both samples. The relaxation frequency at which the loss attains peak value decreases with decreasing temperature. The viscosity of both samples is found to have an Arrhenius type of variation, from which activation energy was estimated using the reduced temperature plots. Further, the viscosity data was used to estimate the shear wave velocity and the attenuation parameter of the samples using relevant theories.

Microbial Consortia in Oman Oil Fields: A Possible Use in Enhanced Oil Recovery

Microbial enhanced oil recovery (MEOR) is one of the most economical and efficient methods for extending the life of production wells in a declining reservoir. Microbial consortia from Wafra oil wells and Suwaihat production water, Al-Wusta region, Oman were screened. Microbial consortia in brine samples were identified using denaturing gradient gel electrophoresis and 16S rRNA gene sequences. The detected microbial consortia of Wafra oil wells were completely different from microbial consortia of Suwaihat formation water. A total of 33 genera and 58 species were identified in Wafra oil wells and Suwaihat production water. All of the identified microbial genera were first reported in Oman, with Caminicella sporogenes for the first time reported from oil fields. Most of the identified microorganisms were found to be anaerobic, thermophilic, and halophilic, and produced biogases, biosolvants, and biosurfactants as by-products, which may be good candidates for MEOR.

Impacts on Ambient Air Quality Due to Flaring Activities in One of Oman's Oilfields

ABSTRACT This work was conducted to assess the impacts on workplace and ambient air quality due to release of sulfur dioxide (SO2) into the atmosphere at Al-Noor production station, located in southern desert of Sultanate of Oman. The SO2 is released because of oxidation of H2S to SO2 on flaring of H2S rich off gas at the Al-Noor. In the first phase of the study, CALPUFF modeling system was used to predict the ground level concentrations of SO2 emissions from the flare stacks. The evaluation of the modeling system was carried out by comparing the predicted results with that of the measured. In the second stage of the study, the estimated results were compared with the air quality standards/guidelines set by Omani regulatory authorities as well as by World Health Organization (WHO). It was concluded on the basis of current study that the sensitive individuals in the workplace of the Al-Noor could experience adverse health effects due to short-term exposure of SO2.

Work Related Injuries in an Oil field in Oman

The aim of this paper is to describe the epidemiology of occupational injuries in the Harweel oil field, Oman. The study is based on data gathered from a computerized database maintained by Petroleum Development of Oman (PDO). All non-fatal work-related occupational injuries registered between April 2007 and December 2009 were gathered and analyzed. A total of 170 work-related injuries were reported during the study period. Foreign body to the eye was the most common type of injury (27.6%) encountered among all injuries, followed by man falls/slips (11.8%). Injury to the upper extremities accounted for the largest percentage (38.8%) among other body parts. While, a significant portion of the injuries (52%) affected workers aged less than 30 years. The average injury rate per 1000 exposed workers per year was 19.8. The study outlines the types of injuries most commonly encountered in the oil field in Oman. Additional data is required in order to devise proper epidemiological analysis. Establishing a comprehensive surveillance system for injuries is essential to ascertain factors influencing such injuries.

Artificial neural networks workflow and its application in the petroleum industry

We develop a neural network workflow, which provides a systematic approach for tackling various problems in petroleum engineering. The workflow covers several design issues for constructing neural network models, especially in terms of developing the network structure. We apply the model to predict water saturation in an oilfield in Oman. Water saturation can be accurately obtained from data measured from cores removed from the oil field, but this information is limited to a few wells. Wireline log data are more abundantly available in most wells, and they provide valuable, but indirect, information about rock properties. A three-layered neural network model with five hidden neurons and a resilient back-propagation algorithm is found to be the best design for the saturation prediction. The input variables to the model are density, neutron, resistivity, and photo-electric wireline logs, and the model is trained using core water saturation. The model is able to predict the saturation directly from wireline logs with a correlation coefficient (r) of 0.91 and an error of 2.5 saturation units on the testing data.

Effect of Water Content and Surfactant Type on Viscosity and Stability of Emulsified Heavy Mukhaizna Crude Oil

Heavy crude oil from the Mukhaizna oil field in Oman was emulsified with water in an attempt to decrease its viscosity. The oil has a kinematic viscosity of 7160 mm2/s at 30 °C, density of 0.9571 g/cm3 at 15 °C, and asphaltene content of 4.7 wt %. The effects of changes in water content (20−30 wt %), type and concentration of surfactant, addition of a water-soluble polymer, and agitation temperatures (25 and 42 °C) were studied in order to identify the optimum viscosity and stability for transporting the oil. The stability was measured by the water separation rate from the emulsion. For the Mukhaizna heavy crude oil, 21−22 wt % of water content and 0.4 wt % of nonylphenol ether type or higher alcohol alkylene oxide type surfactant were found to be optimum for a stable emulsion with a concomitant significant decrease in viscosity to about 1/3−1/4 that of the original crude oil. This improves the transportability of the heavy crude oil and makes it suitable for use as a power generation fuel.

A laboratory feasibility study of dilute surfactant injection for the Yibal field, Oman

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding. The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations. The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.

PIC, Dow plan ethylene complex in Kuwait

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding.The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations.The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.

ABSTRACT: Seismic Visualization of Subtle Fault/Fracture Zones in Carbonate Reservoirs: Two Case Studies (Fahud - Oman and Waterton - Canada)

One of the key elements in unravelling the structural geometry of carbonate reservoirs is the analysis of seismic data. This poster is compiled primarily to give an insight in the visualization techniques used to highlight fault/fracture patterns. Secondly a work around is given to solve the problems encountered with data management between the different software packages used in the studies. The two case studies discussed are both part of separate multi-disciplinary asset studies carried out in the Shell International Carbonate Development team in Rijswijk. The first study (carried out in the first half 2000) focussed on the Upper Cretaceous Natih E reservoir of the Fahud oil field in Oman. The shallow onshore seismic data suffered from severe noise and quality loss due to amongst others soft overburden. The second study, which is still under evaluation, is carried out on the pre-stacked imaged seismic data in the foothills of the Rocky Mountains in Alberta. The North Waterton gas reservoirs are situated in the thrusted Lower Carboniferous to Devonian sequence. Due to the large terrain effects the seismic acquisition and processing is a tedious job with results that are difficult to interpret.

Steam-Soak Performance in South Oman

Summary With about 2 × 109 stock-tank m3 [12.6 × 109 STB] of medium/heavy oil originally in place (OOIP) in south Oman, considerable scope exists for increasing oil recovery by thermal methods. The viability of thermal recovery in south Oman was tested with a steamflood pilot in the Al Khlata sands of the Marmul field and a 2-year steam-soak project to test the applicability of steam soak in five south Oman oil fields producing heavy oil. This paper describes the performance of the latter project. The wells selected for the test program included a wide range of south Oman reservoir and oil characteristics—i.e., the main reservoir drive mechanisms of depletion, solution-gas, and edge- and bottomwater drive, the reservoir sandbody types, and oil viscosities from 80 to 4000 mPa·s [80 to 4, 000 cp]. Steam-soak operations were successful, and oil production accelerated significantly, with an average stimulated production rate twice that before stimulation. Acceleration was less marked in wells where reservoir energy is limited or where the primary (cold) water cut is more than 30%. At primary (cold) water cuts >50%, no increase in oil production rate was observed. The process was simulated numerically for several wells, with the results in close agreement with performance. Improved understanding of the process resulting from the simulation allowed the most important factors influencing performance to be identified and aided process optimization in the field test. Two small-scale steam-soak projects currently are being assessed for implementation in the early 1990's.

Late Precambrian-Cambrian Sediments of Huqf Group, Sultanate of Oman

The Huqf Group is the oldest known sedimentary sequence overlying crystalline basement in the Sultanate of Oman. It crops out on a broad regional high, the Huqf Axis, which forms a dominating structural element on the southeastern edge of the Arabian peninsula. Subsurface and outcrop evidence within and outside of Oman suggests that the sediments of the Huqf Group lie within the age span of late Precambrian to Early-Middle Cambrian. The Huqf Group is subdivided into five formations corresponding to an alternation of clastics (Abu Mahara and Shuram Formations) and carbonates (Khufai and Buah Formations) deposited in essentially shallow marine to supratidal (or fluviatile) conditions and terminated by an evaporitic sequence (Ara Formation). Evaporites are absent on the Huqf Axis, but they are thickly developed to the west over a large part of southern and central Oman, where they acted as the major structure former of most of Oman's oil fields, and even locally pierced up to the surface. In the subsurface, the Huqf Group has been reached by the drill mainly in southern Oman, where its lithostratigraphy resembles that defined in the type area. In central Oman, the oldest sediments exposed in the core of the Oman Mountains may be correlative with the Huqf Group. Regional correlations suggest that the predominantly carbonate-evaporitic facies of the Huqf Group was widely distributed in late Precambrian-Early Cambrian time: the Huqf basin is tentatively considered part of a belt of evaporitic basins and intervening carbonate platforms, which stretched across the Pangea landmass from the Indian subcontinent (Salt Range of Pakistan) through South Yemen, Oman, and Saudi Arabia into the gulf states and Iran (Hormuz Series and carbonate platform north of the Zagros).

Application of Pulse-Test Methods in Oman

Single-well pulse testing using very short pulses is effective for measuring vertical permeability. A particular advantage is that, unlike the constant-rate method, it does not require fully built-up conditions. Introduction Major decisions concerning the future development of a reservoir must increasingly be made in the early stages. Numerical simulators are now used early to study the effect of various development schemes. The extent to which these model studies are useful as a method of comparing various possible development schemes depends largely on the reliability of the early available data. The lateral permeability development and the magnitude of the vertical permeability (for coning studies, for example) arc often critical parameters. Because subsequent production can disturb the reservoir to such an extent that representative permeability data can be obtained only initially, tests that can provide that early information are especially important. Recently, therefore, there has been a revival of interest in well tests, especially those that provide a direct measurement of the in-situ horizontal and vertical permeabilities. permeabilities. New test methods based on pulse disturbances (single or repeated) have been proposed to achieve this. The advantage of these methods over constant-rate methods is that, owing to the more complex response resulting from the pulses, they provide more selective information on the in-situ reservoir parameters. The pulse response can be characterized by only relative pulse response can be characterized by only relative pressures (see Fig. 1); therefore pulse tests can be pressures (see Fig. 1); therefore pulse tests can be performed even when a general back-ground pressure performed even when a general back-ground pressure trend is present. Although there are these theoretical advantages, they are counterbalanced by greater, experimental difficulties. The measured response usually is weak, so special high-sensitivity recording equipment must be used. Also, the weak response is more susceptible to small disturbances than the response of conventional tests. An additional problem is created by the fact that variable pressures must be recorded. To ensure that the pressures measured inside the observation wells truly reflect the pressure variations in the reservoir, these wells must be "hard" enough. This means that the time constant of the wellbore-perforation system must be smaller than the variations in pressure that are to be observed. A well can be made harder by reducing the total compressibility of the fluids inside the wellbore and additionally by reducing the resistance over the perforations (skin). This implies that it might be necessary to completely fill the well with a gas-free liquid or to use special packer arrangements. This is generally time-consuming and expensive. These interwell pulse methods generally are applied only to low-storage pulse methods generally are applied only to low-storage reservoirs with close spacing, since in such cases a reasonable response can be expected. In the Yibal oil field in Oman, an interwell pulse test was carried out over long distances. JPT P. 1025