Al-Kuait, A.M.S. (Saudi Aramco) | Al-yateem, Karam Sami (ARAMCO Services Company) | Olivares, Tulio (Halliburton) | Zubail, Makki A. (Saudi Aramco) | El Bialy, Moustafa (Halliburton) | Ezell, Ryan G. (Halliburton) | Maghrabi, Shadaab (Halliburton)
Safaniya is one of largest offshore oil fields located north of Dhahran in Saudi Arabia. It is 50 km by 15 km in size and began production in 1956. Lately, a few wells drilled in this field showed reservoir damage where the production dropped or the well had no flow. Workover operations were performed on six wells and two new wells were drilled. For all eight wells, 6?-in. laterals were drilled through the reservoirs with an engineered invert emulsion drilling fluid (RDF). The RDF design was controlled to ensure an acid-soluble, thin, external filter cake with no fines invasion. The vulnerability of the filter cake to be attacked by the acid was fundamental to this RDF design. A delayed filter cake breaker fluid was then designed for use on the 6?-in. laterals; this fluid consisted of an organic acid precursor (OAP) and a water wetting additive. The OAP released acid in a delayed manner, whereas the water wetting additive made the oil-based filter cake water wet, to make it vulnerable to acid attack. With this approach, the filter cake was removed uniformly in all subject laterals across the reservoir. The production data on the eight wells treated with the OAP show an improved oil production rate of more than 4,000 B/D for six of the eight wells, which exceeds the key performance indicator (KPI) set for the laterals. In previous years from 2005-10, the six workover wells showed, on average, very low oil production rates (OPR) comparatively. In addition, after the OAP treatment, these six wells show higher well flow head pressures than in 2005-10. The water cut percentage on these laterals was 0 or less than 1, compared to 2005-10, when the water cut percentage varied from 8% to 50% for these workover wells. This paper discusses the workover operation of the six wells and the drilling and delayed stimulation treatment on two new wells in the Safaniya field, including laboratory evaluation, field application and production data.
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.
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.
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.
Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations.
An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively.
Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.
Turkey, Laila (KOC) | Hafez, Karam Mohamed (KOC) | Vigier, Louise (Beicip) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Datta, Kalyanbrata (KOC) | Knight, Roger (KOC) | Lefebvre, Christian (Beicip-Franlab) | Bond, Deryck John (Kuwait Oil Company) | Al-qattan, Abrar (KOC) | Al-Jadi, Manayer (Kuwait Oil Company) | De Medeiros, Maitre (Beicip) | Al-Kandari, Ibrahim (Kuwait Oil Company)
A pilot water flood was carried out in the Marrat reservoir in the Magwa Field. The main aim of this pilot was to allow an assessment of the ability to sustain injection, better understand reservoir characteristics. A sector model was built to help with this task.
An evaluation of the injectivity in Magwa Marrat reservoir was performed with particular attention to studying how injectivity varied as injected water quality was changed. This was done using modified Hall Plots, injection logs, flow logs and time lapse temperature logs.
Data acquisition during the course of the pilot was used to better understand reservoir heterogeneity. This included the acquisition of pressure transient and interference data, multiple production and injection logs, temperature logging, monitoring production water chemistry, the use of tracers and a re-evaluation of the log and core data to better understand to role of fractures.
A geological model using detailed reservoir characterization and a 3D discrete fracture network model was constructed. Fracture corridors were derived from fractured lineaments interpreted from different seismic attribute maps:
A sector model of the pilot flood area was then derived and used to integrate the results of the surveillance data. The main output is to develop an understanding of the natural fracture system occurring in the different units of the Marrat reservoir and to characterize their organization and distribution. The lessons learned from this sector modeling work will then be integrated in the Marrat full field study.
The work described here shows how pilot water flood results can be used to reduce risk related to both injectivity and to reservoir heterogeneity in the secondary development of a major reservoir.
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.
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.
Currently, many reservoirs in the region approach the end of primary recovery phase where new techniques are needed to enhance recovery. Therefore, the need to optimize oil recovery from the current resources is very well understood by regional oil companies. To enhance oil recovery from current oil resources, field operators need to overcome the forces responsible for oil entrapment. Enhanced Oil Recovery techniques (EOR) introduce new energy into oil reservoirs to reduce the influence of these forces. Most of these resources contain light oil and are considered suitable candidates for either miscible or chemical EOR techniques. The first technique is challenged by the availability of suitable miscible gas. While, chemical EOR techniques are challenges by the high salt concentrations in the maturing oil reservoirs. The high salinity conditions encourage deficiencies in the performance of chemical EOR processes. Therefore, minimizing the effect of in situ salt on the injected chemical would impose tremendous improvement that leads to higher oil recovery. One way to diminish salt effect is to condition the oil reservoirs by injecting a slug of preflush water prior to chemical injection.
In this paper, the performance of polymer flooding, after preflush slug, in high salinity reservoir is investigated by numerical simulation means. The injected slugs, both preflush and polymer, are driven by water. The objective is to identify the relationship between preflush, polymer, and drive water characteristics and oil recovery. Seven parameters were considered: preflush slug size, preflush salinity, polymer slug size, polymer concentration, polymer slug salinity, and drive water salinity. The results show that these parameters have various degree of influence on oil recovery. For example, increasing the preflush slug size would results in more oil recovery especially during the early time. Detailed findings will be presented in the paper.
There are many challenges associated with the design and installation ofArctic subsea pipeline. A leading example is the Northstar developmentpipelines currently operating safely offshore the Alaskan North Slope. Uniqueoffshore Arctic environmental loading conditions, such as ice gouging,influence each pipeline design differently. Statistical distributions andprobabilistic assessments of ice gouge records can be used to predict designextreme gouge depths which can then be used to determine pipeline burial depthsrequired for protection against ice keels.
The Northstar subsea pipeline project used the statistical ice gougeanalysis method described by Lanan et al. (1986), based on the exponentialprobability distribution, to select design pipeline burial depths forprotection against ice gouging. This method was applied to publicly availabledata and site-specific survey data collected prior to the pipeline installationin 2000, to predict the design extreme ice gouge depths expected along thepipeline route. Each year since the pipeline installation, new ice gouge datahas been collected by BP Exploration (Alaska).
This paper reviews additional ice gouge data collected since installation ofthe Northstar pipelines and has assessed the use of alternate ice gougeanalysis methods to predict extreme ice gouge design depths for future pipelineinstallations in the Beaufort Sea, Data available from all Alaskan Beaufort Seaice gouge surveys in the Northstar pipeline area was also included in some ofthe statistical comparisons.
Results obtained using the exponential analysis method were compared toanalyses using alternate probability distribution functions (PDFs), such as theWeibull, gamma, and log-normal. Data thresholds have also been investigated forPDF fitting. Work by Caines (2009, 2011) has shown that alternate probabilitydistribution functions might be more appropriate for modeling ice gouge depthdata, compared to the traditional exponential method. A brief comparativeanalysis was conducted using known age Northstar pipeline route data toinvestigate the effects of using all available gouge depth data versus annualmaximums only.