Saleem, H. (Kuwait Oil Company) | Al-Shammari, R. (Kuwait Oil Company) | Al-Mai, N. (Kuwait Oil Company) | Robert, H. (Schlumberger) | Saxena, M. (Schlumberger) | Joy, S. (Schlumberger) | Rao, P. (Schlumberger) | Ismail, M. (Schlumberger)
KwIDF is a complex cross-domain solution consisting of a fully integrated infrastructure which supports field instrumentation, automated workflows and ergonomically designed collaboration solution. This paper describes virtualization technology and associated improvements in processes that will improve the Digital Oil Feld infrastructure resources and allow KOC's Corporate IT Group with tools to achieve more flexibility in delivering business critical data that translates into decision-ready information and collaborative support.
After three years of operation, data volumes are increasing rapidly with multiple workflows driven by multiple applications and the current infrastructure is not adequate to provide optimum performance. Added to this, complex workflows are planned for the next stage of development which will demand performance that the current system will not be able to deliver.
Though there are dedicated servers for each application, it is difficult to manage the application servers and storage. Therefore, it is essential to build a robust infrastructure for the current and future environments which will only become more complex with the onset of advanced workflows and exponential increase in the volume of data.
This paper describes the virtualization solution for Kuwait Digital Integrated Field infrastructure which will improve the utilization of resources, enable high availability and provide better disaster recovery solution. The solution will include the SCADA industrial network and the corporate user network which will allow KOC to achieve measurable business benefits such as reduction in the cost of IT Infrastructure while improving performance and reliability
To maintain the production and improve the recovery of hydrocarbons, nano materials are introduced recently. Improved oil recovery (IOR) is the application of various techniques for increasing the quantity of the crude oil that can be recovered from a hydrocarbon oil field. Among these techniques are chemical injection, which has been an expensive method, and field applications have been decreased during the past two decades. Currently with the advent of nanotechnology, nanofluids have been launched as a cheap, efficient and environmentally friendly alternative to other chemicals. Nanomaterials has been created and proposed to be used for IOR. Several nano materials with various sizes and concentrations have been proposed. Among the various these nanomaterials, nano-silica, nano alumina, nano zinc, and nano iron with different sizes has been recommended.
In the present work, two different nano materials used to improve the recovery of oil experimentally. These nano materials are; nano silica, and nano alumina. The size of each nano material is varies from 80 to 87 nm. The size and shape of each particles were examined using x-ray diffraction (XRD) and field emission-scanning electron microscope (FE-SEM) while their microanalysis was performed by Energy Dispersive System (EDS). Some these materials are prepared mechanically using ball mill such as nano silica and the others are created chemically such as nano alumina.
Numerous flooding scenarios have been performed to compare between the potentials of each nanofluids used to improve the hydrocarbon recovery. A control experimental run with water flooding (WF) was performed first. The ultimate recovery factor by WF was found about 67%. Then a flooding process using each nano fluid has been conducted for three different concentrations (0.1, 0.5, and 1 wt%). The ultimate recovery factors have been measured for all of these nano fluids and they are ranging from
This research examines and analyzes the new outcomes from implementing these nanomaterials for improving oil recovery over the traditional methods. Ultimately, the knowledge gained from this work can be used to interpret and define the nanofluids improvement mechanisms, and projected a roadmap for ongoing and future work.
Glasbergen, Gerard (Shell Global Solutions International) | Wever, Diego (Shell Global Solutions International) | Keijzer, Efraim (Shell Global Solutions International) | Farajzadeh, Rouhi (Shell Global Solutions International)
Polymer flooding is an attractive option in hydrocarbon maturation plans. Several successful polymer floods and pilots have been implemented. One of the risks in polymer flooding is loss of injectivity. The consequences of loss of injectivity can be large. In conditions where matrix injection is required, reduction of injection rate may result in a much slower propagating polymer front and consequently later arrival of the anticipated oil bank eroding on the economic value of the EOR process. In extreme cases it can even lead to loss of the injector. Under fracturing conditions the loss of injectivity may be less noticeable, but it can lead to out of zone fracturing or fractures that grow too much in size and cause shortcuts to the producers or affect future infill well drilling.
Reduction of injectivity is a generic concern in conventional waterfloods and can play an even larger factor when adding polymer to the waterflood. The increased viscosity of the injected polymer solution is the most obvious reason for an anticipated decrease in injectivity, but also other mechanisms can have an impact. These mechanisms include excessive polymer adsorption and associated permeability reduction, filtration of impurities in the polymer solution, fluid incompatibilities or reduced water quality.
In this paper we will discuss the various causes for loss of injectivity and propose a structured approach for the associated prevention and mitigation options. Prevention includes (1) selection of the most appropriate polymer type; (2) best practices for preparation of the polymer solution; (3) safeguarding the water quality; and (4) enabling options for mitigation in case excessive injectivity loss is observed. The remediation step includes (1) the identification of the root-cause of an apparent injectivity problem; (2) the design of an appropriate clean-up treatment; (3) monitoring of the operation; and (4) implement measures to avoid repetition of the problem. We will include an overview of the preventive and mitigation options for the different causes of injectivity decline in polymer floods.
Dutta, Dipankar (Kuwait Oil Company) | Al-Muraikhi, Haifa Rashed (Kuwait Oil Company) | Tiwary, Asheshwar (Kuwait Oil Company) | Tiwari, Brajesh Kumar (Kuwait Oil Company) | Abdul-Aziz, Wejdan Jassem (Kuwait Oil Company) | Bardapukar, Vilas (Kuwait Oil Company) | Al-Anezi, Sawsan Nayef (Kuwait Oil Company)
Ratawi Limestone is a fairly low permeability reservoir in the Umm Gudair field of Kuwait. Production history shows low liquid rate and fast pressure depletion around the wellbore. To understand the causatives for flow restriction, this study captures systematically different pore types, their relationship, distribution, connectivity and their impact on reservoir fluid flow behavior. It is observed that pores are not related to any depositional surface and are rather formed due to mesogenetic corrosion of highly micritized, tight carbonate rock bodies. Primary pores are almost completely destroyed during the process of shallow burial diagenesis. Separate vug pores are both fabric as well as nonfabric selective type and are the main contributor of pore volume within an overall pervasive (micritic) matrix pore dominated system of wackestone and packstone. Five porefacies are created on the basis of capillarity within a wider range of pore throat size variation. Type 1 is represented by macropores, Type 2 and 5 are mesopore and rests are micropore dominated. Each porefacies is assigned a linear equation on core calibrated porosity- permeability transform. The resultant permeability shows about 20% less value compared to permeabilities of corresponding intergranular Lucia class 2 pore type. This gap is specially pronounced within the reservoir rocks with high porosity and intermediate permeability values. Seven years of production history of this reservoir shows low rate of production with rapid pressure depletion around wellbore within a few months of production. Logical option to improve production is to increase the reservoir contact using horizontal multilaterals along with reduced well spacing and aggressive pressure support through water injection.
Golab, A. (FEI Digital Rock Services) | Deakin, L. (FEI Digital Rock Services) | Ravlo, V. (FEI Digital Rock Services) | Mattisson, C. (FEI Digital Rock Services) | Carnerup, A. (FEI Digital Rock Services) | Young, B. (FEI Digital Rock Services) | Idowu, N. (FEI Digital Rock Services) | Al-Jeri, S. A. (Kuwait Oil Company) | Al-Rushaid, M. A. (Kuwait Oil Company)
A study was designed to confirm the formation properties obtained from available conventional RCA data and inferred from corrected wireline log data using digital rock analysis (digital RCA and SCAL analysis) on cores from the Greater Burgan field. This study was performed for Kuwait Oil Company, Fields Development Group (S&EK) by FEI Digital Rock Services in 2014.
As part of this study, 27 feet of whole core, from the Lower Ahmadi (AHL2) to Upper Wara (WU1) formations, were imaged by X-ray computed tomography (CT) imaging, including 1 foot of partially preserved core. 14 plugs were extracted from these cores and imaged in 3D by a high resolution helical micro-CT. Analysis revealed stark differences in mineralogy, grain size and sorting and the presence of severe fracturing in some plugs due to the fragility and friability of the rock.
Sub-plugs were extracted from 10 of the 14 plugs (including one sub-plug from the partially preserved section) and imaged in 3D by helical micro-CT. 7 of the sub-plugs proved suitable for digital RCA and SCAL analysis. The 3D images were used to calculate digital RCA properties (porosity, permeability, grain density, grain size distribution and formation factor) and pore network models were built to perform digital SCAL simulations and predict multiphase transport properties such as Pc, kr and resistivity index for primary drainage and imbibition.
In addition, the
A tight rock workflow was used to identify sub-resolution porosity in 3 of the plugs. Experimental MICP curves showed that substantial portions of the pore throats were below the image resolution, caused by large amounts of pore-filling materials. Hence, pore scale information could not be directly extracted from some images. Consequently, process based modelling was carried out on two plugs to generate pore-networks. A quasi-static pore-network model was used to simulate oil/water displacements and predict multiphase transport properties. Detailed imaging of oil-in-place and porosity was performed on a partially preserved plug to create a map of remaining oil which revealed that oil was retained in most porous grains and strongly retained in clay-rich zones.
The digital core analysis results are in agreement with available log and core data. The Lower Ahmadi (AHL2) section is good quality in terms of porosity, permeability and flow properties, whereas the Upper Wara (WU1) section is of poorer quality.
Kumar, Sanjeev (Kuwait Oil Company) | Al-Hamad, Hamad (Kuwait Oil Company) | Al-Bous, Faisal (Kuwait Oil Company) | Al-Mutairi, Fayez (Kuwait Oil Company) | Sanyal, Arunava (Kuwait Oil Company) | Safar, Ahmad (Kuwait Oil Company)
A number of heavy oil or tar accumulations have been reported in several Middle East reservoirs. Heavy oil is often overlooked as a resource because of the expense and technical challenges associated with producing it.
But more than 6 trillion barrels of oil in place attributed to the heaviest hydrocarbon. Most of the conventional onshore hydrocarbon reservoirs have been depleted, and time of easy hydrocarbon is over; so, it is prudent to look into the unconventional reservoirs like heavy oil. An accurate evaluation and characterization is obviously crucial to its efficient exploitation. The evaluation and characterization of heavy oil depends on its identification, quantification, analysis of representative fluid sample and reservoir properties.
The methods proposed in the literature might be successful in identifying heavy oil reservoirs but are less reliable for quantifying the amount of heavy oil, and are insensitive to oil viscosity, the key property that controls the producibility of heavy oil. Heavy oil characterization is incomplete without the sampling of fluid in the reservoir environment. It is often desirable to acquire the sample with wireline formation tester tool and integrate the in-situ fluid properties with NMR logs.
In this study we successfully integrate, conventional logs, NMR logs, in-situ fluid sample, PVT data and conventional core data for identification and quantification of heavy oil present in the pore space. This integrated study overcomes the limitations of individual techniques. Our case study shows that the porosity deficit between conventional total porosity and NMR porosity gives the identification of heavy oil present in the pore space, this difference between two porosities represents the extra viscous component of fluid that are not observable by the NMR tool. The amount of porosity deficit is the amount of extra heavy oil / tar in the pore space and this gives the quantification of the same.
Conventional and NMR derived reservoir properties are required to be integrated with conventional core porosity, permeability, water saturation and viscosity derived from PVT sample in order to characterize Heavy Oil in Clastic Reservoirs.
Through years of research and development, ProSep has brought to market a family of mixers for use in practically every application where separation of phases or constituents take place. In produced water applications, ProSep has incorporated a series of modulating mixers along with another proprietary process technology, the CTour Process, to provide a compact solution for new build as well as retrofit / debottlenecking applications. The CTour Process is the injection of natural gas condensates into the produced water treatment line for an in-situ extraction of residual OIW. The ProSep series of modulating mixers, along with our series of chemical injection mixers, provide the efficient mixing needed to achieve low sheer, homogenous fluid mixing of the condensate to aid to the extraction of PAH molecules and dissolved BTEX components as well as dispersed hydrocarbons. The modulating feature of the mixer allows for a maintained and consistent low differential pressure under varying flow rate conditions.
This same mixer technology can also be applied on the crude oil treating pipeline using our ProMix – for chemical injection of de-emulsifiers, corrosion inhibitors, and scale inhibitors – and ProSalt – wash water injection mixer – products. Both mixing systems allow for cost savings with regard to chemical and wash water usage and injection. Additionally, the homogenous mixes created allow for more efficient downstream process equipment, such as dehydrators and desalters, with less oil reporting to the brine water effluent, therefore reducing the burden on other separating technologies in the process. These unique designs offer efficient mixing over high turndown due to their ability to modulate, require less pressure differential for operation, provide a more homogenous mixture over a shorter distance, and provide a narrower droplet distribution curve.
Al-Rubaiyea, Jamal (Kuwait Gulf Oil Company) | Al-Houli, Meshari (Kuwait Gulf Oil Company) | Al-Ajmi, Fahad (Kuwait Gulf Oil Company) | Al-Duwaish, Majed (Saudi Arabian Chevron) | Elsherif, Ahmed (Schlumberger) | Lahmar, Hakima (Schlumberger)
Over the last several years, the ability to perform accurate quantitative formation evaluation in high angle and horizontal wells has been recognized as high priority for major operators. The Logging While Drilling (LWD) has witnessed a revolution in technology in recent years. These new LWD tools have gained recognition in geosteering and well placement operations.
The need for advanced formation evaluation is more critical for carbonate reservoir where the complex pore structure will play a big role in fluid mobility. Formation mobility in carbonate reservoirs has been always an important output of any formation evaluation.
The South Fuwaris Field is located in the Partitioned Zone between Kuwait and Saudi Arabia. The Lower Cretaceous Ratawi reservoirs were discovered in 1961, and production commenced in 1963. There are two major reservoirs – the Ratawi Limestone, which is predominantly developed by vertical wells, and the Ratawi Oolite, which is exclusively developed by horizontal wells. The reservoirs comprise low-moderate permeability limestone. Interpretation is complicated by the existence of microporosity, mesoporosity and macroporosity. Understanding of pore type distribution would be of value is the placement of future Ratawi Oolite horizontal wells.
The LWD resistivity was used in this field as standard resistivity tool (Laterolog type) to determine the true formation resistivity. In addition, due to the fact that LWD tools measure while rotating, several resistivity images with different depth of investigation are also available in real time and recorded mode.
In this case, the LWD resistivity imaging was used to study azimuthal formation porosity distribution in order to quantify the different porosity portions (Primary / Secondary). Following that, an empirical equation was used to determine formation permeability profile. This profile can be further improved when calibrated with core data or formation pressure survey while drilling.
Organic acids have been used to stimulate HP/HT oil and gas wells. However, these acids cannot be used above certain concentrations, which depend on the type of acid used. For example, 9 wt% is the upper limit for formic acid concentration, whereas acetic and citric acids can be used only up to 13 and 1 wt%, respectively. Using these acids above these limits causes a formation damage results from the precipitation of the acids' calcium salts.
A new technique was developed and experimentally proven to increase the concentration of organic acids that can be used in the oilfield without precipitation of the reaction products. This involves the addition of an environmentally friendly acid (gluconic acid) chelant to the selected organic acid under investigation. In a recently published paper (SPE-173751), the authors showed a significant improvement in the solubility of calcium lactate when lactic acid was mixed with gluconic acid to stimulated calcite rocks. The current work investigates the generalization of this idea for other organic acids such as: acetic, formic, citric, glycolic, and boric acids, with an objective to examine the effectiveness of the new acids to stimulate carbonate formation at 150-250°F and determine the optimum injection requirements.
Coreflood results showed that mixing gluconic acid with acetic acid increased the solubility of the resulted calcium salt and allowed using acetic acid at 15 wt% without the risk of precipitating calcium acetate. When mixed with formic acid, a minimum of acid pore volume was observed at a gluconic: formic acids molar ratio of 1:7. This allowed the use of formic acid at 12.5 wt% without any observation of calcium formate precipitation. Gluconic-citric and gluconic-boric acid mixtures required as high as 4 PV to breakthrough, indicating that the enhancement of product solubility depends on the type of the acid mixed with gluconic acid. Finally, a gluconic-glycolic acid mixture with a molar ratio of 1:1 showed the least acid pore volume required to breakthrough (2.35 PV) with similar results to what was previously reported for gluconic-lactic acid mixtures.
AbdElNasser, M. G. (Qarun Pet. Co., Ahmed H. El-Banbi, Cairo University) | Al-Maraghi, A.M. (Qarun Pet. Co., Ahmed H. El-Banbi, Cairo University) | Abady, S. M. (Qarun Pet. Co., Ahmed H. El-Banbi, Cairo University)
This paper presents a case study for drilling a horizontal well with multi stage transverse fractures in the NEAMA field in Karma concession in the western desert of Egypt. The well production results are expected to lead the Western Desert operators to change the development strategy for several western desert fields to unlock the unrecovered reserves in the upper Baharia tight formation.
NEAMA field has total of 9 wells: 5 wells on production with total production around 500 BOPD, and 4 shut-in wells due to low productivity. The field STOIIP is around 15 MMSTB. With the historical low initial production rates, it was decided to develop the stranded reserves by drilling a horizontal well to replace three vertical wells and test the feasibility of applying horizontal wells with multi-stage fracturing in such tight reservoir.
A horizontal well with 7 fracturing stages was completed at the down-dip part of the field, LWD (Logging While Drilling) measurements were used to control well's direction and predict rock lithology. The LWD helped to control the well trajectory between the upper and lower boundaries of the reservoir's zone of interest. The well was completed with permanent downhole pressure gauge and ESP system in the vertical hole.
The well was put on production with initial rate of 400 BOPD with 20% water cut which was four times the total field production. The well production was maintained at low water cut until water production increased significantly. Integrated analysis of all collected data revealed that water channeling behind casing was responsible for the excessive water production. It was planned to work over the well to restore its oil production.
The paper discusses the integrated data analysis techniques that led to the choice of completion option of horizontal well with transverse fractures for new wells in NEAMA field. The results and additional analyses of both pressure and production data are expected to help other Western Desert operators to develop significant reserves of tight UBAH reservoir.