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The reliability of the estimated parameters in well test analysis depends on the accuracy of measured data. Early time data are usually controlled by the wellbore storage effect. However, this effect may last for the pseudo-radial flow or the boundary dominated flow. Eliminating this effect is an option for restoring the real data. Using the data with this effect is another option that can be used successfully for reservoir characterization.
This paper introduces a new technique for interpreting the pressure behavior of horizontal wells and fractured formations with wellbore storage. A new analytical model describes the early time data has been derived for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. Several models for the relationships of the peak points with the pressure, pressure derivative and time have been proposed in this study for different wellbore storage coefficients. A complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. The study has shown that early radial flow for short to moderate horizontal wells is the most affected flow regime by the wellbore storage. For long horizontal wells, the early linear flow is the most affected flow regime by the wellbore storage effect.
The most important finding in this study is the ability to run a short test and use the early time data only for characterizing the formation. This means there is no need to run a long time test to reach the pseudo-steady state. Therefore, from the wellbore storage dominated flow, the early radial and pseudo-radial flow can be established for horizontal wells and hydraulic fractured formations. A step-by-step procedure for analyzing pressure tests using the analytical models (TDS) and the type curves is also included in this paper for several numerical examples.
In a past decade, various nanoparticle experiments have been initiated for improved/enhanced oil recovery (IOR/EOR) project by worldwide petroleum researchers and it has been recognized as a promising agent for IOR/EOR at laboratory scale. A hydrophilic silica nanoparticle with average primary particle size of 7 nm was chosen for this study. Nanofluid was synthesized using synthetic reservoir brine. In this paper, experimental study has been performed to evaluate oil recovery using nanofluid injection onto several water-wet Berea sandstone core plugs.
Three injection schemes associated with nanofluid were performed: 1) nanofluid flooding as secondary recovery process, 2) brine flooding as tertiary recovery processs (following after nanofluid flooding at residual oil saturation), and 3) nanofluid flooding as tertiary recovery process. Interfacial tension (IFT) has been measured using spinning drop method between synthetic oil and brine/nanofluid. It observed that IFT decreased when nanoparticles were introduced to brine.
Compare with brine flooding as secondary recovery, nanofluid flooding almost reach 8% higher oil recovery (% of original oil in place/OOIP) onto Berea cores. The nanofluid also reduced residual oil saturation in the range of 2-13% of pore volume (PV) at core scale. In injection scheme 2, additional oil recovery from brine flooding only reached less than 1% of OOIP. As tertiary recovery, nanofluid flooding reached additional oil recovery of almost 2% of OOIP. The IFT reduction may become a part of recovery mechanism in our studies. The essential results from our experiments showed that nanofluid flooding have more potential in improving oil recovery as secondary recovery compared to tertiary recovery.
The oil and gas industry must face the challenges to unlock the resources that are becoming increasingly difficult to reach with conventional technology. Most oil fields around the world have achieved the stage where the total production rate is nearing the decline phase. Hence, the current major challenge is how to delay the abandonment by extracting more oil economically. The latest worldwide industries innovation trends in miniaturization and nanotechnology material. A nanoparticle, as a part of nanotechnology, has size typically less than 100 nm. Its size is much smaller than rock pore throat in micron size. A nanoparticle fluid suspension, so called nanofluid, is synthesized from nano-sized particles and dispersed in liquids such as water, oil or ethylene glycol.
Through continuously increasing of publication addressed on the topic, nanofluid has showed its potential as IOR/EOR in the past decade. It has motivated us to perform research study to reveal the recovery mechanism and performance of nanofluid in porous medium. We focus on liphopobic and hydrophilic silica nanoparticles (LHP). Miranda et al. (2012) has mentioned the benefit of using silica nanoparticles. It is inorganic material that easier produced with a good degree of control/modify of physical chemistry properties. It can also be easily surface functionalized from hydrophobic to hydrophilic by silanization with hydroxyl group or sulfonic acid. Ju et al. (2006) has initially observed LHP with size range 10-500 nm could improve oil recovery with around 9% (with LHP concentration 0.02 vol. %) compared with pure water. They explained that the recovery mechanism involves wettability alteration of reservoir rock due to adsorbed LHP. Besides, they also reported the porosity and permeability impairment of sandpacks during nanofluid flooding.
Stanitzek, Theo (AkzoNobel) | De Wolf, Corine (AkzoNobel) | Gerdes, Steffan (Fangmann Energy Services) | Lummer, Nils R. (Fangmann Energy Services) | Nasr-El-Din, Hisham A. (Texas A&M University) | Alex, Alan K. (AkzoNobel)
Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
This paper analyzes reaction and thermal front development in porous reservoirs with reacting flows, such as those encountered in shale oil extraction. A set of dimensionless parameters and a 3D code are developed in order to investigate the important physical and chemical variables of such reservoirs when heated by in situ methods. This contribution builds on a 1D model developed for the precursor study to this work. Theory necessary for this study is presented, namely shale decomposition chemical mechanisms, governing equations for multiphase flow in porous media and necessary closure models. Plotting the ratio of the thermal wave speed to the fluid speed allows one to infer that the reaction wave front ends where this ratio is at a minimum. The reaction front follows the thermal front closely, thus allowing assumptions to be made about the extent of decomposition solely by looking at thermal wave progression. Furthermore, this sensitivity analysis showed that a certain minimum permeability is required in order to ensure the formation of a traveling thermal wave. It was found that by studying the non-dimensional governing parameters of the system one can ascribe characteristic values for these parameters for given initial and boundary conditions. This allows one to roughly predict the performance of a particular method on a particular reservoir given approximate values for initial and boundary conditions. Channelling and flow blockage due to carbon residue buildup impeded each method's performance. Blockage was found to be a result of imbalanced heating.
Blunt, Martin Julian (Imperial College) | Al-Jadi, Manayer (Kuwait Oil Company) | Al-Qattan, Abrar (KOC) | Al-Kanderi, Jasem M. (Kuwait Oil Company) | Gharbi, Oussama (Imperial College) | Badamchizadeh, Amin (CMG) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Bond, Deryck John (Kuwait Oil Company) | Skoreyko, Fraser A. (CMG)
The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed.
Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP.
Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin??. Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline.
Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.
Vibrations are caused by bit and drill string interaction with formations under certain drilling conditions. They are affected by different parameters such as weight on bit, rotary speed, mud properties, BHA and bit design as well as by the mechanical properties of the formations. During the actual drilling process the bit interacts with different formation layers whereby each of those layers usually have different mechanical properties. Vibrations are also indirectly affected by the formations since weight on bit and rotary speed are usually optimized against changing formations (drilling optimization process). Therefore it can be concluded that for optimized drilling reduction of vibrations is one of the challenges.
A fully automated laboratory scale drilling rig, the CDC miniRig, has been used to conduct experimental tests. A three component vibration sensor sub attached to drill string records drill string vibrations and an additional sensor system records the drilling parameters. Uniform concrete cubes with different mechanical properties were built. Those cubes as well as a homogeneous sandstone cube were drilled with different ranges of weight on bit and bit rotary speed. The mechanical properties of all cubes were measured prior to the experiments. During all experiments, drilling parameters and the vibration data were recorded. Based on analyses of the data in the time and the frequency domain, linear and non-linear models were built. For this purpose the interrelations of sandstone and concrete mechanical properties, drilling parameters and vibration data were modeled by neural networks. Application of sophisticated attribute selection methods showed that vibration data in both, time- and frequency domain, have a major impact in modeling the rate of penetration.
Description: This paper describes key initiatives of the HSE management system that has been developed, and implementation at KOC West Kuwait (WK) fields which resulted in 26 Million Man‐Hours worked without any lost time injury till 31 st March 2012. Application: The multi‐cultural composition of the workforce imposes specific difficulties in execution of HSE initiatives and application of the HSE Management System. Significant efforts have been made by HSE (WK) Team to address these areas using approaches such as communication & awareness on HSE Management System with all levels of Business partners and Company's employees. The initiatives and achievement that HSE West Kuwait has adopted resulted in minimizing the industrial incidents and Motor Vehicles Accidents. This paper also focuses on the process of implementation of various initiatives taken by the HSE (WK) to achieve a substantial lowering of HSE risks, reduction of disabling injuries and frequency rates, and employee HSE behavior, enhanced Contractor's HSE performance and many more indirect positive results. Significance of Subject Matter All of the company's activities have the potential to affect the health, safety and environment of its stakeholders and nearby communities in a positive or negative way. KOC is committed to managing these effects and the risks associated with its activities and products. To fulfill the commitment, HSE (WK) initiated following activities for the implementation of a HSE Management System at the field.
Ozyurtkan, Mustafa Hakan (Istanbul Technical University) | Altun, Gursat (Istanbul Technical University) | Ettehadi Osgouei, Ali (Istanbul Technical University) | Aydilsiz, Eda (Istanbul Technical University)
Static filtration of drilling fluids has long been recognized as an important parameter for drilling operations. Since the standard laboratory testing procedures only consider static conditions, the filtration and cake properties under continuous circulation and dynamic borehole conditions are not usually well determined. Therefore, the measurement of dynamic filtration is particularly important in order to mimic actual downhole conditions.
An experimental study has been carried out by the ITU/PNGE research group to characterize the dynamic filtration properties of clay based drilling fluids. This study is an impressive attempt to figure out the dynamic filtration phenomena of clay based muds. The experimental results obtained from a dynamic filtration apparatus (Fann Model 90) are reported in this study.
Bentonite and sepiolite clays based muds formulated with commercial additives have been investigated throughout the study. Numerous dynamic filtration histories with test duration of 45 to 60 minutes at temperature conditions ranging from 150 to 400 oF, and a differential pressure of 100 psi have been applied to muds. Three key parameters namely spurt loss volume, dynamic filtration rate (DFR), and cake deposition index (CDI) have been determined to characterize the dynamic filtration properties of mud samples.
Results have revealed that bentonite based muds have better dynamic filtration properties than those of sepiolite muds at temperatures up to 250 oF. However, they have lost their stability over 250 oF. Furthermore, formulated sepiolite based muds have remarkable dynamic filtration rates and cake depositions above 300 oF. To sum up, the experimental results of this study point out that sepiolite based muds might be a good alternative to drill wells experiencing high temperatures, particularly in deep oil, gas and geothermal wells.
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.
Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau.
An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message.
Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.