Yim, Y. (Petroleum Institute) | Haroun, M. R. (Petroleum Institute) | Al Kobaisi, M. (Petroleum Institute) | Sarma, H. K. (University of Calgary) | Gomes, J. S. (ADNOC E&P) | Rahman, M. M. (Petroleum Institute)
Smartwater flooding is a promising oil recovery technique, demonstrating positive results in many laboratory and field tests, by altering salinity and ionic composition of injection water. Injection of smartwater in carbonate reservoirs has gained interest due to its potential feasible application, taking advantage of improved oil recovery. Electrokinetic enhanced oil recovery (EK-EOR) is another rising technology that involves passing low D.C. current through the reservoir between a subsurface anode and cathode in the producing well. It has demonstrated a number of advantages including fluid viscosity reduction, permeability enhancement and reduced water cut. Our formulation aimed at advancing their combined mechanisms through a novel hybrid EOR. This study is the first attempt to present the experimental work on Smartwater Flooding integrated with the application of Electrokinetics (EK).
The effects of total salinity, reducing monovalent ions (Na+ and Cl-) and spiking of multivalent anions (SO42-) on the crude oil/brine/rock interaction were studied. Zeta potential tests were integrated with core flooding experiments systematically designed to identify the optimum ionic concentration and current density. Optimization of current density was essential for controlling both Cl2 gas generation and formation damage. EK showed positive effects with our designed Smartwater, when optimum currentdensity was induced, allowing earlier production and incremental displacement efficiency of 2.4-6%.
Haroun, Mohamed (Petroleum Institute) | Mohammed, Abdul Moqtadir (Petroleum Institute) | Somra, Bharat (Petroleum Institute) | Punjabi, Soham (Petroleum Institute) | Temitope, Ajayi (Petroleum Institute) | Yim, Youngsun (Petroleum Institute) | Anastasiou, Stavroula (Petroleum Institute) | Baker, Jassim Abu (Petroleum Institute) | Haoge, Liu (Petroleum Institute) | Al Kobaisi, Mohammed (Petroleum Institute) | Karakas, Metin (University of Southern California) | Aminzadeh, Fred (University of Southern California) | Corova, Francisco (Petroleum Institute)
Surfactant Foam assisted CO2 EOR, though getting traction for its environomic mobility control potential, faces numerous challenges for deployment in HPHTHS heterogeneous carbonate reservoirs. Amongst the major challenges, the first is the lack of a surfactant formulation compatible with our carbonate reservoirs and the second is the absence of a foam and CO2 front monitoring tool either at laboratory or field scale.
In this study, a novel monitoring technique has been developed to track quality of the foam while core-flooding. This is essential to capture the onset formation, development rate and break-through of the said foam across varying length of core-plugs. This has been previously conducted in lab-scale by virtue of pressure response with or without expensive imaging methods. This tool complements the conventional method of studying pressure response with resistance measurements across the core allowing tracking of the foam generation and propagation. Various preconditioning smart brines (SB) were alternatively injected with the non-ionic surfactant APG, co-injected with gas, to generate foam
The foam generation, stability and breakthrough were studied as a function of salinity, ion composition and injected pore volumes of the various brines and surfactant. Core-plugs of 2 different rock types were flooded with 4 variations of smart brines at a constant flow rate. The tested formulations were ramped up from 2 to 8 pore volumes. The response of the ΔP/PV integrated with the Δρ/PV curves were analysed to detect foam generation and breakthrough. This allowed an immediate characterization of the foam performance providing capability of tracking the foam formation/dissipation across the length of the core-plugs, essential for compatible successful foam formulation.
This novel method allowed for instantaneous resistance observations in lab-scale along with the pressure response. The performance of the monitoring technique provided a new dimension in understanding foam flooding. This was integrated to provide comprehensive analysis of the formulated foam. Our innovative method provides the capability of quicker screening to successfully generate foam
Pantelides, Sokrates T. (Vanderbilt University) | Prabhakar, Sanjay (Vanderbilt University) | Liu, Jian (Vanderbilt University) | Zhang, Yu-Yang (Vanderbilt University) | Lai, Chia-Yun (Masdar University) | Chiesa, Matteo (Masdar University) | Alhassan, Saeed (Petroleum Institute)
Extraction of oil from wells is hampered by the fact that oil sticks to rock surfaces and water does not pry it loose easily. Technically, this is an issue caused by the relative wettability of rock surfaces. Experiments have shown that Na ions that are present in sea water have a negative effect on oil extraction, while Ca, Mg, and other ions enhance oil extraction. However, only limited understanding of the pertinent mechanisms has been achieved. Atomic-scale modeling of wettability is usually pursued using classical molecular dynamics based on empirical potentials. Only limited research based on quantum mechanical calculations has been reported so far. Here we describe the development and implementation of parameter-free, quantum-mechanical approaches, at different levels of approximation, that can provide detailed understanding of relative wettability and have predictive capabilities. At the lowest level of approximation, we calculate the binding energies of water and prototype oil molecules to calcite surfaces in vacuum as indicators of relative wettability. At the next level, we calculate binding energies in the presence of liquid water using quantum molecular dynamics. We find that the binding energy of Na acetate is larger than the binding energy of acetic acid, a prototype oil molecule, which suggests that, upon reacting with Na ions, a layer of oil becomes stickier on calcite rocks. On the other hand, Ca and Mg acetate desorb easier than acetic acid, facilitating oil extraction, as observed. At a much more sophisticated level of approximation, we calculate the wetting angle, a measurable quantity that serves as a measure of relative wettability. We applied this method to water on graphene and graphitic surfaces, which has been studied extensively and for which we have obtained new experimental data.
Ahmed, Shehzad (Universiti Teknologi Petronas) | Elraies, Khaled Abdalla (Universiti Teknologi Petronas) | Hashmet, Muhammad Rehan (Petroleum Institute) | Bt Mohd Shaifan, Siti Rohaida (Petronas Research Sdn Bhd) | Hsia, Ivy Chai Ching (Petronas Research Sdn Bhd) | Bahrim, Ridhwan Zhafri Kamarul (Petronas Research Sdn Bhd)
Polymer enhanced foam (PEF) provides an additional strength over conventional CO2 foams for mobilizing oil from the unswept low permeable oil rich zones during an enhanced oil recovery process. The efficiency of the process depends on two major factors i.e. stability and apparent viscosity of PEF. In this study, an experimental investigation of apparent viscosity and stability of polymer enhanced CO2 foam is presented with an objective to assess the polymer performance and to identify the best performing polymer under reservoir conditions of 1500 psi and 80 °C.
For this purpose, conventional standard hydrolyzed polymacrylamide (HPAM) polymers and an associative polymer i.e. Superpusher P329 were used in combination with a widely used foamer i.e. alpha olefin sulfonate (AOS) and a foam stabilizer i.e. betaine. Foam stability tests were conducted in the presence of crude oil using FoamScan. Whereas for foam rheological study, a high pressure high temperature Foam Rheometer was utilized and the foam was sheared over the range of 10 to 500 sec-1 inside the recirculating loop.
As compared to other HPAMs, an associative polymer i.e. Superpusher P329 significantly amplified foam longevity and provided a more prolonged liquid drainage. A shear thinning behavior was observed for the entire range of shear rate tested and for all the tested foam. HPAMs were found ineffective in improving foam apparent viscosity and the viscosities obtained were found equivalent to that to polymer free foam. Superpusher P329 showed interesting combination with AOS and significant viscosity enhancement has been reported in this paper.
This research concluded that Superpusher P329 has the ability to generate strong foam and it is a potiential candidate for mobility control during polymer enhanced CO2 foam flooding process.
CO2 injection into a mature oil field for EOR purpose is widely accepted and economical technique. The ultimate recovery during CO2 flood is affected by poor sweep efficiency due to various associated constraints such as reservoir hetrogenities, gravitational segregation and viscous fingering of gas. CO2 combination with surfactant solution for the generation of foam is an effective process that significantly lowers the gas mobility and improves macroscopic sweep efficiency. Foam is a dispersion of gas in a continuous liquid phase such that some part of the gas phase is made discontinuous by a thin liquid film called lamella. Foams of conventional surfactants deteriorate quickly and they have limited foam generation ability and due to this reason these are not widely implied as general EOR method. It is a focus of research to generate strong foam under reservoir conditions which provides a high reduction in injected phase mobility thus providing a better sweep efficiency.
Omosebi, O. A. (University of Oklahoma) | Sharma, M. (University of Oklahoma) | Ahmed, R. M. (University of Oklahoma) | Shah, S. N. (University of Oklahoma) | Saasen, A. (University of Stavanger) | Osisanya, S. O. (Petroleum Institute)
AbstractSignificant amount of oil and gas reserves contain CO2 and H2S. Leakage of these gases to fresh water aquifers and their escape to the surface compromises human health and safety and create unthinkable environmental hazards. Cement exposed to these acid gases degrade, thereby promoting their release through the wellbore to overlying fresh water formations and/or the environment. This study investigates how these contaminants aid the corrosion of well cement in high pressure-high temperature (HPHT) environment.Experiments were conducted under two broad test conditions. In the first case, cement cores were aged at 100°F in CO2-H2S brine solution. The total test pressure was varied from 3000 psi to 9000 psi. In the second case, cement cores were exposed to brine saturated with gas mixture comprising H2S, CO2, and CH4 at total test pressure of 6000 psi. Temperature was varied from 100°F to 350°F. The compressive strength, shear bond strength, porosity, and permeability of the aged and unaged specimens were measured to quantify the alteration in these critical cement properties. Observations are supported with FTIR, SEM and EDS analyses.As temperature increases, the presence of H2S shows more impact on the loss of mechanical strengths and increase in transport properties of Class G cement than Class H cement. Variation of H2S concentration also shows significant impact on cement integrity.Compared to previous study involving the exposure of cement to pure CO2, the presence of H2S improves the relative strength of cement. However, transport properties are compromised. FTIR mineralogy confirms that the extent to which cement is carbonated by CO2 is limited by the presence of H2S. In addition, SEM and EDX indicate that ettringite was formed at low temperature (100°F). However, it dissolves at high temperature (350°F) without significantly compromising the structural integrity of cement.The most significant new finding in this study is that the presence of H2S and its coexistence with CO2 under HPHT conditions minimizes the loss of the structural integrity of well cement by pure CO2. This is important because it narrows down the most significant factor to consider when designing acidresistant cements for HPHT wells.
Emad W. Al-Shalabi, Petroleum Institute; Haishan Luo, Mojdeh Delshad, and Kamy Sepehrnoori, University of Texas at Austin Summary The interest in low-salinity-water injection (LSWI) compared with seawater injection or high-salinity-produced-brine injection is increasing in both laboratory and field tests. The single-well chemical-tracer test (SWCTT) is also becoming increasingly popular as an in-situ test to assess the reduction in oil saturation caused by an enhanced-oil-recovery (EOR) process. Hence, accurate modeling of SWCTTs is essential. In this paper, modeling and simulation of the SWCTT of LSWI in a carbonate reservoir is investigated by use of the UTCHEM reservoir simulator, a nonisothermal, 3D, multiphase, multicomponent, chemical compositional simulator developed at the University of Texas at Austin (UTCHEM 2011). Both radial-and Cartesian-grid models are set up for a field-scale pilot by use of measured rock and fluid data of a Middle Eastern reservoir. Tracer reactions and the empirical LSWI model implemented in UTCHEM are used to estimate residual oil saturation (ROS) as a result of LSWI. Two approaches are used to estimate ROS to LSWI, including analytical and numerical methods. Results show that both approaches give consistent values for ROS for homogeneous radial-and Cartesian-grid models. The two approaches were inconsistent for the multilayer radial model, which highlights the necessity of the use of numerical approaches for layered reservoirs. The Cartesian-grid model was used to investigate the effect of heterogeneity on SWCTT results, where a new numerical approach is proposed for estimating ROS. This finding validates the approach used and the implementation of both tracer reactions and the LSWI model in UTCHEM.
In this paper, a new FPGA-based THz imaging device for real-time multiphase flow metering is proposed. The overall system consists of a THz source and a THz camera within which a stainless steel-flanged Teflon-made cylindrical probe is provided to carry the multiphase flow. Hence, the system acts like an X-ray-based device but has the advantage of having non-ionizing waves which makes it a safer alternative. In addition, the system provides a much informative indication about the flow by capturing its two-dimensional image in real-time and without the requirement of performing the time-consuming and errorless-free image tomography techniques. The THz camera consists of 64 × 64 pixels which represent the actual accumulated dielectric of objects value within a projected line in the space. The camera provides the pixel values via a digital video bus (USB port) to an FPGA board for real-time video processing and display. The video processing consists of a cascade of consecutive tasks which include image filtering and histogram, feature extraction and counting (for phase fraction measurement), in addition to block-based motion estimation (for flow rate measurement). This constitutes a breakthrough in the field of multiphase flow metering since this task can take full advantage of the mature and advanced techniques achieved in video processing to achieve the most accurate and informative multiphase flow measurement. Extensive experimental tests were successfully carried out on the developed device using various samples with different concentrations of water and air. Hence, an accuracy of 90.2% for the multiphase flow measurement, with a total processing time of 110 ms/frame were achieved. This can be improved even further if a more advanced FPGA featuring high speed clock, in addition to more advanced video processing algorithms are simultaneously used.
Scale inhibitor (SI) squeeze treatment is an established practice in offshore fields to prevent inorganic scale deposition in the wellbore and near wellbore formation. Squeeze lifetime is measured by the duration for which the concentration of the chemical is released at a concentration above the required minimum inhibitor concentration (MIC). Hence, maximizing SI adsorption to the pore surfaces may proportionately enhance squeeze lifetime. However, most oil-field squeeze scale inhibitors being aqueous-based, it is unlikely to get optimum adsorption on an oil-wet formation due to unfavorable rock surface condition. This work is targeted towards optimum formation conditioning through an intelligently designed pre-flush treatment; so that the adsorption and lifetime of SI in an oil-wet carbonate reservoir are significantly improved.
Eco-friendly APG surfactants are evaluated with and without alkali and co-surfactants to design the pre-flush composition. A series of coreflood experiments are conducted in simulated reservoir conditions, using data and materials from a high temperature carbonate oil reservoir from the Middle-East. The results are evaluated in light of IFT and phase behavior and changes of rock wettability due to pre-flush treatment.
The results show that SI squeeze lifetime can be enhanced by as much as 240% when compared to conventional treatment and it has a direct correlation with wettability index and IFT. Anionic surfactant may look more attractive than nonionic surfactant due to favorable wettability alteration and highly reduced IFT, however they may not be the right choice for carbonate formation due to higher adsorption and competition with scale inhibitor molecules. Cost benefit analysis evince that introduction of the newly designed pre-flush treatment would results in improved economics through reduced treatment frequency, leading to minimized well intervention and consequent production loss.
Not enough attention is given on the design/optimization of pre-flush and conditioning of the formation to be used as adsorbent/storehouse of the inhibiting chemical in preferentially oil wet carbonate formations. The applicability of surfactant-alkaline has been long established as means of EOR mechanism but they are rarely investigated for near wellbore treatments to maximize chemical storage and placement; which is what this work has studied.
Corrosion under insulation (CUI) is a major problem for industry. Extensive removal and reinstatement of insulation for inspection is prohibitively costly. A non-destructive testing (NDT) tool which can characterise areas of CUI damage in insulated piping and pipelines with minimal removal of insulation is required. Sufficient data about the CUI is required to allow Fitness for Service to be assessed.
Guided wave testing (LRUT) is a long range ultrasonic technique that was developed in the mid 1990’s to provide the solution to CUI inspection of piping and pipelines. The technology, understanding and application of LRUT has been continuously developed over the last 15 years, but is still a screening technique which is currently unable to provide dimensions of CUI. Indications reported by LRUT must thus be followed up using a second NDT technique to confirm and quantify CUI damage.
A project sponsored by the Petroleum Institute, Abu Dhabi, has been established to improve on commercially available LRUT and develop a Fitness for Service tool to allow integrity management decisions to be made from LRUT inspections.
In the first phase of the project, an independent evaluation of the performance of LRUT was performed, in terms of probability of detection (POD) for the system and operators/analysts. A purpose built test loop was constructed to be representative of real-world conditions, including metal loss defects simulating CUI. Future phases will (i) evaluate and develop better understanding of key variables and factors affecting the performance of LRUT, aiming at developing best practice guidance, and (ii) develop a Fitness for Service tool based directly on LRUT data. The results of the first phase are presented in this paper, with a number of interesting observations and lessons learnt that can aid in improving the outcomes from LRUT for CUI and for piping and pipelines in general.
Removing signal distortions due to near surface complexities is the key challenge for land seismic data imaging. In the Middle East, where several major oil fields are located onshore, these complexities require developing new technologies: as extreme shallow velocity variations occur occasionally elsewhere, not enough research and development has been carried out to fully compensate them so far. In addition, the common recording geometry for deep targets produces a near-surface information gap (Vesnaver 2005). In this paper we review recent advances and some ongoing research that address this problem, with applications to real cases in the Arabian Peninsula.
The first technique reviewed is the inversion of the vibrator plate controller data, normally available in the Vibroseis seismic records, but rarely used for improving the Earth imaging. We show that it helps removing high-frequency spatial distortions due to local soil anomalies. As recording this data is part of standard field operations, its use comes almost for free, as the related processing is not heavy in terms of computing power.
A second cost-effective approach is the integration of seismic and satellite imagery. The resolution commercially available for Earth images in various electromagnetic bands is fitting the normal bin size adopted in 3D seismic surveys, e.g., 25×25 m. Thus, correlating the soil properties in terms of back-scattered radiation with physical properties as P-wave velocities or Q factor, allows improving the resolution of the shallowest layer in our Earth model. As this layer – (the so-called weathering) – is normally the most heterogeneous, improving its estimate allows removing better the related distortion for imaging the possible underlying oil and gas reservoirs.