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.
Whole level of the erosion and the resistance of rocks which were composed closured have been studied, besides, the impact of temperature and laser irradiation for more investigation about this issue has been involved before all. This subject more reveals the matter which laser absorption on the laboratory scale using laser to what extent can cause the augment of the relative permeability and secondary porosity of reservoir rock, that of the vertical and horizontal useful connectivity and eventually that of the positive transferability.
This research has been carried out in the form of case study on one of Iranian south west formations in north east of Behbahan city in Iran, either the rate or generation of forming the subtle and large fractures has been studied by considering and preparing this section from rocks of stratified sequence of the laboratory area before and after the laser irradiation operation and various analyzer by the means of Spectrophotometer and advanced electron microscope. It should be noted that during the erosion and ablation in the laser drilling operation in the experimental rocks of considered field, given the capability of the field, the formation and field lithology we observed the creation of fractures at the level of micro and nano simultaneously whose vacant spaces were positive, and reservoir and some others were neutral, this fractures can be created by the rate of crude oil absorption. The main purpose of this study is to advance the operations towards the higher technology in order to the better efficiency in the field of the well completion to be gained improving the rate of oil production by the introduction of this modern method of improving and fracturing reservoir which uses certain specialized parameters and indicators, and, finally, the certain method that might be a better way to use laser irradiation on our chosen formation of Iran.
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.
Thread compound "dope?? in the vernacular, has been used routinely in assembling joints of casing and tubing. The practice in almost universal application in the oil and gas industry involves the manual application of the lubricant in a fashion that is rudimentary, non-systematic and unquantifiable. There is evidence presented in this paper that damage to the near-well zone and other unpleasant events may be associated with the thread compound.
This paper presents the results of both laboratory and field investigations quantifying the effects of the dope on near-well damage. During the assembly of tubing and casing a portion of the thread compound is exuded inside and outside the connection and gets access to the well fluids through the tubing and annular space. Studies presented here show that the dope forms a suspension which penetrates and damages the formation. The studies used standard fluid circulation velocities during typical completion operations.
To characterize and quantify the problem, core samples from the El Tordillo field, with different permeabilities were used. The samples were subjected to the circulation of the suspension created by the thread compound and the completion fluid, measuring the change in the core permeability. The work simulated the well conditions during water injection for water injection wells and during acid treatments for producer wells. A significant reduction in permeability, manifested by a fast and a very large increase in pressure, was measured, at the front face of the core sample. The same measurements showed a far smaller impact in the core body suggesting very minor penetration of dope particles.
This paper describes the laboratory and field work, with description of the test protocols, well conditions and laboratory emulation of field conditions that were used.
Carboxybetaine viscoelastic surfactants have been applied in acid diversion and fracturing treatments in which high temperatures and low pH are usually involved. These surfactants are subjected to hydrolysis under such conditions because of the existence of a peptide group (-CO-NH-) in their molecules, leading to changes in the rheological properties of the acid. The objective of this paper is to study the impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine viscoelastic surfactant-based acids, and propose the mechanism of viscosity changes by molecular dynamics (MD) simulations.
Surfactant-acid solutions with different compositions (surfactant concentration varied from 4 to 8 wt%) were incubated at 190°F for 1 to 6 hours. Solutions were then partially spent by CaCO3 until the sample pH was 4.5, and the apparent viscosity was measured using a high-temperature/high-pressure (HT/HP) viscometer. To understand the mechanism for viscosity changes on the molecular level, MD simulations were carried out on spent surfactant-acid aqueous systems using the Materials Studio 5.0 Package.
It was found that short-time hydrolysis at high temperatures (for example, 1 to 2 hours at 190°F) led to a significant increase in surfactant-acid viscosity. However, after incubation for 3 hours, phase separation occurred and the acid lost its viscosity. Simulation results showed that viscosity changes of amido-carboxybetaine surfactant acid by hydrolysis at high temperatures may be caused by different micellar structures formed by carboxybetaine and fatty acid soap, its hydrolysis product. The optimum molar ratio of amido-carboxybetaine and fatty acid soap to form worm-like micelles was found to be nearly 3:1 from our simulations.
Our results indicate that hydrolysis at high temperatures has a great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel breakdown can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.
Recent work has shown the potential usefulness of both magnetic susceptibility and magnetic hysteresis techniques in assessing the effect of fine-grained hematite on permeability, where the hematite was dispersed in the matrix of relatively tight gas red sandstone samples. The present study demonstrates that grain lining hematite cement is also a major controlling factor on permeability in a relatively tight gas sandstone reservoir in the North Sea. Magnetic susceptibility measurements on core plugs in this reservoir showed a strong correlation with probe permeability. Moreover, samples with a higher content of hematite exhibited lower permeability values. Thin-section analysis revealed the presence of a thin (approximately 10 to 15 lm) rim of hematite cement surrounding quartz grains, which block pore connections and reduce permeability. Magnetic hysteresis measurements on representative samples indicated a similar paramagnetic clay content in both the low and high permeability samples, suggesting that the clay (mainly illite) is not the dominant controlling factor that produces the variations in permeability that we observed. Because samples with higher hematite content exhibit lower permeability, it appears that hematite is a major control on the permeability variations seen in this reservoir. Although the paramagnetic clays undoubtedly have an influence on the absolute permeability values (increasing paramagnetic clay content has previously been shown to correlate with decreasing permeability), small amounts of grain lining hematite cement can reduce the permeability significantly further. Analysis of the magnetic hysteresis parameters on a Day plot indicated that the permeability was essentially independent of the hematite particle size for the fine particle sizes observed in this study.
Alaskar, Mohammed N. (Stanford University) | Ames, Morgan F. (Stanford University) | Connor, Steve T. (Stanford University) | Liu, Chong (Stanford University) | Cui, Yi (Stanford University) | Li, Kewen (Stanford University) | Horne, Roland N. (Stanford University)
The goal of this research was to develop methods for acquiring reservoir pressure and temperature data near the wellbore and farther out into the formation and to correlate such information to fracture connectivity and geometry. Existing reservoir-characterization tools allow pressure and temperature to be measured only at the wellbore. The development of temperature- and pressure-sensitive nanosensors will enable in-situ measurements within the reservoir. This paper provides the details of the experimental work performed in the process of developing temperature nanosensors. The study investigated the parameters involved in the mobility of nanoparticles through porous and fractured media. These parameters include particle size or size distribution, shape, and surface charge or affinity to rock materials.
The principal findings of this study were that spherically shaped nanoparticles of a certain size and surface charge compatible with that expected in formation rock are most likely to be transported successfully, without being trapped because of physical straining, chemical, or electrostatic effects. We found that tin-bismuth (Sn-Bi) nanoparticles of 200 nm and smaller were transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle size range. We also found that the entrapment of silver (Ag) nanowires was primarily because of their shape. This conclusion was supported by the recovery of the spherical Ag nanoparticles with the same surface characteristics through the same porous media used during the Ag nanowires injection. The entrapment of hematite nanorice was attributed to its affinity to the porous matrix caused by surface charge. The hematite coated with surfactant (which modified its surface charge to one compatible with flow media) flowed through the glass beads, emphasizing the importance of particle surface charge.
Preliminary investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. We found that silica microspheres of different sizes (smaller than the fracture opening) could be transported through the fracture. We demonstrated the possibility of using microspheres to estimate fracture aperture by injecting a polydisperse microsphere sample. It was observed that only spheres of 20 µm and smaller were transported. This result agreed reasonably well with the measurement of hydraulic fracture aperture (27 µm), as determined by the cubic law.
The oil-based drill solids are regarded as controlled or hazardous waste since it is contaminated with oil and other organic/inorganic contaminants. As such, the drill solids can be disposed with 3 different ways: (1) decontamination treatment before discharged into the sea; (2) re-injecting the drill solids into the well or (3) hazardous waste controlled landfill. The disposal of the drill solids in the landfills is usually the last environmental option. The lowest environmental impact way for the solid disposal, especially for offshore operation, is still a decontamination treatment before discharged. However, the conventional decontamination technology still exhibits limited efficiency to extract oil from the drill solids; yielding the oil content in the treated solids of much greater than 1% oil content in the dried solids, which does not meet a strict environmental regulation in many highly ecological-sensitive countries (e.g. UK and North Sea countries, etc.).
This paper demonstrates a new promising technology to overcome this efficiency limitation, called nanoemulsion. Nanoemulsion is a water-in-oil emulsion, having the Winsor type III or IV stages but with high surfactants-to-interface ratio. When analyze using dynamic light scattering, it shows the natural distribution of <100nm particle size. Nanoemulsion is able to provide ultralow interfacial tension (IFT) of <0.01mN/m. According to Laplace Pressure equation, when IFT is extremely low, less energy is required to remove the oil that trapped inside the pores. Recently Nanoemulsion has been demonstrated able to remove sticky oil-base mud inside the wellbore and able to suspend the mud after treatment. When using it to remove the oil from the drill solids, it is able to reduce the contact angle and capillary force on the solid particle surface, subsequently, allowed water to penetrate and wet the particle surface and accessible pores. This mechanism indeed converts the surfaces become water-wet (hydrophilic). Once the particles surfaces are water-wet, oil will instantly desorb from it and easily segregate through centrifuge force. Different proposed process will be shared and discussed in this work. It was found that the oil content in the drill solids after treatment with nanoemulsion cleaning process was able to reach <1%.
Edwards, John Ernest (Schlumberger) | Herrera, Adrian (Schlumberger) | Judd, Tobias Conrad (Schlumberger) | Kristensen, Morten Rode (Schlumberger Middle East SA.) | Al-Rashdi, Yaqoob Salem (Petroleum Development Oman) | Hindriks, Cornelius
A new method of stress testing with a wireline tool uses a drilled hole sealed with a compression pad to apply hydraulic pressure to the reservoir. Geomechanics modeling shows why this reduces the fracture initiation pressure and avoids intersecting the borehole with the induced fracture. The superposition of two induced stresses, mechanical and hydraulic, causes the tensile failure to initiate towards the end of the drilled hole as the hydraulic pressure is increased. The 9-mm-diameter hole is drilled from the center of the sealing compression pad to a depth of up to 15 cm. A fracture initiating some distance from the wellbore will be located part way through the near-wellbore perturbed stress field and will propagate away from the wellbore to the far field in the direction of reduced minimum stress. Reservoir simulation shows that the leakage rate of injected fluid around the compression pad is insignificant.
The first jobs using this technique are described, including procedures for passive tool orientation so that the drilled hole is aligned with the maximum horizontal stress. Information revealed about breakdown pressures in tight dolomite explained why drilling-induced fractures were affecting resistivity logs and well test interpretation. The current procedure for stress testing is the pumping of drilling mud between inflated packers. The new technique described here solves two problems associated with the inflated packer method. The pumped fluid volumes are much smaller, so clean fracture fluid from a sample chamber can be used instead of mud. And the system compressibility is reduced, so the pressure transients are more responsive to the formation.
The ability to induce a fracture in the formation with a pad tool using dedicated fluid with a low dead volume creates a new way of connecting to the reservoir, an alternative to connecting via the borehole wall surface. This large, undamaged contact area due to the induced fracture beyond the drilling-damaged zone will facilitate sampling low-permeability formations or high-viscosity oils.
In order to screen various chemical and microbial EOR methods for core-flooding experiments and potential field trials, a laboratory investigation of evaluating the effect of micro-emulsion on the reduction of interfacial tension (IFT) was recently carried out at CSIRO by using commercially available chemical and bio-surfactants. Environment friendly non-ionic, anionic surfactants and a biosurfactant (Bacillus subtilis) were used to create micro-emulsion in an oil-brine system. Stable micro-emulsion (ME) was achieved by proportionally mixing various alcohols with surfactants.
Twenty-four micro-emulsion samples with five different chemical combinations were prepared for screening. All samples were stirred to create a stable ME phase. The volume changes of the ME phase were monitored over two weeks and their density, viscosity, and IFT were measured. The size distribution of ME phases was also characterised using optical microscopy equipped with an UV light source.
The micro-emulsion created by co-surfactants were found to be quite effective in reducing the oil-brine IFT and oil viscosity, and achieved ultra low IFT under reservoir pressure and temperature. There appears to be a linear relationship between the size of micro-emulsion and IFT reduction. ME with small sizes results in more IFT reduction and achieve stable ME at high temperature and pressure. Compared with the IFT reduction from the surfactant or microbial metabolism, the reduction of IFT through stable ME can be several orders of magnitude larger and may thus achieve better enhanced oil recovery in suitable reservoir systems.