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Collaborating Authors
Drilling Fluids and Materials
Abstract Historically, shale instability is a challenging issue when drilling reactive formations using water-based muds (WBM). Shale instability leads to shale sloughing, stuck pipe, and shale disintegration causing an increase in fines that affects the rate of penetration. To characterize shale instability, laboratory tests including Linear Swell Meter (LSM), shale-erosion and slake-durability are conducted in industry. These laboratory tests, under different flow conditions, provide shale-fluid interaction parameters which are indicative of shale instability. The composition of WBM is designed to optimize these interaction parameters, so that when used in the field the fluid helps achieve efficient drilling. This paper demonstrates modeling of shale-fluid interaction parameters obtained from the LSM test. In the standard LSM test, a laterally confined cylindrical shale sample is exposed to WBM at a specific temperature and its axial swelling is measured with time. The swelling reaches a plateau which is characterized by a shale-fluid interaction parameter called % final swelling volume (A). A typical LSM test runs for around 48–72 hours and many tests may be needed to optimize fluid composition. In this work, a method/model is developed to predict final swelling volume (A) as a function of the Cation exchange capacity (CEC) of the shale and salt concentration in the fluid (prominent factors affecting shale swelling). An empirical model in the form of A = f(CEC)*f(salt) which describes the explicit dependence on the influencing variables is developed and validated for 16 different shale samples at various salt concentrations. This model would significantly reduce LSM laboratory trials saving time and money. It could also enable rig personnel to obtain quick measure of shale characteristics so that WBM composition could be adjusted immediately to avoid shale instability issues.
- Asia (0.69)
- North America > United States (0.47)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics (1.00)
Abstract 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 °F) on the viscosity of water based mud has been presented.
Abstract During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid. It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid. It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.
- Asia > Middle East > Kuwait (0.29)
- Asia > Middle East > Qatar (0.28)
- Asia > Middle East > Qatar > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Block 6 > Al Khalij Field > Mishrif Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Najmah Formation (0.99)
- (4 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (3 more...)
The Mystery of Vanishing MWD/LWD Tools in Downhole: Interaction of Heavy WBM, Complex Petrophysical Formation Properties and Tool Metallurgy in Deep Kerogen-rich Carbonates
Acharya, Mihira N. (Kuwait Oil Company) | Kabir, Mir R. (Kuwait Oil Company) | Al-Ajmi, Saad A. (Kuwait Oil Company) | Al-Doheim, Arif A. (Kuwait Oil Company) | Dashti, Qasem (Kuwait Oil Company) | Al-Anzi, Ealian H. (Kuwait Oil Company)
Abstract Robustness of measurement while drilling (MWD) and logging while drilling (LWD) tools is laboratory-tested and rigorously field-tested for the expected operating and measurement specifications. Such tools have been used in the industry for decades with proven track record of stability. However, a typical tool string deployed as a part of bottom-hole assembly (BHA) has recently failed to withstand the unexpected BH conditions during drilling of the pilot hole using potassium formate mud (KFM), a heavy water based mud. The failure occurred within a deep-fractured calcareous kerogen section (CKS). The tools had multiple surface communication failures; the first one was resolved as debris was found obstructing the rotorstarter part before drilling the CKS. The second failure occurred in the back-up tools, after drilling into the CKS and remained unexplained throughout drilling with the expectation of BH data recorded on memory. Inspection of the tool components, once the drilling was completed, revealed two major findings: First, some parts of the BHA, specifically the components of the CuBe tool had "vanished". Secondly, the recovered tool parts had further damage due to corrosion and pitting. In addition, an unexpected color change in metal body parts was observed. In the paper, the authors explain the unique mystery of tool eating "down-hole ghost". Similar tools were previously used without an issue at comparable high pressure and temperature conditions and in geological sections alike in Kuwait in drilling with oil-based mud. The service provider's operational experience elsewhere has failed to explain the bizarre outcome, as they had not encountered similar incidents of vanishing tool parts and down-hole color change. The claim was that similar tools were successfully operated in water-based mud drilling including KFM. This claim was confirmed prior to the field execution with metallurgical compatibility tests carried out by the mud supplier.
- Europe (0.68)
- Asia > Middle East > Kuwait (0.51)
- Geology > Mineral (0.99)
- Geology > Geological Subdiscipline (0.69)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Measurement while drilling (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
Impact of Hydrolysis at High Temperatures on the Apparent Viscosity of Carboxybetaine Viscoelastic Surfactant-Based Acid: Experimental and Molecular Dynamics Simulation Studies
Yu, Meng (Texas A&M University) | Mu, Yan (South China University of Technology) | Wang, Guanqun (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Summary 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 wormlike 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.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.46)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- North America > United States > Wyoming > Bighorn Basin (0.99)
- North America > United States > Montana > Bighorn Basin (0.99)
- (2 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Summary Fracture fluid damage caused by residual polymer gel in propped fractures results in low fracture conductivity and short effective fracture length, sometimes severely reducing the productivity of a hydraulically fractured well. The residual gels are concentrated in the filter cakes built on the fracture walls and have much higher polymer concentration than the original gel. The residual gel exhibits a higher yield stress and is difficult to remove after fracture closure. In this work we studied polymer gel behavior theoretically and experimentally in hydraulic fracturing. We developed a model to describe the flow behavior of residual polymer gel being displaced by gas in parallel plates. We developed analytical models for gas/ liquid two-phase stratified flow of Newtonian gas and non-Newtonian residual gel to investigate gel cleanup under different conditions. The concentrated gel in the filter cake was modeled as a Herschel-Bulkley fluid, a shear-thinning fluid following a power law relationship, but also having a yield stress. The model developed shows that three flow regimes may exist in a slot, depending on the gas flow rate and the filter-cake yield stress. At low gas velocities, the filter cake will be completely immobile. At higher gas velocity, the shear at the fracture wall exceeds the yield stress of the filter cake, and the gel is mobile, but with a plug flow region of constant velocity near the gas/gel interface. Finally, at high enough gas velocity, a fully developed velocity field in the gel is created. The parameters for the gel displacement model were evaluated by experiments. We examined the filter-cake formation by pumping the fracture fluid through a conductivity cell, allowing leakoff to build the filter cake, measuring the cake thickness, and flowing gas through the cell to simulate the cleanup process. The results show that the yield stress of the residual gel plays a critical role in gel cleanup.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
Offshore Drilling Waste Discharge: Egyptian Environmental Regulations
Agwa, Ahmad (Development Drilling Group, Kuwait Oil Company KOC) | Sadiq, Rehan (Okanagan School of Engineering, The University of British Columbia, Kelowna, BC, Canada) | Leheta, Heba (Naval Architecture and Marine Engineering Department, Faculty of Engineering, Alexandria University, Alexandria, Egypt)
Abstract Egypt is located in the Northeast of Africa where oil and gas (O&G) are produced offshore from the Gulf of Suez and the Southeast part of the Mediterranean. The O&G production in Egypt is distributed as follows: 70% Gulf of Suez, 16% Western desert, 8% Sinai Peninsula and 6% Eastern desert. Past O&G activities, refining and transport have resulted in chronic pollution in Egyptian offshore, and numerous environmental programs have been initiated to protect new development areas from the environmental impacts. The offshore drilling process uses drilling fluids (muds) and generates waste fluids and cuttings, which could be the largest discharges going into the receiving water bodies. Water-based drilling fluids are commonly employed for drilling in Egyptian offshore because of their expected environmental benign behavior in the marine environment. The main objective of this paper is to highlight relevant Egyptian environmental regulations and explain several options to manage offshore drilling wastes: offshore discharge, offshore down-hole injection and onshore disposal.
- Asia > Middle East > Saudi Arabia (1.00)
- Africa > Middle East > Egypt (1.00)
- Geology > Mineral (0.73)
- Geology > Geological Subdiscipline (0.47)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.35)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > HSSE standards, regulations and codes (1.00)
- Health, Safety, Environment & Sustainability > Environment > Waste management (1.00)
Abstract 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%.
- Asia (0.28)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (3 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics (1.00)
Derivation of Kinetic Rate Constant of Enzyme-Buffer Mud Cake Clean Up Systems - Laboratory Investigation and Verification in High Temperature Fractured Carbonate Reservoir
Mehtar, M. A. (ADMA-OPCO, Abu Dhabi) | Kasam, Y.. (ADMA-OPCO, Abu Dhabi) | Al-Aleeli, A.. (ADMA-OPCO, Abu Dhabi) | Ghosh, B.. (The Petroleum Institute, Abu Dhabi) | Ghosh, D.. (Epygen Labs. Dubai) | Chaudhuri, B.. (Department of Pharmaceutical Sciences and Institute of Material Sciences, University of Connecticut, USA)
Abstract Horizontal wells enable drainage from a longer wellbore which helps to allow lower drawdown rate compared to vertical wells, minimizing gas or water coning. However productivity can be seriously affected unless mud cake damage is efficiently removed from all producing intervals along the horizontal wellbore. In recent years eco-friendly and non-corrosive bioenzymes (α/β-amylase) have shown great potential in cleaning wellbores uniformly and achieving higher well productivity. However in a low pressure fractured reservoir, there is always a possibility of localized reaction and loss of the clean-up fluid, unless the reactivity of the fluid is engineered based on the given well parameters. In this study α-amylase enzyme is modified to withstand higher thermal shock by structurally reinforcing the β-Helix layer to strengthen the catalytic centre by preferential protein hydration technique. Buffering was done to maintain different system pH and kinetic rate constant is derived through reducing sugar release measurement by DNS method using starch-xanthan gum-CaCO3 based drill-in-fluid as substrate. Though the overall reaction is extremely complex, a good correlation could be drawn between system pH and the rate of breaking mud cake into simple sugar. The kinetic rate constant index is used in final formulation of enzymatic clean up fluid for application in high temperature (110 °C) long horizontal wells drilled in carbonate formation, which allowed different soaking time due to operational constraints. The results show that there is excellent correlation between laboratory prediction and clean up efficiency in terms of well productivity.The study showed that each individual well demands a specific formula for clean-up fluid and higher than prognosed production could be achieved through custom formulation, based on well condition and operational requirement.
- North America > United States (0.94)
- Europe (0.93)
- Asia > Middle East > UAE (0.29)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
Abstract The two main parameters required to assess an enhanced oil recovery (EOR) technique in terms of its efficiency are interfacial tension and surface (wettability) alteration. The impact of these parameters on recovering what is left in the reservoir is crucial. With the current interest in brine injection as a potential-EOR method, the role of IFT and wettability alteration needs better understanding. In this study, a theoretical model is developed to evaluate the impact of both parameters. The results of this study indicate that salinity injection affects more surface wettability rather than interfacial tension. Conventional techniques of contact angle measurements on reservoir rocks at downhole conditions are very complicated. They are highly sensitive and require good core preservation and preparation. We propose a protocol to measure contact angle dependence on brine salinity, which includes a single contact measurement in rock/brine/oil system using fresh water and a set of less complicated measurements in brine/oil and rock/brine/air systems. The results of our predictive protocol for contact angle measurements are in very good agreement with conventional experimental measurements using glass/brine/dodecane system. The fact that simple contact angle measurements on the surface in air are required to calculate contact angles at different salinities makes the utilization of this protocol very attractive and less sensitive to surface preparation and its complexity.
- Asia > Middle East (0.47)
- Europe > Austria (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.84)