Al-Nakhli, Ayman (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Al-Shehri, Dhafer (King Fahd University of Petroleum and Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum and Minerals)
Recent rise in global warming and fluctuations in world economy needs the best engineering designs to extract hydrocarbons from unconventional resources. Unconventional resources mostly found in over-pressured and deep formations, where the host rock has very high strength and integrity. Fracturing techniques becomes very challenging when implemented in these types of rocks, and in many cases approached to the maximum operational limits without generating any fracture. This leaves a small operational window to initiate and place the hydraulic fractures. Current stimulation methods to fracture these formations involve with adverse environmental effects and high costs due to the entailment of water mixed with huge volumes of chemicals such as biocides, scale inhibitors, polymers, friction reducers, rheology modifiers, corrosion inhibitors, and many more.
In this study, a novel environmentally friendly approach to reduce the breakdown pressure of the unconventional rock is presented. The new approach makes it possible to fracture the high strength rocks more economically and in more environmentally friendly way. The new method incorporates the injection of chemical free fracturing fluid in a series of cycles with a progressive increase of pressure in every cycle. This will allow stress relaxation at the fracture tip and correspondingly enough time for fracturing fluid to infiltrate deep inside the rock sample and weaken the rock matrix. As a result of which the tensile strength-ultimately the breakdown pressure of the rock gets reduced. The present study is carried out on different cement blocks.
The post treatment experimental analysis confirmed the success of cyclic fracturing treatment. The results of this study showed that the newly formulated method of cyclic injection can reduce the breakdown pressure by up to 24% of the original value. This reduction in breakdown pressure helped to overcome the operational limits in the field and makes the fracturing operation greener.
Ahmad, Hafiz Mudaser (King Fahd University of Petroleum and Minerals) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum and Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum and Minerals) | Khan, Sarmad (King Fahd University of Petroleum and Minerals) | Al-Harthi, Mamdouh (King Fahd University of Petroleum and Minerals)
Hydration of shale formations during drilling operations have adverse effects on wellbore stability. The shale hydration resulted from the interactions between drilling fluid and swelling clay contents in the shale formations. This paper addresses the improvement of wettability and hydration properties of shale to enhance the wellbore stability during the drilling operations. The novel ionic liquid-based drilling fluids were used to alter the wettability and hydration properties of shale. The novel ionic liquid based drilling fluid was developed by blending various ionic liquids and drilling fluid additives such as filtration control agent and rheological modifier. The rheology and filtration related properties of the base drilling fluid and its modified version with ionic liquids were determined. Shale inhibition characteristics of modified drilling fluids were evaluated by using real field shale sample and analyzing it with linear shale swelling test and hot rolling dispersion test. Two different ionic liquids (IL-1, IL-2) were deployed in the formulation of drilling fluids with a concentration of 0.05%. The conventionally used shale inhibitor KCl was also used in the formulation of drilling fluid with the concentration of up to 2%. The results of modified drilling fluids were then compared with the base drilling fluids prepared by mixing bentonite and cationic polymer (polydadmac). The rheological experiments showed that the addition of KCl and ionic liquids in the base drilling fluid resulted in a decrease in rheological properties. The filtration experiments also showed that filtrate volume has increased with the addition of KCl and ionic liquids in the drilling fluids. The hot rolling shale recovery experiment was performed at 65°C and superior shale recovery was observed with the synergistic effect of B/IL-2/K drilling fluid. Linear swelling of shale was assessed over a time period of 10 hours and minimum linear swelling of shale was observed with B/IL-2/K drilling fluid which indicated that the ionic liquid in the drilling fluid chemically interacts with the shale surface and makes it hydrophobic in nature which limits the interactions of water with shale. This use of novel ionic liquid-based drilling fluid enhances the borehole stability by modifying the shale surface and resulted in improved wellbore stability. The novel drilling fluid also has superior rheological, filtration properties and salt tolerance.
Murtaza, Mobeen (King Fahd University of Petroleum & Minerals) | Rahman, Mohammad Kalimur (King Fahd University of Petroleum & Minerals) | Al Majed, Abdulaziz Abdulla (King Fahd University of Petroleum & Minerals) | Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals)
The mechanical properties are determined to measure the sustainability and long-lasting behavior of cement slurry under wellbore conditions. Different measurement methods were adopted in the past to study the mechanical behavior of a cement slurry. The most commonly used methods applied in oil and gas sector are cement crushing and acoustic velocities measurements. Both techniques have some limitations and additional techniques are warranted. Scratch test technique is commonly used for characterization of mechanical properties of metals, coatings and other materials. Advances in scratch testing of materials has resulted in its application to cohesive material such as rocks and cement. Recently, scratch test has been successfully applied for the strength evaluation of oil well cement. In this paper, we present the results of scratch tests carried out on oil well cement using type G cement and the specimens modified using nanoclay as an additive. The compressive strength test results from scratch test was compared to the macro level testing of cement cores loaded in compression up to failure. The dynamic elastic parameters of cement mix, elastic modulus and Poisson's ratio, were also determined using the scratch test. The scratch test based strength measurement technique will serve as a very handy tool for drilling and geomechanics engineers to study the mechanical properties of the cement slurry aged under different wellbore conditions with high level of certainty.
Murtaza, Mobeen (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Majed, Abdulaziz Al (King Fahd University of Petroleum & Minerals) | Chen, Weiqing (King Fahd University of Petroleum & Minerals) | Jamaluddin, Abul (King Fahd University of Petroleum & Minerals)
In cementing operations of deep oil and gas wells, long term integrity of the well is highly dependent on the cement sheath. Obtaining success rate in cementing operations has been subjected to a myriad of challenges, as drilling into deeper, high pressure/high temperature horizons is done. To gain long term integrity of cement sheath, a successful placement of cement slurry plays a pivotal role. So, the design of suitable rheological properties helps characterize the cement pumpability, mixability, and displacement rates for adequate removal of mud. So, the design of cement slurry for HPHT and deviated wells has become a complex task. Recently employing nano-materials in improved oil recovery, designing of drilling fluids as well as hydrocarbon well cementing has been the focus of many studies. The intrinsic characteristics of being smaller in size, while at the same time providing a larger surface area, nanomaterials can prove to be a game-changer for the challenges faced in HPHT cementing. This paper reproduces the outcomes of an investigational study conducted to determine the effect of nanoclay as an additive on rheological properties of Type-G cement slurry under various temperature conditions. Nano-clay with Class G cement in two different concentrations 1% and 2% by weight of cement, mixed and tested under different temperature conditions (37°C, 50°C, 60°C & 80 °C). Additionally, nano-clay based cement mixtures were prepared by substituting cement with 1%, 2% and 3% of nano-clay by weight of cement(BWOC), and admixed with silica flour, along with various chemical admixtures. American Petroleum Institute (API) standard-10B was followed to condition the slurry at predetermined temperature, while the slurry was under atmospheric pressure. This conditioning was followed by the measurement of rheological properties. Results of this investigation demonstrate that incorporation of nano-clay advances the rheology of prepared cement slurry that could aid in mud-displacement and anti-settling as per the requirements.
Basfar, Salem (King Fahd University of Petroleum and Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum and Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum and Minerals) | Stanitzek, Theo (Akzo Nobel Chemicals AG)
Barite sagging is one of the common issues while drilling high pressure-high temperature wells. This will cause variation in the mud weight in both vertical and deviated wells. Barite sagging can cause many problems such as; density variations, well-control problems, stuck pipe, downhole mud losses, and induced wellbore instability.
The objective of this study is to assess the effect of adding a new copolymer to the invert emulsion drilling fluid to prevent the sagging issue. Sag test was conducted under static conditions over a wide range of temperature (200°F to 350°F). Sag test was performed using vertical and decline (45° degree) aging cell. In addition, the effect of adding the new copolymer on the rheological properties and the electrical stability of the invert emulsion drilling fluid was evaluated.
The results obtained showed that adding 1 lbm/bbl of the new copolymer had no effect on drilling fluid density (14.5 ppg). The new copolymer slightly enhanced the electrical stability of the invert emulsion drilling mud. The new copolymer had a minor effect on the plastic viscosity, yield point, and gel strength. Adding 1 lbm/bbl of the copolymer prevent barite sagging at 350°F, where the sag factor was 0.55 before adding copolymer, and 0.503 after adding it. The storage modulus (G’) was increased by 40% after adding 1 lbm/bbl of the new copolymer confirming the sag test results. There was no effect of adding the new copolymer in the filtration loss and filter cake thickness.
The novelty of this work is the development of a new drilling fluid formulation that can be used in drilling HPHT wells without any sag issue. This development will help the drilling engineers to safely drill deep wells and maintain the drilling fluid integrity during the drilling operation. In general, this will reduce the overall cost of the drilling operation by reducing the non-productive time in solving many issues such as well control, loss of circulation, or pipe sticking.
Oil or gas wells which have static reservoir (Fig. 1) pressure greater than 10000 psi and temperature above 300°F are classified as high-pressure high-temperature (HPHT) wells (Smithson T., 2016). Completion of HPHT wells are one of the most challenging in the oil industry. This complexity in HPHT well pushed the researchers to develop a formulation of drilling fluids that can be used to control the formation pressure and provide a well control. Barite as a weighting material was used to increase the drilling fluid density. The main issue of barite is the settling of its particles (Aldea et al. 2001; Meeten 2001; XIAO 2013).
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Muqtadir, Arqam (King Fahd University of Petroleum & Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum & Minerals)
In a quest to reduce the greenhouse gasses, geologic sequestration of carbon dioxide (CO2) in an underground hydrocarbon rock formation or aquifer is one of the most promising alternative to reduce the amount of CO2 release in an open environment. However, long-term storage of CO2 effects the geomechanical and geochemical properties of the host rock. In carbonate aquifers, water dissolves the injected CO2 gas forming carbonic acid which has the tendency to dissolve calcium compounds present in the formation. The dissolution of calcium is particularly worrying since it contributes to the matrix of the rock. Thus, the mechanical properties of the rock are altered, which left unattended could result and in compaction of the formation and surface subsidence.
This paper aims to study the degradation of the petrophysical and mechanical properties of two types of rocks namely limestone and sandstone due to the storage of supercritical CO2 for desired amount of time. Supercritical CO2 has low viscosity but high density and has ability to store in large amount within the same space and with the high pumping efficiency. Two different carbonate rocks and one sandstone rock were exposed to a CO2-brine solution at a pressure of 1200 psi and at 120 °C for durations ranging from 10 to 120 days. The mechanical properties were then examined by both static and dynamic mechanical tests along with the routine core analysis (RCA).
Results showed that long term CO2 storage affected the mechanical, acoustic and petrophysical parameters of rocks examined in this study, viz., Khuff limestone, Berea Sandstone, and ordinary limestone. The duration of solubility time brine-CO2-rock has a considerable impact on the petrophysical and mechanical parameters of the rock samples. Outcomes of this study also shows that the rock mechanical and petrophysical properties significantly affected when CO2 store for the longer period of time. CO2, rock, and brine interaction is dependent on time consequently the rock mechanical and petrophysical parameters changes are also time dependent. The potential candidate found for geological sequestration of CO2 studied is limestone because of its minimal rock properties altered.
Release of CO2 gas in the environment is one of the main concern and reason for the rise in the global warming because CO2 has the tendency to trap heat. Although about half of the greenhouse gasses are absorbed naturally (into deeper seas), the rest stays in the Earth's atmosphere for centuries.
Ahmad, Hafiz Mudaser (King Fahd University of Petroleum & Minerals) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum & Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum & Minerals) | Al-Harthi, Mamdouh A. (King Fahd University of Petroleum & Minerals)
Water-based drilling fluids are utilized to carry out efficient and smooth drilling operations of oil and gas wells. Bentonite is a basic constituent of water-based drilling fluids. It has excellent swelling properties, ability to make gel structure and acts as viscosifier to tailor the rheological properties of drilling fluids. Deep well drilling with bentonite drilling fluids at high temperature and pressure conditions will severely affect the performance of drilling fluid in term of degradation and flocculation due to thermal induce swelling of bentonite. High salts contamination during the drilling process reduces the hydration and dispersion of bentonite and results in flocculation.
The aim of this study was to improve bentonite drilling fluid performance using novel water-soluble polymers and nanoparticles. Nanoparticles significantly improved the filtration properties by reducing the fluid loss into formations and by making a thin filter cake for smooth drilling operations. Novel water-soluble polymers such as acrylamide/2-Acrylamido-2-methylpropane sulfonic acid copolymer and acrylamide/2-Acrylamido-2-methylpropane sulfonic acid/ N-Vinylpyrrolidone terpolymer were used to improve the rheological properties and dispersion of bentonite. Rheological and filtration properties were evaluated using functionalized carbon nanotubes and graphitized nanotubes by varying the temperature from 25°C-85°C. Herschel-Bulkley and Bingham model were used to calculate various parameters such as plastic viscosity and yield stress. It was observed that incorporation of 0.25 wt.% polymers and 0.25 wt.% nanoparticles improved the filtration and rheological properties such as yield stress and steady shear viscosity.
Drilling fluids are widely used to assist in drilling operations for the exploration of natural resources (Anderson et al. 2010). Water-based drilling fluids (WBDF) are a complex mixture of multi-components in which bentonite clay is dispersed homogeneously as a continuous phase (Alderman et al. 1988). Other components typically include barite as a weighting materials, polymer as a viscosifier and a shale inhibiting agents, salts, pH control agents, and nanoparticles as fluid loss material (Boul et al. 2016, Fattah and Lashin 2016, Jain, Mahto, and Mahto 2016, Penner and Lagaly 2001, Zhang et al. 2016). The functions of WBDF in drilling operations are to maintain the column pressure against the formation pressure, to transport the formation cuttings to the surface, to maintain the viscosity during drilling operations, shale inhibition and to prevent the loss of drilling fluid into the reservoir formations (Aftab et al. 2016, Allahvirdizadeh, Kuru, and Parlaktuna 2016, Taha and Lee 2015). In addition to these function, WBDF must be environment-friendly, non-corrosive, cheap and less reactive, and have superior temperature and salt tolerance (Kosynkin et al. 2011). The most important constituent of WBDF is bentonite clay which acts as a viscosifier in drilling operations. Bentonite clay mainly composed of sodium montmorillonite which represents some unique properties such as swelling upon hydration, thixotropy, and cake formation (Shirazi et al. 2011). It also represents cation exchangeability and low permeability when in the wet state (Shakib, Kanani, and Pourafshary 2016). Bentonite dispersions are impermeable in a stable state which makes it a suitable candidate for drilling fluids. Bentonite clay has a layered structure in which octahedral sheets of alumina is sandwiched between two tetrahedral sheets of silica (Abdou, Al-Sabagh, and Dardir 2013, Hamed and Belhadri 2009). The interlayer cations are responsible for holding these sheets together by the electrostatic force of attraction. When bentonite clay hydrated with water, the exfoliation of inter-layer occurs which leads to the adsorption of water on negatively charged surfaces (Au and Leong 2013). The adsorption of water and particle to particle associations leads to the increase in rheological behaviour of bentonite . But the use of bentonite dispersion alone as a potential drilling fluid may cause some serious problems. It makes a thick filter cake on the formations which lead to the potential pipe sticking, formation damage, and lowering the drilling operation productivity (Anyanwu and Mustapha Unubi 2016, Song et al. 2016). To overcome these problems, polymer-clay based drilling fluids with attractive rheological properties are normally used (Luo et al. 2017).
As the increasing demand of gas to support the industrial boom grows in the entire world, the unconventional, in particular, extremely tight gas reservoirs are playing significant role. However, the exploitation of these tight resources is still an economical and technical challenge, which can be dealt with the incisive use of current resources. Effective hydraulic fracturing techniques are the only solutions that make the development of these resources economical. This paper is concerned about the method of fracturing treatment design, economical evaluation, candidate selection, and fracture economic optimization. Finally, the detailed financial analysis of fracture job with net production increase is used to select the best stimulation solution for tight gas reservoirs. Moreover, the paper will serve as a good source of information to gain better understanding of hydraulic fracturing design to maximize the economics of tight gas reservoirs.
Tight gas reservoirs are considered to be unconventional due to the fact that gas cannot be produced from them at economic flow rates unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the reservoir to the wellbore?? [Holditch. 2007]. Nowadays, they have started playing key role in supplying energy to the world. Uneconomical resources today will be economical in future through new advancement in technology especially in simulation and fracturing techniques. Normally, a large hydraulic fracture treatment is required to produce gas economically from unconventional reservoirs. In some naturally- fractured low permeability gas reservoirs, horizontal wells and/or multilateral wells can be used to provide the stimulation required for commerciality. The stimulation method used is a function of reservoir characteristics and economics (Stephen A. Holditch. 2009). From all the stimulation methods, the best and economical method is hydraulic fracturing (R. W. Veatch Jr. 1983.).
From the past investigations, there was no proper attention given into the economics of hydraulic fracturing (G. Hareland. 1994). Several models have been developed and utilized to determine fracture dimension and characteristics. The exact cost of fracture operations and the relation between fracture dimensions, the cost of fracture operations and ultimate returns still need to be investigated thoroughly. Several questions need to be addressed when one considers undertaking a fracture in low permeability gas reservoirs. These include whether it is necessary to conduct this job, is there enough improvement and profits to warrant conducting the operation, the total cost and the expected production period. The above questions can only be solved by correct hydraulic fracture design, its performance and economics. The economics of hydraulic fracture design helps in optimizing the design and deliverability of tight gas reservoirs.
This paper is concerned about the method of treatment design and economical evaluation of hydraulic fracture design in tight gas reservoirs. The fracturing fluid is designed based on the type of well, temperature, pressure and formation characteristics. Then the proppant and treatment size is designed based on economic optimization. Later the financial analysis of treatment cost and revenues make clear that the hydraulic fracture is the most effective stimulation treatment in tight permeability gas reservoirs.