Hydraulic fracturing solutions use a gelling agent known as guar gum. Guar beans are grown in a number of countries, including the United States. The endosperm of the guar bean is ground to produce an off-white powder known as guar gum (guar). Guar acts as a gelling agent, which can be crosslinked by adding additives, such as barium, to tailor the molecular weight of the guar solution. Crosslinking the guar increases the viscosity of the solution, which results in a gelatinous material having sufficient surface tension to transport a proppant (e.g., sand), which is used to maintain cracks and fissures in an open condition in the geological layers to allow oil and gas to flow to the collection well.
Chendrika, Lusiana (Schlumberger) | Purwitaningtyas, I. M. (Schlumberger) | Fuad, Muhammad (Schlumberger) | Etuhoko, Michael (Husky-CNOOC Madura Limited) | Nurdin, Syaiful (Husky-CNOOC Madura Limited) | Jihong, Lian (Husky-CNOOC Madura Limited) | Rusli, Barne (Husky-CNOOC Madura Limited)
Manganese tetraoxide (Mn3O4) drilling fluid weighting material was first applied in two high-pressure/high-temperature (HP/HT) Madura Sea, Indonesia wells, BD-A and BD-B. Mn3O4 is less damaging to the environment and formation than other weighting agents. In the BD wells, coiled tubing (CT) will perform Mn3O4 mudcake removal by spotting an acid solution. The main challenges come from the formation characteristics: temperature up to 305°F, pressure of 8100 psi, 5,000 ppm H2S, and 5.5% CO2.
Slow-reacting acid was preferred to prevent creating a corrosive environment. The reaction of acetic acid, formic acid, and a chelating agent with Mn3O4 at 305°F was studied. A corrosion test was performed to see the effect of the acid and 5,000 ppm H2S on CT string and completion tubing metal. Viscosimeter and densitometer testing was done on 155 ppb Mn3O4 mud that was mixed at laboratory scale to represent actual drilling mud in the well. Filter cake was made using an HP/HT filter press and 10-micron alloxite disc to represent formation permeability.
Using the mix of acetic acid and chelating agent solution, 100% solubility of filter cake was achieved after 6 hours reaction time, giving enough time for CT to spot the acid in the entire 1,000-ft openhole interval and provide a uniform filter cake removal. With additional organic acid inhibitor and H2S inhibitor, the corrosion rate on CT and completion tubing metal after 16 hours test was found acceptable without pitting observed.
This method has been proven effective to remove Mn3O4 filter cake with significant pressure drawdown reduction, hence increasing well productivities. The utilization of CT improves cost efficiency by accurately placing a right amount of acid solution across the openhole section.
This stimulation fluid system is the first application in the world and was proven to be effective to remove Mn3O4 based filter cake and protect CT and tubing metal against H2S and CO2 in an HP/HT environment.
Liu, Yifei (China University of Petroleum) | Dai, Caili (China University of Petroleum) | You, Qing (China University of Geosciences) | Zou, Chenwei (China University of Petroleum) | Gao, Mingwei (China University of Petroleum) | Zhao, Mingwei (China University of Petroleum)
This article presents a novel organic-inorganic crosslinked polymer gel, which uses resin-silicate as the organic-inorganic crosslinker, to extend the temperature limitations of currently used polymer gels for water control in mature oilfields. The gelation performances, including gelation time, gel strength and thermal stability, were studied, and the optimum composition was selected by study of gelation performances. Results show that with increase of the concentrations of components, gelation time became shorter and gel strength was improved. And the gel system was stable after 90 days at 140 °C. The optimum composition of the gel system was selected as: 4~7 wt% resin and 2~5 wt% silicate with 0.1~0.3 wt% polymer. Meanwhile, differential scanning calorimetry (DSC) measurement was used to investigate the maximum tolerated temperature of the gel. The results showed that the chemical bonds of the gel began to break at 156 °C, which indicated that the gel can resist high temperature up to 156 °C. At last, environmental scanning electron microscopy (ESEM) microstructure and fourier transform infrared spectroscopy (FTIR) spectrum of the gel were studied to analyze the gelation process and investigate the mechanism for temperature resistance. The three-dimensional network microstructure of the resin-silicate crosslinked polymer gel was more compact and more uniform than the gel prepared without silicate. The formation of silicon-oxygen bonds (Si-O) increased the crosslinking density and temperature tolerance of the gel system.
A new laboratory work procedure has been developed to evaluate and test the performance and effectiveness of chemical-sealant-based loss circulation materials (CS-LCMs), which are often used in cases of severe-to-total losses. These unconventional testing methods should be useful tools to evaluate the integrity of loss circulation material (LCM) products under downhole conditions in terms of differential pressure buildup and how quickly such LCMs can arrest lost circulation.
Evaluation and testing of LCMs in the laboratory before field application are crucial. Conventionally, the plugging capacity of particulate LCMs is tested against various-sized slotted discs using a permeability plugging apparatus (PPA), and integrity is tested in terms of sealing capacity and fluid loss value. Testing the performance of CS-LCMs required another means that included plugging extra-large vugs and building a significant differential pressure that could sustain the drilling fluid column. Pumpability of CS-LCMs and mechanical strength performance over time were evaluated using a high-pressure/high-temperature (HP/HT) consistometer, ultrasonic cement analyzer (UCA), and modified PPA following this fit-for-purpose procedure.
Extensive laboratory testing revealed that the new testing method was highly compatible with almost all types of chemical-based LCMs, including resin, gunk squeeze, and thixotropic slurries. The effectiveness and performance of several commercially available CS-LCMs were measured using different vug sizes (i.e., up to tens of millimeters). Thickening time of LCMs were observed pumpable [i.e., <70 Bearden units of consistency (Bc)], even after hours of conditioning at bottomhole circulating temperatures (BHCTs). As per API routine practice, tested slurry is deemed unpumpable if Bc exceeds 70. However, the thickening time of gunk squeeze LCMs were observed to be significantly high in a short interval of time once aqueous and nonaqueous streams mixed together. Gunk-based LCMs build high differential pressures and compressive strength over the same periods of curing time at bottomhole static temperature (BHST) and pressure compared to thixotropic-based LCMs.
Appropriate laboratory testing and evaluation of chemical-based LCMs under downhole conditions are highly recommended before field trail/application. This new testing/evaluation method should help minimize operational risk and nonproductive time (NPT) at the rig site.
Nedwed, Tim (ExxonMobil Upstream Research Company) | Kulkarni, Kaustubh (ExxonMobil Upstream Research Company) | Jain, Rachna (ExxonMobil Upstream Research Company) | Mitchell, Doug (ExxonMobil Upstream Research Company) | Meeks, Bill (ExxonMobil Development Company) | Allen, Daryl P. (Materia Inc.) | Edgecombe, Brian (Materia Inc.) | Christopher, J. Cruce (Materia Inc.)
Industry maintains well control through proper well design and appropriate controls and barriers. This has made loss of well control a very low probability event. Currently the final barrier to maintain control is a valve system (blowout preventer or BOP) located on top of wells capable of sealing around or shearing through obstructions that might be in the well (e.g. drilling pipe and casing) to isolate the well. Although the risk is low when proper drilling practices and design are employed, there are still concerns about well control especially for operations in sensitive environments. Adding an additional barrier could alleviate these concerns.
One scenario for well control loss is if the BOP fails to seal allowing drilling fluids and reservoir fluids to flow. We are currently evaluating a concept to respond to such an event and seal leaking BOPs by injecting a liquid monomer and a catalyst below a BOP leak point to form a polymer-plug seal.
Mixtures of dicyclopentadiene (DCPD) and other monomers mixed with a ruthenium-based catalyst cause a rapid polymerization reaction that forms a stable solid. These reactions can occur under extreme temperatures and pressures and withstand significant contamination from other fluids and solids.
Lab studies have shown that DCPD-based polymer plugs can withstand axial stress of 15,000 psi without significant deformation even at temperatures of 200°C and with 20% drilling fluid contamination. For well control, one option is to preposition monomer mixes and catalyst into pressurized cannisters located at or near subsea BOPs while drilling high-complexity wells. Connecting the pressurized cannisters to appropriate ports on the BOP will allow rapid transfer. During a well-control event, actuating valves would rapidly force the monomer mixes and catalyst from the cannisters into the BOP to initiate polymerization. Polymerization reactions can be as short as a few seconds depending on the monomer mix and catalyst. The resulting solid polymer plug will block the leak path to potentially seal the well.
This paper describes the concept details and summarizes the current status of research.
Effective zonal isolation is critical in lost circulation, cement repair and conformance applications. To be successful it is often necessary to not only block pathways but also ensure a tight seal. Gaps or weak points between the blocking material and boundary layers can result in poor zonal isolation leading to gas migration, gas entrapment, and/or excessive water production among other issues. The mechanisms vary but cement, polymers, and sodium silicate can all lose volume upon setting and aging. The degree of contraction being impacted by downhole events such as fluid loss, influx of gas, water or conditions such as high temperatures
In the case of Portland cement, several different methods have been developed to ensure dimensional stability. A long time approach has been the addition of aluminum powder to the cement slurry for the in-situ generation of hydrogen gas. This paper looks at how elemental aluminum as well as zinc can be adapted for use in a sodium silicate-based system. In developing a new technology, several questions are posed at the onset. At the top of this list are the health, safety, and environmental implications of the individual components and final product. Fine powders are inherently dusty and carry an explosive risk if not properly handled. Development of a safe form of the metal powders became the first priority. The direction taken was to slurry the metals using suitable base oils and mutual solvents. As part of the slurry development, the shape and size of the aluminum and zinc were studied for resistance to settling, rheological stability, and reaction kinetics.
Stable metal slurries could be formed in base oils such as polyalphaolefins or mineral oils when combined with other additives. The selected base oils were shown to function in a similar manner as encapsulators and be used control the rate of the gas generation reaction. Mutual solvents such as triacetin provided further functionality by being able to initiate a polymerization reaction of alkali silicate. Short-term properties such as set time, density, rheology, and compressive strength were made adjustable by concentration and the use of filler/bridging material such as walnut hulls, glass powder, calcium carbonate, barite, or fly ash.
While sodium silicates can be set by either an internal or external setting agent, the industry preference is for a one component system. Presented in this paper will be the development of a one component system that safely incorporates the in-situ generation of hydrogen to yield a chemically durable, mechanically strong expanded silicate-based plug.
Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals ) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals ) | Shawabkeh, Reyad (King Fahd University of Petroleum & Minerals )
Removal of water-based filter cake that formed either during drilling or hydraulic fracture operations is a difficult task. Chelating agents were introduced in the oil industry to solve the common problems associated with the conventional acids (hydrochloric acid, an organic acid, or a mixture of these acids), such as rapid and uncontrolled reaction rate and corrosion to well tubulars, especially in horizontal and deep wells.
The objectives of this study are to (1) assess the reaction of starch with different chelating agents (GLDA, EDTA, DTPA) at different conditions of pH and temperature, (2) evaluate the compatibility of chelating agents with HTA enzyme (α-amylase enzymes), (3) assess the reaction of enzyme with starch and xanthan gum, and (4) design the best scenario for calcium carbonate filter cake removal.
The obtained results showed that EDTA (20 Wt%, pH 7, and 12), DTPA (20 Wt%, pH 7, and 12), and GLDA (20 wt%, pH = 4, 7, and 12) were not able to break the starch after hot rolling for different time period (12 hrs) at 200°F. These chelating agents were incompatible with α-amylase enzyme (HTA enzyme), which was able to completely break the starch in 6 hrs at 200°F. The best scenario to remove the calcium carbonate filter cake is to soak the filter cake with use α-amylase enzyme for 6 hrs and after that soak the filter cake with GLDA (20 Wt%, pH 4) for 16 hrs.
Ideal filter cake (low permeable, thin and fast formed) should be built on the wall of the hole during the drilling operations to save the integrity of the drilling fluid and to prevent the formation damage. In gravel pack operation, a polymer layer of the filter cake should be formed on the face of the fracture to minimize the pressure loss and hence save the energy to extend the fracture. To maximize the well productivity, the filter cake should be effectively removed after the drilling or the gravel pack operations.
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.
ABSTRACTThis paper describes the thermal and/or hydrolytic stability behavior of solutions of carboxylic acids commonly used in refinery feed prep units and characterizes their daughter molecules. Crude oils are often treated with carboxylic acids to help accomplish some of the goals of refining feed prep units such as pH adjustment, amine removal, and metals removal. These acids, like the crude oil, are subjected to the extreme temperatures of the crude furnace when they pass the desalter dissolved in the crude oil or as unresolved water carryover. Often, the thermal decomposition values for a pure acid are used to give an idea of the level of corrosion risk to the unit. But, this assumes that no change occurs when the acid is dissolved in an aqueous matrix and ignores any stabilizing or destabilizing effect that may have. This work thermally stressed aqueous solutions of carboxylic acids and analyzed the resulting solution and headspace. The paper discusses the expected corrosion impact on distillation overheads and brine rundown systems.INTRODUCTIONCarboxylic acids often are used in conjunction with emulsion breakers and other chemical adjuncts in an effective desalter management program. Whether their use is to enhance the aqueous extraction of amines or metals, or to enhance emulsion resolution through a charge neutralization mechanism, their efficacy is monitored and controlled using a simple indicator like pH. However, selection of an appropriate acid program should not be viewed so simply. It is often taken for granted that the literature degradation data for a neat sample of acid is indicative of its behavior in an aqueous solution. As would be the case when fed as a formulated adjunct or when dissolved in desalter effluent brine.One of the proposed benefits of one acid over another is its solubility or sometimes its octanol/water partition coefficient. Increased oil solubility is supposed to benefit metal or amine extraction due to increased contact time in the crude. While increased water solubility is supposed to benefit the crude unit by reducing the corrosion risk and limiting product contamination sources, though sometimes at the expense of the waste water treatment plant. Although the partitioning of carboxylic acids at room temperature and pressures in model systems like octanol/water is measurable and differentiable, not much has been published on the partitioning behavior of materials at crude unit conditions. The differences in solvency/polarity between crude oil and 1-octanol are not insignificant, in fact, they are quite different as evidenced by the Hansen solubility parameters in Table 1. Hansen solubility parameters are an enhancement of the Hildebrand solubility parameter. Hansen parameters break the Hildebrand parameter (termed the “total” parameter) down into three discrete kinds of intermolecuclar force: dispersion (δD), polarity (δP), and hydrogen-bonding (δH). As with other solubility parameter systems, “like-dissolves-like” is the guiding principle. That is, that materials with similar solubility parameters tend to interact strongly and thus dissolve or partition together. Note how the dispersion parameters are similar but the polarity and hydrogen-bonding parameters are very different between bitumen and 1-octanol. Further, other surrogates for model hydrocarbon matrices like naphtha, toluene, or heptane are quite different from 1-octanol in the same regards.
Underbalanced drilling technology is widely used to minimize formation damage in the reservoir section and enhance productivity. It involves drilling with a fluid whose hydrostatic pressure is lower than that of the formation being drilled. As a consequence of this lower hydrostatic there is a continuous flow of hydrocarbons to surface which is handled by separation equipment and exported thru pipelines where they exist or burned at the flare if no transportation infrastructure is located near rig-site.
The injection of nitrogen into drill-pipe to lighten the hydrostatic pressure of the drilling fluid introduces significant challenges with regards to corrosion mitigation planning. A very well developed corrosion mitigation plan often exists for single phase drilling fluid but the introduction of a gaseous phase leads to changes that need to be incorporated to prevent against excessive corrosion.
Problems and complications due to corrosion issues were hindering an underbalance drilling operation's progress. This paper examines how, optimizing the corrosion control techniques leads to improved drilling performance in subsequent bit runs. The willingness by the operator to tweak and improve the chemical concentrations and learn and apply those lessons learned immediately in the field pays immediate dividends.