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.
Aminopolycarboxylic acids (APCAs) have been used in a variety of applications ranging from textiles to pharmaceuticals. They are also commonly used in the oil-and-gas industry for scale removal, standalone stimulation, and iron control. Because of the common-place usage of APCAs, it is important to understand the corrosion that can result from the use of APCAs and the methods that can be applied to reduce corrosion damage resulting from their use. The objective of this work is to evaluate the corrosion rate of APCAs on low-carbon steel at high temperatures and to determine the mechanism of corrosion.
At high temperatures, conventional acids such as hydrochloric acid (HCl) are extremely corrosive, lack penetration, and have sludging tendencies. Several organic acids such as formic acid and citric acid were proposed to overcome these shortcomings. However, these organic acids have displayed problems with solubility and compatibility. Chelating agents show good dissolving power, low corrosion, low sludging tendencies, and excellent iron control, and have been successfully used to replace HCl in certain applications. Furthermore, some of them are easily biodegradable and environmentally friendly.
To study the mechanism of corrosion at high temperature, N-80 coupons were exposed to APCA solutions for 12 hours in the absence of corrosion inhibitors (CIs). At 350°F, the corrosion rate of ethylenediamine tetraacetic acid (EDTA), L-glutamic diacetic acid (GLDA), hydroxyethyl ethylene triacetic acid (HEDTA), and methylglycine diacetic acid (MGDA) had corrosion rates of 1.07, 0.754, 0.974, and 0.76 lbm/ft2, respectively. When the temperature was lowered to 300°F, the corrosion rates of each chelating agent decreased to 0.858, 0.724, 0.803, and 0.642 lbm/ft2 for EDTA, GLDA, HEDTA, and MGDA, respectively. The addition of a 1-vol% sulfur-containing CI to HEDTA and MGDA tests at 350°F caused a significant decrease in corrosion rates to 0.0102 and 0.00561 lbm/ft2, respectively. Furthermore, the mechanism of the APCA corrosion of low-carbon steel was found to be a combination of chelant-enhanced dissolution and cathodic reduction of the APCA. Chelant-enhanced dissolution involves the dissolution of the oxide layer on the surface of the metal, and is accelerated at high temperatures by reductive dissolution. Cathodic reduction of carboxylic-acid groups of APCAs was determined to be responsible for the corrosion of the bare metal layer.
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.
Wellbores drilled through low-pressure formations encountered offshore or in depleted formations, require use of light-weight cement slurries (less than 13 pounds per gallon (ppg)). These densities in cements can be achieved through foaming, increasing the water content, or using silica-based microspheres. Water-extended cements have a threshold down to weights of approximately 13 ppg and to achieve densities lower than this require the use of foaming and/or silica based microspheres. Each of these methods has limitations that can severely impact hydraulic properties of cement. The foamed cements have the potential to become unstable at high pressures, while silica-based microspheres have chemical instability in the high alkalinity environment of wellbore.
This chemical instability of silica-based microspheres used in cements, creates a hydrophilic gel that is expansive and creates fractures within cement matrix as it expands. This is more formally referred to as alkali-silica reactivity (ASR). Prevention of ASR involves the application of additives to the cement that act as a sink for the alkalinity during hydration for long-term prevention of the ASR. Lithium nitrate is one of these prevention methods that is theorized to allow for other beneficial reactions.
This study investigates the effects of a highly alkaline cement pore-water on the chemical stability of microspheres. Microstructural characterization involves identification of reaction products in alkali- reacted glass beads within 28 days hydrated wellbore cement at wellbore temperatures, as well as the impact of lithium nitrate as a prevention method. The scanning electron microscopy of polished and fractured surfaces reveal two different reaction processes, with the ASR clearly absent in the slurry containing lithium nitrate. The micro-mechanical properties of these changes were also tested using microindentation tool. Lastly, porosity values were tested using helium gas Porosimetry. Lithium nitrate shows an effect on mechanical properties but not on porosity values as compared to cements solely containing microspheres.
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.
A fouling-resistant gas stripping technology was tested for removing dissolved gas species from dirty water streams such as produced water. The CoStrip™ degasifier uses a countercurrent stream of microbubbles to absorb gas species from the water stream into a stripping gas. The microbubbles act as carriers, removing dissolved gases such as hydrogen sulfide (H2S), carbon dioxide (CO2), and BTEX (Benzene, Toluene, Ethylbenzene, and Xylene) compounds. The technology is able to treat water with a high level of suspended solids and oils, which would otherwise clog a conventional packed tower or sieve tray gas stripper. A pilot test was conducted on heavy oil (API-10 to 12) produced water in California, which demonstrated a variety of benefits. The benefits of a degasifier installed upfront of a produced water treatment train include: dissolved gas removal, safe use of open-top equipment downstream due to H2S reduction, lower downstream chemical consumption and sludge generation due to dissolved gas removal, corrosion mitigation, and improved downstream membrane longevity.
Al-Muntasheri, Ghaithan A. (Saudi Aramco) | Li, Leiming (Aramco Services Company: Aramco Research Center-Houston) | Liang, Feng (Aramco Services Company: Aramco Research Center-Houston) | Gomaa, Ahmed M. (Saudi Aramco)
Fracturing fluids are used for transport and placement of proppants in hydraulic-fracturing operations. In the case of conventional reservoirs, sufficient fluid viscosity is needed to transport proppant. An ideal fracturing fluid should possess enough viscosity to suspend and carry proppant. After the proppant placement, the fluid viscosity should drop to facilitate an efficient and quick fracture cleanup. This ensures adequate fracture conductivity. Most of the fracturing fluids used in these operations are dependent on crosslinking reactions between polymers and crosslinkers. Breaker technologies such as oxidizers, enzymes, fluoride compounds, oxides, vitamins, and decrosslinking agents are used to break the crosslinked polymer-based gels. These materials are added as components of the initial fracturing-fluids recipe. This paper will focus on the available breaker technologies used for degrading and cleaning up fracturing fluids used for conventional reservoirs. Each breaker has its own operating mechanism and window of application in terms of temperature and pH. The design and selection of a breaker package will first require an understanding of how the fracturing fluid forms. The current review reveals the crosslinking mechanisms of various fracturing fluids. These include the crosslinking of biopolymers with borates, the crosslinking of synthetic and biopolymers with metals, and the crosslinking of phosphate esters with metals. In the acidizing of carbonate reservoirs, the use of viscous fluids is needed to allow diversion of acid to lower-permeability paths. Moreover, the high viscosity retards the reaction between the acid and the rock, and this ensures deep penetration of the stimulation fluid. In this application, the viscosity develops as a response to the change in pH. Hydrocarbon fluids are used for hydraulically fracturing water-sensitive formations. Each of the aforementioned fracturing fluids has its own suitable breaker technology. For borate-crosslinked biopolymer gels, breakers such as oxidative and enzyme breakers can be used to reduce fluid viscosity by degrading polymer chains. An alternative approach to reduce viscosity of this type of fluid is the use of acids that lower the pH and decrosslink the fluid. A third route to reduce this fluid viscosity is by use of chelating agents and complexing agents. Lowering fluid viscosity alone may not sufficiently guarantee adequate proppant-pack and formation cleanup. It has been proved that low-viscosity fluids may still contain high-molecular-weight (MW) polymers that could severely damage formation and proppant pack. These high-MW polymers should be further broken into low-MW fragments with oxidizers or enzymes to achieve better production numbers. When metals are used to crosslink biopolymers and synthetic polymers, breakers such as oxidative breakers can still be effective. Acid fracturing fluids use fluoride-based breakers that can complex with the zirconium (Zr) and hence decrosslink the gel. When fracturing high-temperature wells, breakers can prematurely degrade the gel viscosity. This leads to less proppant placement and possibly screens out the proppant. As a result, the propped fracture becomes shorter and the well productivity will be less. To avoid this, breakers are encapsulated with materials that act as barriers between the breaker and fluid. The dissolution of the encapsulating material gives additional time for the gel to place the proppant. This paper reviews more than 100 papers and patents to summarize the experience and available knowledge in the area of using breakers for cleaning up fracturing fluids.
The in-line scavenging of hydrogen sulfide is the preferred method for minimizing the corrosion and operational risks in oil production (