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Search Brine: 4.3.3 Solids
... 10.0 3.7* 0.8 No test 3.7 1.4 1.5 4.9 1.7 0.9 --Notest-- KCI 9.7 7.28* 1.3* No test 8.8 2.6 1.3 12.4 3.3 1.6 --No test-- NaBr 12.5 3.7 0.9 0.5 6.6 1.0 0.2 14.2 1.0 0.2 --No test-- KBr 11.4 3.7* 0.6* No te...7-kg/m3] CaBr2/ZnBr2 brine at temperatures from 200 to 400 F [93 to The obvious advantages of using solids-free heavy brines for 204 C] for 7 and 30 days (Table 6). The corrosion rates were less packer-flui...
...Solids-Free, High-Density Brines for Packer-Fluid Applications A.M. Ezzat, SPE, NL Baroid/NL Industries I...ased muds are not stable suspensions. Laboratory corrosion data and field observations suggest that solids-free, inhibited high-density brines could be ideal packer fluids for deep, hot wells. Expensive was...hover and fishing operations required for recovery of tubing stuck in settled mud solids could be eliminated. Introduction A worldwide review of workover operations indicated extremely Lig...
...ion. The brine should be filtered; 1. From our observations, the 30-day static test is a sufficient solids content less than 100 mg/L could be achieved in the field. period to determine the long-term corros...ctive 5. The oxygen content in CaCI2/CaBr2/ZnBr2 brines is very at low concentrations in minimizing solids-free brine corrosivity. low. At ambient temperature, the following oxygen concentrations were measu...tock brines: 0.1 to 0.2 ppm for 11.6-lbm/gal 3. Field case histories have proved that the inhibited solids-free [1390-kg/m3] CaCI 2; 0.05 to 0.1 ppm for 14.2-lbm/gal [1702-brines have performed exceptionall...
Summary. High-density water- or oil-based muds are not stable suspensions. Laboratory corrosion data and field observations suggest that solids-free, inhibited high-density brines could be ideal packer fluids for deep, hot wells. Expensive washover and fishing operations required for recovery of tubing stuck in settled mud solid could be eliminated. Introduction A worldwide review of workover operations indicated extremely high costs associated with recovery of tubing stuck in settled mud solids. High-density water- or oil-based muds are not stable suspensions when left static in a well for a long time. High temperatures and/or contamination of these muds with the produced gas and oil destroys the initial suspension properties and allows mud solids and weighting materials to settle on top of the packer and around the tubing. Expensive washover and fishing operations are then performed. During the washover, more costly complications, such as twist-off or stuck washover pipes, casing leaks, blowouts, and formation damage, could develop. When such complications occur, many wells have to be plugged and abandoned. Most of these problems could be eliminated by using solids-free packer fluids. Single-salt brines and blends of high-density brines have been tested to determine their corrosive nature. An inorganic corrosion inhibitor was developed and field tested. In the last few years, many deep, high-temperature, high-pressure wells in the Gulf of Mexico have been successfully completed with inhibited high-density brines, which were also left as packer fluids. Some of these wells were worked over, tubing and packers were retrieved easily, and no significant corrosion was observed. Packer-Fluid Functions Packer fluids are placed in the casing/tubing annulus to provide a hydrostatic head necessary to control the well in case of packer failure or leaks, and to reduce the pressure differential between the inside of the tubing and the annulus, the outside of the casing and the annulus, and the perforated interval below the packer and the annulus. Packer fluids should protect tubing and casing metal surfaces from corrosion and enhance retrievability of tubing and packers. Important Fluid Characteristics Packer fluids must be chemically and mechanically stable under downhole conditions; i.e., there must be no settling of suspended solids and no chemical precipitates if mixed with produced fluids or gases, Also, the fluid components must not degrade with time or temperature. Fluids must not deteriorate packer elastomers. Fluids must remain pumpable during the life of the well; i.e., no high gelation or solidification may develop over time. Fluids must not cause corrosion (inside casing or outside tubing). The fluids must not damage the producing formation because they may contact these producing zones during completion or workover operations. Water-based drilling-mud organic additives degrade upon prolonged exposure to high temperatures and sometimes generate corrosive gases, such as CO2 and H2S. Bacterial activity could also break down organic materials and/or produce corrosive elements. Lignosulfonate solutions can react electrochemically at metal surfaces to form sulfides, even at moderate temperatures. Properly formulated oil-based muds are nonconductive and should not cause corrosion. In case of packer failure or leaks, however, produced oil or gas dissolves in oil mud and destroys the suspension properties, allowing the weighting material (barite) to settle on top of the packer and to cause stuck packer and tubing. Laboratory Testing Procedures Laboratory corrosion testing procedures (Appendices A and B) and equipment were developed. Data obtained explained the corrosive nature of these brines under static conditions, simulating packer-fluid applications. Uninhibited Single-Salt Brines and High-Density-Brine Blends Corrosion tests were performed to determine corrosion rates for seven commercial available, single-salt, saturated brines (NaCl, KCl, KBr, NaBr, CaCl2, CaBr2, and ZnBr2) without inhibitors. Test periods were 1 to 180 days at temperatures of 250, 300, 350, and 400 degrees F [121, 149, 177, and 204 degrees C]. Initial tests were conducted on No. 1010 carbon steel coupons. An average rate for duplicate samples was calculated for each test period (Table 1). The highest corrosion rates for all brines were with the 1-day test and much lower rates were observed in longer test periods. As the temperature increased, the 1-day test corrosion rates increased significantly. For example, CaCl2 at 250 degrees F [121 degrees C) showed 5.3 mils/yr [0.135 mm/a] and at 400 degrees F [204 degrees C] showed 54.7 mils/yr [1.39 mm/a]. ZnBr2/CaBr2 at 250 degrees F [121 degrees C] showed 10.2 mils/yr [0.259 mm/a] and at 350 degrees F [177 degrees C] showed 140 mils/yr [3.56 mm/a]. These relatively high rates decreased tremendously, however, with longer exposure times of 7 and 30 days. This phenomenon indicated that the active corroding elements in the brine were being consumed and/or that the reaction produced a protective coating on the metal surface. That is, the worst corrosion reaction is during the initial contact of brines with steel, and the longer brines are left static in a well, the less corrosive they become. CaCl2/CaBr2/ZnBr2 blends with densities of 15.5, 16, 16.5, 17.5, and 18 lbm/gal [1857, 1917, 1977, 2097, and 2157 kg/m3) were tested at 250, 300, 350, and 400 degrees F [121, 149, 177, and 204 degrees C). As with the single-salt brines, the 1 day test corrosion rates were relatively higher than the 7-, 30-, and 90-day tests. These brine blends demonstrated much higher rates than the single-salt brines, especially at and above 300 degrees F [149 degrees C] (Table 2). In addition to the temperature effect on the corrosion rates, higher blend densities produced higher corrosion rates, which are attributed to the higher acidic ZnBr2 content required at the higher blend densities. Summer blends (higher crystallization temperatures) in the same density range formulated with smaller amounts of the acidic ZnBr2, showed lower corrosion rates than the winter blends (lower crystallization temperatures). In the tables and figures, LCD is last crystal to dissolve method. JPT P. 491^
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- North America > United States > Louisiana > Downdip Tuscaloosa-Woodbine Trend Basin > False River Field > Tuscaloosa Formation (0.99)
- Asia > Japan > Katagai Field (0.99)
...SPE 65000 High-Density Invert-Emulsion System with Very Low Solids Content to Drill ERD and HPHT Wells 11 Table n. 4 - Tests with Cesium Formate Formulation: g g Sy...300 200 100 6 3 G 0 /G 10 AV PV YP ES agent agent Synt. Paraffin A Ilmenite WA02 96 52 37 21 4 3 3/5 48 44 8 275 Synt. Paraffin B Ilmenite WA02 74 40 28 16 3.5 3 3/4 37 34 6 270 Measurements at 120 ...
...SPE 65000 High-Density Invert-Emulsion System with Very Low Solids Content to Drill ERD and HPHT Wells 13 Table n. 9 - Typical Properties of Two Different Weighting ...ighting 600 300 200 100 6 3 G 0 G 10 AV PV YP ES agent agent 2137/3 WA02 Ilmenite 96 52 37 21 4 3 3 5 48 44 8 275 2137/3 WA02 Barite 112 59 41 23 4 4 4 5 56 53 6 1000 Measurements at 120 F AHR 16h a...
...SPE 65000 High-Density Invert-Emulsion System with Very Low Solids Content to Drill ERD and HPHT Wells Luigi F. Nicora, SPE, Pierangelo Pirovano, SPE, Lamberti SpA, ...s the laboratory development of a new Low density (ECD) and high surge and swab pressures. To build Solids Oil Based Mud System (OBMS) with a very high mud with such high densities, the concentration of wei...y 35% v/v. Together as solid free oil based mud with very low viscosity at densities with the drill solids and the organophilic clay, the total amount up to 1.52 SG, especially suggested for Extended Reach ...
Abstract The paper describes the laboratory development of a new Low Solids Oil Based Mud System (OBMS) with a very high specific gravity (2.04 SG; 17 ppg) for high-temperature and high-pressure applications. The system can also be applicable as solid free oil based mud with very low viscosity at densities up to 1.52 SG, especially suggested for Extended Reach Drilling Wells. The main goals of the new system are:Optimization of fluid rheology by reduction of the solids contents in the mud. Temperature and system stability at 170°C. The objectives have been pursued in the following ways:by using a very heavy brine as the internal phase; by decreasing the oil / brine ratio; by using a weighting agent with higher density than barite. In this way, the amount of weighting solids which needs to be added can be drastically reduced to even below 22% v/v for a 2.04 SG mud, compared to 35% v/v as in traditional oil based muds. Also the PV values have been reduced from typically round 60 cP to even below 25 cP. The addition of new components to the system has lead to the need of a new emulsifier package, which has been optimized with the development of a primary emulsifier and a wetting agent based on innovative chemistries. Introduction Saga Petroleum discovered in 1997 a new high temperature high pressure (HTHP) field offshore Norway, the Kristin field. A total of three exploration wells have been drilled on the Kristin structure. The temperature in the reservoir is 175°C and the pressure 930 bar, requiring the use of drilling fluids with high temperature stability and high density (2.04 kg/l). The drilling of these wells has identified the need of developing a drilling fluid system with better rheological properties and improved temperature stability. Conventional oil based mud has been used in exploration drilling. In vertical wells the mud has behaved satisfactorily but, when drilling inclined hole, a lot of mud related problems occurred such as barite settling, high equivalent circulating density (ECD) and high surge and swab pressures. To build mud with such high densities, the concentration of weight material needs to be very high. In the wells drilled in the Kristin field the amount of barite was approximately 35% v/v. Together with the drill solids and the organophilic clay, the total amount of solids in the mud was reaching almost 40% v/v. This very high solids content makes it very difficult to achieve a good rheological profile of the mud. To develop the Kristin field for production several extended reach drilling (ERD) wells need to be drilled. Drilling of these wells cannot be done with this type of mud because of the high ECD, caused by the high rheology of the mud, which might fracture the formation and cause lost circulation problems. The development of a new oil based mud system, which gives far lower ECDs, is therefore essential to be able to drill the necessary wells. Invert emulsion fluids consist of a salt water solution dispersed into a continuous hydrophobic phase. This emulsion is stabilized by emulsifiers. The salt water phase has traditionally been a CaCl2-brine, often with lime added for alkalinity. The oil / water ratio is traditionally in the range of 65/45 - 85/15. The concentration of solids in the mud will often dictate the oil / water ratio. In solids laden muds the oil ratio must be high, to keep the solids oil wet and dispersed.
- Europe > Norway > Norwegian Sea (0.65)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Garn Formation (0.99)
- (9 more...)
...19 21 6 13 13 3 1 5 3 3 3 8 4 2 3 RPM 31 15 18 5 11 10 3 1 4 2 2 3 6 3 1 Gel 0 28 18 21 6 11 10 4 1 4 3 3 3 6 5 2 Gel 10 40 31 40 10 17 15 6 3 9 3 4 3 10 8 5 PV 85 62 64 40 67 77 19 20 31 17 30 7 26 13 17 ...81 42 48 17 50 42 1 -1 13 1 8 25 19 4 2 Fluid Loss 6 10 10 8.6 6.8 6.4 NC NC 8.5 NC 8 NC 7.4 NC NC solids influences the brine lubricity and the presence of drilled / low gravity ...solids significantly reduces lubricity. Laboratory tests showed that the lubricity coefficient of the K-Fo...
...imitations. K-Formate brine was utilized up to maximum density of 12.5 ppg to reduce the impacts of solids in the mud. For the first time, maximum mud weight of 17.8 ppg was achieved operationally using mic...
...ty Stabilize polymers at higher temperatures Inhibit bacterial growth High tolerance to solids contamination Non-damaging to the reservoir Low corrosivity Good shale inhibition with ...
Abstract The Jurassic reservoirs of deep wells in Kuwait have traditionally been drilled with OBM. Barite is utilized as the weighting material in the OBM resulting damages to these reservoirs, thereby reducing the productivity to a significant extent. The higher oil to water ratio (95/5) of OBM limits the possibilities of identifying the micro fractures in reservoirs due to the limited conductive medium in OBM. Potassium formate WBM, with Manganese Tetraoxide as weighting material was successfully applied in HPHT wells overcoming these limitations. K-Formate brine was utilized up to maximum density of 12.5 ppg to reduce the impacts of solids in the mud. For the first time, maximum mud weight of 17.8 ppg was achieved operationally using micromax (Mn3O4) in this WBM. Also, for the first time in Kuwait, this kind of fluid was used to drill the section with the inclinations above 60° in deep wells. As a result of using K-Formate WBM in the reservoir sections, production increased significantly when compared to the wells drilled with OBM and barite. Wells were simulated easily without the presence of barite. Water based conductive medium gave better quality of image logs. Unlike other WBM's, K-formate WBM was stored for long periods, over a year in the mud plants without any damage to the mud properties. Recycling reduced the overall fluid costs in the subsequent wells drilled with K-formate WBM. Environmental damage due to the OBM spills and cuttings were completely avoided; K-formate WBM is highly bio-degradable under atmospheric conditions and is environmentally friendly. The experience and success gained with its use on the initial wells led to the planned usage of this WBM on all deep exploratory wells. This paper explains the experiences gained and the achievements made over the years with K-formate WBM used for drilling the deep HPHT wells.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Evaluating Formation Damage Risks in a Glauconitic Sandstone Reservoir: A Case History from the Offshore North West Shelf of Australia
Hatcher, G.B. (CSIRO Division of Petroleum Resources) | Chen, H. (University of New South Wales) | Rahman, S.S. (University of New South Wales) | Hogg, P.F. (West Australian Petroleum Pty. Ltd.)
...I 9 8 ; 7 ' """ v IP 6% 'V' ..,. I J'" r" ' !' '" WS pH 76% 5%,-, 4% 4% ...3% o 2% 2% 1% -...1!L 6 t 5 4 o 100 200 300 400 500 600 700 Cummulative Flow (ml) b Nacl...
...uents were filtered to on exposure to freshwater, The sum of evidence suggests capture any produced solids for petrographic characterisation. that swelling ofglauconitic smectite is the underlying cause cf ...
... at 0.22 11m to exclude any pro du ed m.productIon after a corrosion batch treatment. A pressure solids from the chemical analyses and to capture the bUIldup survey confirmed that the problem was formati...on re solIds for petrographic characterisation. ated and. showed a reduction ofpermeability to 12 md and an ...
G.B. Hatcher, Australian Petroleum Co-operative Research Centre (APCRC), CSIRO Division of Petroleum Resources, H. Chen and S.S. Rahman, SPE, APCRC, Centre for Petroleum Engineering, University of New South Wales, P.F. Hogg, West Australian Petroleum Pty. Ltd. Abstract When exploiting hydrocarbon reserves in lithologically and petrophysically complex glauconitic sandstones, potentially damaging fluid/rock and fluid/fluid interactions must be thoroughly investigated. This paper reports on the first phase of a comprehensive, multi-disciplinary study of such interactions conducted on samples from the Saladin field, located on the offshore North West Shelf of Australia. Core floods indicate that the formation is not susceptible to significant damage during the flow of simple brines. However, chemical analysis of core flood effluents after periods of stasis indicate continuing interactions between introduced fluids and fluids resident in the large volume of microporosity. Awareness of such delayed interactions will be important in restored state core analysis and when evaluating the damage potential of more complex fluid systems. The reservoir was found to suffer extreme damage on exposure to freshwater. The sum of evidence suggests that swelling of glauconitic smectite is the underlying cause of the damage, with pore throat plugging by mobilised glauconitic smectite and non-expandable glauconitic clays the probable damage mechanism. Saturation with calcium chloride solutions prevented water shock damage. Introduction The risk of significant impairment of a reservoir's capacity to produce hydrocarbons must be assessed when planning any field operation which may impinge on the reservoir. The basis for this assessment is an understanding of reservoir behaviour when contacted by the fluids used in these operations. This allows the potential damage mechanisms to be identified and the underlying causes to be determined. Appropriate preventative and/or remedial procedures can then be designed. Formation damage mechanisms and causes in many reservoir types have been extensively studied and significant advances made in understanding how and why damage occurs. Refs. 1 through 3 provide good overviews of the subject. However, complex lithologies, such as those containing unusually high clay concentrations or having dual porosity systems have received less attention. Such reservoirs may still have the potential to produce unpleasant surprises during field operations. Glauconitic sandstones are one such complex lithology, having both a high clay content and a dual porosity system. They contain abundant, iron-rich clay particles aggregated into grains whose microporosity can represent a significant proportion of the total porosity. Fluids flowing through the intergranular pore system may largely bypass this micropore volume, but remain in communication with its fluid content across the porous glaucony grain surfaces (Fig. 1). Potentially damaging fluid/rock and fluid/fluid interactions may take place as the two fluid volumes equilibrate during the static periods which are a normal part of oilfield operations. Conventional, continuous flow core floods may fail to identify such risks. This paper reports the results of a series of modified aqueous core floods conducted to investigate these phenomena. During the floods, flow was periodically interrupted to allow equilibration between the fluids in the macropore and micro-pore systems. Core flood effluents were characterised by pH measurement and chemical analysis. Effluents were filtered to capture any produced solids for petrographic characterisation The core plugs themselves were subjected to petrographic examination before and after exposure to the introduced fluids. Formation Damage Mechanisms and Causes It is not the purpose of this paper to present a review of formation damage research. However certain key concepts need to be outlined and some terms defmed. Since the specific damage issues investigated involved clays and their interactions with introduced fluids, the following discussion is limited to concepts pertinent to clay-related formation damage. P. 461
- Overview (0.74)
- Research Report (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Saladin Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Barrow Basin > TL/4 > Saladin Field > Saladin 11 Pilot Well (0.99)
- Oceania > Australia > Western Australia > Carnarvon Basin (0.99)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Laboratory Development and Field Application of a Novel Water-Based Drill-In Fluid for Geopressured Horizontal Wells
Dobson, J.W. (TBC-Brinadd) | Harrison, J.C. (TBC-Brinadd) | Hale, A.H. (Shell E&P Technology Co.) | Lau, H.C. (Shell E&P Technology Co.) | Bernardi, L.A. (Shell E&P Technology Co.) | Kielty, J.M. (Shell E&P Technology Co.) | Albrecht, M.S. (Shell E&P Technology Co.) | Bruner, S.D. (Shell Offshore Inc.)
...35 2 2 26 26 26 10 second gel, lbm/100 ft 2 3 4 1 1 3 3 3 10 minute gel, lbm/100 ft 2 4 5 1 1 4 3 3 CLASS H 24 hr HTHP Fluid Loss, mL (unless otherwise noted) MgCl 2 0 lbm/bbl 0.5 lbm/bbl 1 lbm/b...
...leting geopressured horizontal wells. This fluid has a with a heavy brine, minimal soluble bridging solids concentration, unique combination of properties which make it especially suitable and low-viscosity..., reducing the viscosity, and allowing utilizing a water-based system. Well data are found in Table solids to settle. Viscosity stability for the fumed silica 1. mixture was achieved through the addition o...
... polymers to provide a reserve of alkalinity and to deliver added stability to and primary bridging solids. the polymers. Filtration Control. Extensive screening was conducted of fluid Antifoaming/Defoamin... Fluid Requirements for Field of calcium bromide or zinc bromide. 1 Application Primary Bridging Solids. Three fine grinds of calcium carbonate Ten major issues were evaluated in an extensive laboratory ...on of seal over a specific formation pore opening. This provides nominal this new high-density, low-solids drill-in fluid: filter-cake deposition with as little as 10 lbm/bbl of the primary h igh differe...
Summary Research has identified a novel water-based drill-in fluid for drilling and completing geopressured horizontal wells. This fluid has a unique combination of properties which make it especially suitable for geopressured applications. They include the use of calcium and/or zinc bromide as a base brine, minimal concentration of calcium carbonate as bridging material, low plastic viscosity, tight fluid loss control, good filter-cake properties, and excellent return permeability. This drill-in fluid has been used successfully to drill a 1,200-ft production interval, 4.75-in. diameter wellbore in the Gulf of Mexico with a system weight of 13.2 lbm/gal, bottomhole temperature of 185°F and a 1,400 to 1,700 psi overbalance. The system functioned very well in both the drilling and the completion operations. Fluid rheology was easily maintainable and the hole conditions were excellent without torque or drag problems. Initial production data suggest that the well is producing at expected rates with low drawdown pressure. Introduction In 1995 we have witnessed widespread use of horizontal wells by Shell in the Gulf of Mexico. At present, the drilling and completion of horizontal wells requiring a fluid density of 12.5 lbm/gal or less have become routine practice in the Gulf of Mexico. As horizontal well technology requiring low-density systems has gained acceptance within the Shell groups, there is a need to develop nondamaging drill-in fluids for geopressured horizontal wells, requiring densities ranging from 12.5 to 16 lbm/gal. Due to the demand for higher-density drill-in fluids, an effort was undertaken at Shell's technology laboratory in Houston in concert with service companies to develop fluids that met both drilling and completion requirements. More than half a dozen service companies were contacted to submit drill-in fluids for various target reservoirs. These fluids were then evaluated to determine if they met Shell's established criteria for both drilling and completion. The drill-in fluid that met these requirements was then recommended to the operational engineers based on both technical and economic reasons. A horizontal sidetrack well with 1,200 ft of 4.75-in. diameter open hole was planned for drilling using a 13.2 lbm/gal nondamaging drill-in fluid in the Gulf of Mexico during October of 1995. Previous experience indicated the 13.2 lbm/gal system would generate an overbalance of 2,400 psi over the formation pressure, thereby presenting a challenge for a slide drilling operation utilizing a water-based system. Well data are found in Table 1. In this article, the laboratory development and field application of a 13.2 lbm/gal water-based drill-in fluid is summarized. Background of Dense Brine Fluid Systems Ideally, a high-density drilling/completion system should be compounded with a heavy brine, minimal soluble bridging solids concentration, and low-viscosity polymer additives. Density adjustments to the system should be made with brine rather than particulates to maintain an ultrathin filter cake and low viscosity profile, but with high low shear rate viscosities. The most commercially available dense brines are calcium chloride, calcium bromide, and zinc bromide. However, use of these brines as a base for drilling fluids has been limited. Generally, water-soluble polymers used for viscosity and filtration control do not perform well in calcium bromide or zinc bromide brines. Therefore, the basic components necessary for successfully compounding a high-density drilling fluid, 12.5 to 16 lbm/gal, exhibiting high, low shear rate viscosities, shear-thinning capabilities, and low filtrates were not readily available for calcium or zinc bromide brine blends. Fluid Design. Four major areas were targeted for calcium bromide and zinc bromide based drilling fluid evaluation and development:primary viscosifier; viscosity stabilization; fluid loss control; fluid enhancers/stabilizers. Primary Viscosifier. Fumed silica or fumed silicon dioxide (SiO2) is a 0.2- to 0.3-?m branched-chain aggregate with enormous surface area and chain-forming tendencies. A network of these aggregates will provide an elevated viscosity in static conditions, but will thin easily with shear in a dynamic environment. During the combustion formation of fumed silica in a hydrogen/oxygen flame, hydroxyl groups become attached to some of the silicon atoms on the particle surface. This makes the silicon dioxide surface hydrophilic and capable of hydrogen bonding with suitable molecules. The rheological properties generated by this unique viscosifier in a fluid system are a result of proper dispersion of the aggregates in a liquid media, thereby generating a network drawn into contact by hydrogen bonding between the surface hydroxyl groups. This network increases the viscosity of the system and produces a shear-thinning fluid with a high low shear rate viscosity. Viscosity Stabilizer. The viscosity established by the hydroxyl group surface connections of the SiO 2 is very fragile. Excessive shear forces can break the interaggregate hydrogen bonds, causing the apparent viscosity for the system to decline. Likewise, long-term static aged samples have a tendency to sag, increasing the distance between the aggregates, reducing the viscosity, and allowing solids to settle. Viscosity stability for the fumed silica mixture was achieved through the addition of a select biopolymer in the fluid system. Fumed silica, when combined with a biopolymer which has been sheared into a calcium or zinc bromide brine, possibly becomes intertwined within the opened structure of the biopolymer, providing a more stable low shear rate viscosity in static conditions at elevated temperatures (Table 2). Additionally, water in the brine may provide sites which could become susceptible to a surface hydrogen bond from the biopolymer and/or the SiO2.
Laboratory Development and Field Application of a Novel Water-Based Drill-In Fluid for Geopressured Horizontal Wells
Dobson, J.W. (TBC-Brinadd) | Harrison, J.C. (TBC-Brinadd) | Hale, A.H. (Shell E&P Technology Company) | Lau, H.C. (Shell E&P Technology Company) | Bernardi, L.A. (Shell E&P Technology Company) | Kielty, J.M. (Shell E&P Technology Company) | Albrecht, M.S. (Shell E&P Technology Company) | Bruner, S.D. (Shell Offshore Inc.)
...m/100 ft2 28 35 2 2 26 26 26 10 sec gel, Ibm/l 00 ftz 3 4 1 1 3 3 3 10 min gel, lbm/100 ftz 4 5 1 1 4 3 3 24 hr. HTHP Fluid Loss, ml (unless otherwise noted) CLASS H MaCl, Q!Qm&Q! 9.5 lbm/bbl 1 lbm/b 2...
...ology was easily maintainable and the hole compounded with a heavy brine, minimal soluble bridging solids conditions were excellent without torque or drag problems. concentration, and low viscosity polyme...
...g fluid evaluation and development.z bromide or zinc bromides Primary viscosifier Primary Bridghg Solids. Three fine grinds of calcium Viscosity stabilization carbonate below 74 microns are available t...izers provides nominal filter cake deposition with as little as 10 lbm/bbl of the primary bridging solids. Should losses occur Primary Viscosifier. Fumed silica, or fumed silicon dioxide during drilling o...icles may be compounded (SiO,) is a 0.2 to 0.3 micron branched chain aggregate with with the finer solids as necessary. enormous surface area and chain forming tendencies. A network of these aggregates wil...
Abstract Research has identified a novel water-based drill-in fluid for drilling and completing geopressured horizontal wells. This fluid has a unique combination of properties which make it especially suitable for geopressured applications. They include the use of calcium and/or zinc bromide as a base brine, minimal concentration of calcium carbonate as bridging material, low plastic viscosity, tight fluid loss control, good filter cake properties, and excellent return permeability. This drill-in fluid has been used successfully to drill a 1,200 foot production interval, 4.75 inch diameter wellbore in the Gulf of Mexico with a system weight of 13.2 lbm/gal, bottom hole temperature of 185 F., and a 1400 to 1700 psi overbalance. The system functioned very well in both the drilling and completion operations. Fluid rheology was easily maintainable and the hole conditions were excellent without torque or drag problems. Initial production data suggests that the well is producing at expected rates with low drawdown pressure. Introduction The year 1995 has witnessed widespread use of horizontal wells by Shell Offshore, Inc. (SOI) and Shell Western E&P, Inc. (SWEPI). At present, the drilling and completion of horizontal wells requiring a fluid density of 12.5 lbm/gal or less, has become routine practice in the Gulf of Mexico. As horizontal well technology requiring low-density systems has gained acceptance within the Shell groups, there is a need to develop non-damaging drill-in fluids for geopressured horizontal wells, requiring densities ranging from 12.5 lbm/gal to 16 lbm/gal. Due to the demand for higher density drill-in fluids, an effort was undertaken at Shell E&P Technology Company (SEPTC) in concert with service companies to develop fluids that met both drilling and completion requirements. More than half a dozen service companies were contacted to submit drill-in fluids for various target reservoirs. These fluids were then evaluated to determine if they met SEPTC established criteria for both drilling and completion. The drill-in fluid that met these requirements was then recommended to the operational engineers based on both technical and economic reasons. A horizontal sidetrack well with 1200 feet of 4.75 inch diameter open hole was planned for drilling using a 13.2 lbm/gal nondamaging drill-in fluid in the Gulf of Mexico during October of 1995. Previous experience indicated the 13.2 lbm/gal system would generate an overbalance of 2400 psi over the formation pressure, thereby presenting a challenge for a slide drilling operation utilizing a water-based system. Well data is found in Table 1. In this report, the laboratory development and field application of a 13.2 lbm/gal water-based drill-in fluid is summarized. BACKGROUND OF DENSE BRINE FLUID SYSTEMS Ideally, a high-density drilling/completion system should be compounded with a heavy brine, minimal soluble bridging solids concentration, and low viscosity polymer additives. Density adjustments to the system should be made with brine rather than particulates to maintain an ultra-thin filter cake and low viscosity profile, but with high low shear rate viscosities. The most commercially available dense brines are calcium chloride, calcium bromide, and zinc bromide. However, utilization of these brines as a base for drilling fluids has been limited. Generally, water-soluble polymers used for viscosity and filtration control do not perform well in calcium bromide or zinc bromide brines. Therefore, the basic components necessary for successfully compounding a high density drilling fluid, 12.5 lbm/gal to 16 lbm/gal, exhibiting high, low shear rate viscosities, shear-thinning capabilities, and low filtrates were not readily available for calcium or zinc bromide brine blends. P. 121
- Geology > Mineral > Halide (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.31)
... amounts of heavy oil. 10 10 9 9 K05 K10 8 8 K20 0h 7 K30 7 1h K40 6 4h K50 6 24h 5 5 4 4 3 3 2 2 1 1 0 0 0.1 1.0 10.0 100.0 1,000.0 10,000.0 0.1 1.0 10.0 100.0 1,000.0 10,000.0 Relaxation ...t be a major concern July 2007, Volume 46, No. 7 39 Absolute Amplitude Clay Content (wt% of total solids) Relative Amplitude (%) Relative Amplitude (%)...
...s to formulate an algorithm for differentiating between clay bound in calculating water, oil and/or solids content. This water and bulk heavy oil in NMR logs. The ability to make this paper presents a preli... predictive algorithm for clay content differentiation would enable one to determine oil, water and solids determination, and this knowledge will allow one to more content in samples containing heavy oil an...
...were indeed due to changes in the minimum amount may be larger for fluids in porous media. However, solids/oil/water system and not due to differing degrees of proton the results presented here for 5 wt% br...0, 30, 40 and considered to be acceptable in tests with fluids in porous media. In 50 wt% (of total solids) of each clay compound. The samples with tests where the fluid in the sample was less than the mini...mum detection IRC were labelled I05 (for 5 wt% of total solids of IRC), I10, I20, limit, the obtained NMR spectra resembled that of noise I30, I40 and I50. The sa...
Abstract Low-field nuclear magnetic resonance (NMR), whether implemented in a logging tool, bench top analyser or on-line sensor, cannot detect the complete response of heavy oil or bitumen. Both heavy oil and bitumen relax quickly so the majority of these oils' spectra are detected at relaxation times less than 10 ms at room temperature. In clay-free sands, the contribution of heavy oil to the NMR spectrum is distinct and, as a result, it is still possible to calculate oil and water content based on NMR spectra. However, in sands that contain clays, the relaxation times of clay bound water are in the same range as bitumen. Experimental results from mixtures containing illite, kaolinite, montmorillonite, sand and mild brine show that clay bound water has a characteristic response. These NMR ‘signatures’ were used to develop predictive nomographs of clay content. A second set of experiments involved adding heavy oil to mixtures containing clay, sand and brine. The changes in NMR spectra after exposure to heavy oil were compared to the spectra obtained before oil was added. The differences identified in this work allowed for improvements in calculating water, oil and/or solids content. This paper presents a preliminary predictive algorithm for clay content determination, and this knowledge will allow one to more accurately separate the contributions of heavy oil and clay bound water from a sample despite the fact that these will overlap in an NMR spectrum. Improved characterization of oil sands is a possible consequence of this work. Introduction Nuclear magnetic resonance (NMR) logging tools have been used in numerous applications within the petroleum industry for enhancing recovery. In addition to porosity and permeability determination, NMR has been used to characterize heavy oil and bitumen, composition determination of oil/water emulsions and determination of heavy oil viscosity. NMR logging tools obtain information regarding fluids in porous media by using magnetic fields to polarize the protons in the fluid and by monitoring the time it takes the protons to return to equilibrium. This time is commonly termed the transverse relaxation time (T2). Protons in bulk fluids such as water have a T2 value of approximately two seconds, but the T2 values for heavy oils and bitumen are much faster (e.g. between 1 and 10 ms). The reason for this is that the protons in heavy oil and bitumen are restricted due to the viscous environment. In fact, present NMR logging tools are incapable of detecting the complete spectrum from heavy oil and bitumen formations because of the high viscosities of these samples. As a result, attempts to characterize heavy oil and bitumen are problematic. Restriction of proton movement can also occur because the fluid has sorbed onto clays or organic matter in the sample. Consequently, clay bound water has a low T2 value (e.g. less than 10 ms) compared to water residing in the larger pores of the samples, which has a T2 value that is approximately 100 ms. The fact that the amplitude peaks for heavy oil and clay bound water appear at similar T2 values makes it difficult to differentiate between the oil and water signals from a sample that contains both fluids.
- North America > United States (0.46)
- North America > Canada > Alberta (0.30)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
Tailoring Treated Brines for Reuse Scenarios
Wenzlick, Madison (Research and Innovation Center, National Energy Technology Laboratory) | Siefert, Nicholas (Research and Innovation Center, National Energy Technology Laboratory) | Hakala, Alexandra (Research and Innovation Center, National Energy Technology Laboratory)
... (a) (b) Capital Costs Recurring Costs $5 $6 y 1.0855x y 1.2358x R² 0.0821 $5 $4 R² 0.4463 $4 $...3 $2 $2 $1 $1 $- $- 0 1 2 3 4 5 0 1 2 3 4 5 Theoretical Minimum Work of Separation, Theoretical M...
...stablishment in treating produced water. The treatment process removes oil and grease and suspended solids, reduces the divalent ion concentrations, and concentrates the brine to a near-saturation state. Th...
...available in this manuscript. Steps in the modeled treatment process include: oil-water separation, solids removal, removal of divalent ions and hardness, and dewatering to produce clean ten-pound brine for...
Abstract Produced water from oil and gas wells constitutes a significant portion of the costs and operational considerations of a well. In this work, we design a centralized water treatment facility capable of managing produced water from oil and gas wells in Texas and Louisiana through conversion into salable products: ten-pound brine and pure water. We create two models, each using commercially available technology with varying levels of establishment in treating produced water. The treatment process removes oil and grease and suspended solids, reduces the divalent ion concentrations, and concentrates the brine to a near-saturation state. The baseline model incorporates chemical precipitation for divalent ion removal to meet reuse specifications, whereas the advanced case considers use of nanofiltration membranes (NF) to remove divalent ions. In both cases, we model mechanical vapor recompression for brine concentration. The baseline process is shown to be cost-effective for low-salinity and low-hardness brines. In the case of high salinity or high hardness, the chemical precipitation step is cost-prohibitive. We find that NF membranes are a promising alternative to chemical precipitation as a means of separating monovalent and divalent ions. However, due to the limited about of published data on NF membrane on high salinity produced brines, further research and development may be required before demonstration at the commercial-scale on high-salinity and highhardness brines. In this work, we conduct a sensitivity analysis in order to determine those parameters that allow for cost-effective produced brine management through brine reuse. Introduction Nearly all methods for extracting oil and gas resources produce a high salinity brine byproduct. Oil and gas wells can produce volumes of water equal to or greater than the volume of hydrocarbons, and this ratio tends to increase over time [1]. Therefore, managing produced water will continue to be a significant component of oil and gas operations. The two main current methods for disposal of this produced brine arere-use for enhanced oil recovery (EOR) and deep-well injection into salt water disposal wells (SDWs). As seen in Table 1, of all water produced by oil and gas in 2012, 45% was managed by injection for enhanced oil recovery, 38% injected for disposal, and 7% was injected at offsite commercial facilities for disposal [1]. Out of the top ten states with the highest volumes of wastewater from oil and gas production, six send roughly 48% or more of the water to SDWs [Table 2]. Disposal of water also composes a significant portion of a well's cost, as management of flowback water ranges from 5% to 19% of a well's capital cost, and management of produced water ranges from 7% to 52% of a well's lease operating expenses (LOE) depending on location [2]. In addition, the use of SDWs has also been linked to environmental risks including increased seismic activity and possible contamination of drinking water aquifers [3, 4]. As such, regulatory agencies are increasingly investigating alternatives to disposal by injection [5].
- Geology > Geological Subdiscipline (0.87)
- Geology > Structural Geology > Tectonics (0.48)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (2 more...)
An Assessment of an Uncomplicated Drill-in Fluid and Its Application to a Wide Range of Global Completions and Their Recent Successes
Luyster, M. R. (TBC-Brinadd, LLC) | Tresco, K.. (TBC-Brinadd, LLC) | Dobson, J.. (TBC-Brinadd, LLC) | Ravitz, R.. (M-I SWACO, Schlumberger Company) | Allogo, C. M. (M-I SWACO, Schlumberger Company) | Lim, K. Sooi (M-I SWACO, Schlumberger Company)
...is non-biopolymer reservoir drill-in fluid (NBRDF) system demonstrates relatively high tolerance to solids and reservoir fluids as well as ease of hydration when mixing on the rig. Routinely the hydraulics ...osity, at a lower density range that was not achievable before. The initial concepts of buoyancy of solids and the exclusion of a biopolymer as incorporated in relatively high-density brines formed the basi...
...ories demonstrating the flexibility of this system with respect to utilization as a workover fluid, solids-free (SF) fluid (e.g., no bridging ...solids), and coring fluid, as well as the use of additives to reduce specified risks and breakers to remov...a drilling and completion system whereby no biopolymer was needed and the concentration of bridging solids could be reduced. Therefore, upward density adjustments to the system could be accomplished using t...
... such that there is an unbalanced upward force on the bottom of a submerged object. Thus objects or solids are supported by the difference in pressure. Combined with Archimedes' principle (Appendix), it fol...lows that buoyant force acting on solids is equal to the weight of the water displaced. Thus, buoyancy is an upward force exerted by a fluid...
Abstract An established non-biopolymer reservoir drill-in (NBRDF) system which was developed in very early 2000 for high-density drilling applications – approximately 11.5 to 17.5 lbm/gal – was recently improved to provide functionality in low-density drilling applications – as low as 9.5 lbm/gal. Global implementation of this system over the last several years has demonstrated not only flexibility with respect to drilling and completing in diverse reservoirs but also its application as a workover system. In addition, this system was recently optimized by incorporating compatible chemistry to mitigate atypical damage mechanisms. As such, several case histories are presented to demonstrate the system's broad functionality with respect to density, completion type, reservoir, and logistics, as well as its capacity to reduce near-wellbore/formation damage. This non-biopolymer reservoir drill-in fluid (NBRDF) system demonstrates relatively high tolerance to solids and reservoir fluids as well as ease of hydration when mixing on the rig. Routinely the hydraulics are consistent and predictable even as no biopolymer is utilized. This system is compatible with the incorporation of an inhibitor, specifically, a scale inhibitor to mitigate calcium carbonate and minor sulfate scaling. This system recently incorporated a sized calcinated magnesium compound (MC2) and sized magnesium complex (MC3) which promotes viscosity, specifically low-shear rate viscosity, at a lower density range that was not achievable before. The initial concepts of buoyancy of solids and the exclusion of a biopolymer as incorporated in relatively high-density brines formed the basis for the development of this system. These concepts are discussed first to provide a background for the preceding recent improvements and case histories. Each case history presents a different set of objectives whereby pre-planning assessments were implemented to address and mitigate perceived risks as related to the fluids. The methods employed include assessments for rheology, scaling, hydraulics, displacements, compatibility and formation damage. The drilling and completion results for these projects exhibit a wide range of applications as well as flexibility with respect to required density, completion hardware and reservoir type. The procedures utilized for each project are evaluated with respect to specific drilling and completion targets and include the iterations/modifications required; subsequently the field learnings are also discussed.
- Europe (1.00)
- North America > United States > California (0.46)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
- Europe > Russia > Northwestern Federal District > Timan-Pechora Basin > Toboi Field (0.94)
...72659-MS 9 Table 5--Compatibility test results of HP/HT drill-in fluid sample with simulated drill solids. Drill-In Fluid Sample No. 5 No. 6 14.2-lbm/gal CaBr 2 (bbl) 0.934 0.934 Defoamer (lbm) 0.2 ...3 rev/min (lbm/100 ft 2 ) 7 3 3 3 10 sec (lbm/100 ft 2 ) 4 3 2 2 10 min (lbm/100 ft 2 ) 4 3 3 3 PV (cp) 46 40 45 43 YP (lbm/100 ft 2 ) 36 24 28 22 HP/HT fluid loss at 350 F, ceramic disk (...
...t 2 ) 2 2 3 3 3 3 4 4 10 sec (lbm/100 ft 2 ) 2 2 3 3 3 3 3 4 10 min (lbm/100 ft 2 ) 2 3 4 3 3 3 4 4 PV (cp) 26 33 36 33 41 37 50 49 YP (lbm/100 ft 2 ) 12 13 21 15 23 22 35 34 HP/HT fluid l...
...10 mL after 30 minutes at 350 F. This is in stark contrast to biopolymercontaining samples in which solids settling and dark coloration were observed after static aging at 300 F for only 16 hours. This pape...
Abstract Novel polymers have been designed and developed as thermally stable dual function viscosifiers and fluid-loss additives for high density brine-based drill-in fluids. These polymers allow for the formulation of clay- and biopolymer-free drill-in fluids that are stable at temperatures up to 450°F. This is a significant improvement compared to conventional drill-in fluids, which use biopolymers and have temperature limits of 300°F. Clay-free drill-in fluid samples were prepared in 14.2-lbm/gal CaBr2 brine and conditioned by hot rolling at 150°F for 16 hours, followed by static aging at 400°F for 72 hours. The samples prepared with the novel polymers show no color change or stratification after static aging. There was minimal change upon comparison of the rheological properties of the nonaged and aged samples. The samples provided excellent fluid-loss control even after aging, with a measured high-pressure/high-temperature (HP/HT) fluid loss less than 10 mL after 30 minutes at 350°F. This is in stark contrast to biopolymer-containing samples in which solids settling and dark coloration were observed after static aging at 300°F for only 16 hours. This paper presents full testing results of the new HP/HT drill-in fluids, including formulation, fluid properties, and formation damage assessment.
- Asia (0.93)
- North America > United States > Louisiana (0.30)
- 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 > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)