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Collaborating Authors
Well Drilling
Abstract Historically, shale instability is a challenging issue when drilling reactive formations using water-based muds (WBM). Shale instability leads to shale sloughing, stuck pipe, and shale disintegration causing an increase in fines that affects the rate of penetration. To characterize shale instability, laboratory tests including Linear Swell Meter (LSM), shale-erosion and slake-durability are conducted in industry. These laboratory tests, under different flow conditions, provide shale-fluid interaction parameters which are indicative of shale instability. The composition of WBM is designed to optimize these interaction parameters, so that when used in the field the fluid helps achieve efficient drilling. This paper demonstrates modeling of shale-fluid interaction parameters obtained from the LSM test. In the standard LSM test, a laterally confined cylindrical shale sample is exposed to WBM at a specific temperature and its axial swelling is measured with time. The swelling reaches a plateau which is characterized by a shale-fluid interaction parameter called % final swelling volume (A). A typical LSM test runs for around 48–72 hours and many tests may be needed to optimize fluid composition. In this work, a method/model is developed to predict final swelling volume (A) as a function of the Cation exchange capacity (CEC) of the shale and salt concentration in the fluid (prominent factors affecting shale swelling). An empirical model in the form of A = f(CEC)*f(salt) which describes the explicit dependence on the influencing variables is developed and validated for 16 different shale samples at various salt concentrations. This model would significantly reduce LSM laboratory trials saving time and money. It could also enable rig personnel to obtain quick measure of shale characteristics so that WBM composition could be adjusted immediately to avoid shale instability issues.
- Asia (0.69)
- North America > United States (0.47)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics (1.00)
Abstract Cementing in front Salt Zones requires an appropriate cement slurry design to assure minimum dissolution of the formation by the cement slurry and also minimum deleterious impact on the properties of the cement. The influence of halite on the cement slurry properties is already well discussed in the literature, but there’s no much information regarding the influence of other salts like taquidrite, carnalite, which are much more soluble than halite and are found in Brazil Offshore Fields. The first stage of the work consisted in evaluating the influence of different levels and types of salt on the hydration process and its effects on the behavior of the main physical properties. It was produced fourteen cement pastes, five of them containing NaCl at the contents of 5, 10, 15, 20 and 36% by weight of water and eight containing KCl at contents of 1, 3, 5, 7, 10, 15, 20 and 34% by weight of water. It was also prepared a cement slurry with no salt added to be used as reference. The dissolution rate of the different salts core formation in these cement slurries was determined. The influence on the cement slurry properties, such as free fluid, thickening time, compressive strength and rheological parameters due to halite, carnalite and taquidrite incorporation were also determined. This paper presents the studies conducted to design cement slurries for cementing well through salt layers (halite, carnalite and taquihydryte) located in the Aguilhadas Field in Northeast, Brazil. Based on the results, about 500 m of salt were cemented with a semi-saturated cement slurry which provided an excellent quality of the cementing, proved by acoustic logs. Salt cores of halite, carnalite and taquihydryte were used to determine the dissolution rate of salt into the cement slurry. X-Ray tomography was used to visualize and to quantify the salt dissolution in the dynamic tests. The shear bond strength between halite core and hardened cement slurry with 15% NaCl was determined showing good results.
- South America > Brazil > Sergipe (0.34)
- North America > United States > Texas (0.28)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- South America > Brazil > Alagoas > South Atlantic Ocean > South Atlantic Ocean > Sergipe-Alagoas Basin (0.99)
- South America > Brazil > Alagoas > Sergipe > South Atlantic Ocean > Sergipe-Alagoas Basin (0.99)
Abstract Salt formations are common trap zones for prolific reservoirs. Recent discoveries in the Brazilian coast include light oil carbonate reservoirs below massive salt zones. Well construction challenges in such environments include salt creeping, leaching and proper zonal isolation. This article presents a comprehensive integrated methodology for cementing design which accounts for the following hydraulic aspects: Adequate fluid substitution design supported by numerical simulation considering two phase flow in eccentric annuli and lubrication theory Downhole pressures in the operational window considering free fall effects for deepwater environments Open hole volume prediction based on salt leaching phenomena due to the circulation of unsaturated fluids. Flow rate fluctuation as a result of free fall is considered Increase in salt concentration due to conduction effects after placement and its impact on slurry properties. The methodology is exemplified by two typical scenarios for offshore salt cementing in the Brazilian pre-salt cluster. Slurry design, slurry placement schedules and borehole stability considerations are addressed.
- South America > Brazil (1.00)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.48)
- Geology > Mineral > Halide > Halite (0.35)
- Well Drilling > Drilling Operations (1.00)
- Production and Well Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.94)
- (4 more...)
Abstract Water for field operations, usually obtained from available sources close to location, often contains high concentrations of bacteria. In order to ensure that bacteria that might cause formation damage, corrosion, pore plugging, or souring is not introduced into the wellbore, bactericide is often added to source waters. However, when used to dilute brines to lower salt concentrations, the addition of bactericide is based on the resulting salinity of the brine. Laboratory studies were conducted with various brines and densities to determine when the use of a bactericide is necessary to ensure that bacteria-free brine is introduced into the wellbore. Various brine samples were contaminated with field water containing bacteria and the viability of the bacteria was observed periodically for 48 hours. Results indicated that the viability of bacteria was dependent on the nature and type of brine (NaCl, CaCl2, NaBr, CaBr2, KCl, and ZnBr2), the concentration of salt in the test brine, and exposure time of the microorganism to the brine. A minimum exposure time was required to effectively kill bacteria, and this requirement will be discussed in relation to operational parameters and fluid inhibition issues. The mechanism of microbiological vitality of high osmotic conditions will also be discussed.