In this drilling context, an accurate estimation of the downhole pressure is mandatory to avoid drilling problems such as kicks, lost circulation, and wellbore instability. When considering kick prevention and control, understanding of the mixture behavior (drilling fluid and formation gas) is essential to improve the estimation of the downhole pressure, which would support efficient, safe, and economic drilling operations. The widespread application of synthetic-based drilling fluids in the Brazilian presalt polygon is justified by the technical performance offered by this kind of drilling fluid, such as reduced drilling time compared with water-based drilling fluids, increased lubricity in directional and horizontal wells, and shale-swelling inhibition. In addition, this is an environmentally friendly alternative to oil-based drilling fluids. However, those fluids are more sensitive to pressure and temperature variations than water-based drilling fluids. To obtain a better understanding of the behavior of one specific kind of synthetic-based drilling fluid, the olefin experimental research was conducted and the results and findings are presented in this technical article. The work involved pressure/volume/temperature (PVT) measurements for olefin/methane mixtures to investigate the effect of pressure, temperature, and mixture composition on thermodynamic properties such as density, formation volume factor (FVF), gas-solubility ratio, and saturation pressure. Those properties are important for knowledge of the mixture volumetric behavior at downhole conditions, especially when gas enters the wellbore. The experiments were conducted at isothermal conditions, and a gas-enrichment experimental procedure was applied.
Wellbore stability in shale is often hampered by the detrimental effect of existing weak bedding planes on shear failure of the rock surrounding the borehole. This paper presents results from an analytical solution to the wellbore-stress problem that incorporates rock failure along weak bedding planes. The solution is used for the case study of a highly inclined well section in a laminated layer of troublesome shale with a strike-slip faulting regime above the target formation in Latin America. Findings indicate improvement in the estimated margin for the wellbore-breakout limit of drilling-fluid density, and, more prominently, the safest drilling direction by accounting for the presence of weak bedding planes in the related wellbore-stability analysis.
Yang, Xiangtong (PetroChina) | Qiu, Kaibin (Schlumberger) | Zhang, Yang (PetroChina) | Huang, Yongjie (Schlumberger) | Fan, Wentong (PetroChina) | Pan, Yuanwei (Schlumberger) | Xu, Guowei (PetroChina) | Xian, ChengGang (Schlumberger)
Keshen is a high-pressure/high-temperature (HP/HT) tight-sandstone gas reservoir with reservoir pressure greater than 110 MPa and temperature more than 175°C. The sandstone is hard, with unconfined compressive strength (UCS) greater than 100 MPa. Given the HP/HT nature and natural-fracture systems in the reservoir, with aid of stimulation, many wells produced at a high rate, with the mean value exceeding 500 000 m3/d. In the last few years, many production wells in this reservoir experienced severe sanding issues that contradicted the conventional understanding that sanding would not occur in such hard rock. The sanding wells exhibited large fluctuations of production rate and wellhead pressure, erosion of chokes and nozzles, and eventually major or even complete loss of production. A solution to address the sanding issues was urgently needed because they had caused a major decline in production and resulted in significant economic loss.
Because of the unconventional nature of the sanding issues, the typical sanding-prediction methods dependent on evaluating rock failure were not adequate to reveal the underlying sanding mechanism and develop a viable operational solution. To this end, a new work flow was formulated and applied to this study. The work flow started with detailed data mining on the large amount of drilling, completion, stimulation, and production data of more than 51 wells from this reservoir to investigate possible relationships of drilling practices, completion options, and production schedules to the occurrence and severity of sanding issues. The analysis revealed that downhole flow velocity and production drawdown were the two major controlling factors in the occurrence of sand production. Further geomechanics simulation and particle-migration simulation with a multiphase dynamic flow simulator confirmed that the production drawdown would cause failure of the rock near the wellbore and the gas flow could transport the sand debris to the wellbore and lift it up to the surface. In addition, the fluctuation of production rate was caused by blockage because of the accumulation of sand particles in the wells and production tubing that were flushed out after downhole-pressure buildup.
Using the analysis, the threshold of flow velocity and the threshold of drawdown were identified, and these thresholds can be used in the reservoir management to effectively address the sanding issues.
The experience in Keshen shows that sanding is possible in HP/HT high-productivity sandstone gas reservoirs, even in an extremely hard formation, which overturns some prior conceptions on sanding. The information shared from this paper could attract the attention of those operating similar HP/HT tight-sandstone reservoirs around the world.
Barite is one of the most common weighting materials used in drilling fluids for deep oil and gas wells. Consequently, the main source of solids forming the filter cake is "barite particles," the weighting material used in drilling fluids. Barite is insoluble in water and acids such as hydrochloric acid (HCl) and formic, citric, and acetic acids, and barite is moderately soluble in chelating agents such as ethylenediaminetetraacetic acid (EDTA).
The present study introduces a new formulation to dissolve barite scale and barite filter cake using converters and catalysts. Barite can be converted to barium carbonate (BaCO3) in a high-pH medium (pH = 12) using a combination of potassium hydroxide (KOH) and potassium carbonate (K2CO3) solutions. Subsequently, HCl or low-pH chelating agents can be used to dissolve the BaCO3. Another solution is to use the EDTA chelating agent at pH of 12 and K2CO3 or KOH as a catalyst/converter in a single step. The removal formulation also contains a polymer breaker (oxidizers or enzymes). The three components of the new formulation are compatible with each other and stable up to 300°F. Solubility experiments were conducted using industrial-grade barite (particle size of 30 to 60 µm). The solubility experiments were conducted at 300°F for 24 hours. Varying concentrations of the catalyst were added to determine the optimal concentration. The developed formulation was tested for the removal of filter cake formed by barite drilling fluid using a high-pressure/high-temperature (HP/HT) cell. Filter-cake removal was conducted for filter cakes formed by both water- and oil-based drilling fluids.
The results of this study show that the barite-removal efficiency of the new formulation is 87% for water-based mud (WBM) and 83% for oil-based mud (OBM). The test results show that the solubility of barite particles in 0.6 M EDTA is 62 wt% in 24 hours at 300°F. Adding K2CO3 or KOH catalyst to the 0.6-M-EDTA solution increases the solubility of barite to 90 wt% in 24 hours at 300°F. Thus, barite scale can be removed efficiently using high-pH formulations (pH = 12) to avoid the safety issues associated with HCl. Because the EDTA chelating agent is compatible with the polymer breaker (oxidizer), the filter cake can be removed in a single stage. The concentration of the components of the formulations used in this study is as follows: 10 wt% oxidizer, 10 wt% K2CO3 or KOH concentration (catalyst/converter), and 0.6 M EDTA. The developed formulations achieved more than 80% filter-cake removal in both oil-based and water-based drilling fluids. For OBM, a water-wetting surfactant, a mutual solvent, and an emulsifier were added tot he formulation to remove the oil and to make the surface of the filter cake water-wet. In this study, two solutions are proposed to remove the barite filter cake and barite scale from oil and gas wells at different conditions. The first one is using HCl after converting the barium sulfate (BaSO4) to BaSO3 by use of a high-pH medium such as KOH and K2CO3. Although HCl can easily remove the resulting BaSO3, the generated barium chloride (BaCl2) is a safety and health concern. The second method is to create a high-pH medium (pH = 12) using the removal fluid itself, which uses the EDTA chelating agent in addition to using K2CO3 or KOH as converters.
Ernens, Dennis (Shell Global Solutions International) | Hariharan, Hari (Shell International Exploration and Production Incorporated) | van Haaften, Willem M. (Shell Global Solutions International) | Pasaribu, Henry R. (Shell Global Solutions International) | Jabs, Matthew (Shell International Exploration and Production Incorporated) | McKim, Richard N. (Shell Exploration and Production Company)
Brazing technology allows metallurgical joining of dissimilar materials using a filler material. In this paper, brazing technology applied to casing connections is presented as an enhancement of existing (premium) connections and/or a replacement of metal/metal seals. The initial application was triggered by challenges with mechanical and pressure integrity after the expansion of casing connections. Creating a strong bond between the pin and the box could resolve this and remove the need for a metal/metal seal. Brazing was selected because of the combination of ductility and high bond strength and the relatively fast process to create the bond. The brazing process or the temperature/torque/time (TTT) process is performed using regular casing connections, a filler material deposited by flame spray and a flux. Two processes were developed, one for expandable (VM 50) grade material and one for quenched and tempered grade material. A rig-ready (Class 1, Division 1) prototype brazing system was developed consisting of an induction coil as the heat source, an environmental chamber to shield the hot work, and a modified power tong to provide torque. The results of a series of brazing trials on 85/8- and 95/8-in.-casing connections are presented. The brazed connections were subsequently capped, end-pressure tested, expanded (when applicable), and load cycled. It is concluded that both processes produced leak-tight casing connectors before and after expansion (when applicable), as shown by full-scale tests.
The effective placement of proppant in a fracture has a dominant effect on well productivity. Existing hydraulic-fracture models simplify proppant-transport calculations to varying degrees. A common assumption applied is that the average proppant velocity caused by flow is equal to the average carrier-fluid velocity, while the settling-velocity calculation uses Stokes’ law. To more accurately determine the placement of proppant in a fracture, it is necessary to account for many effects not included in previous assumptions.
In this study, the motion of particles flowing with a fluid between fracture walls is simulated with a coupled computational-fluid-dynamics/discrete-element method (CFD/DEM) code that uses both particle dynamics and CFD calculations to account for both particles and fluid. These simulations (presented in metric units) determine individual particle trajectories as particle-to-particle and particle-to-wall collisions occur, and include the effect of fluid flow. The results show that the ratio of proppant diameter to fracture width governs the relative average velocity of proppant and fluid.
A proppant-transport model developed from the results of the direct numerical simulations and existing correlations for particle-settling velocity has been incorporated into a fully 3D hydraulic-fracturing simulator. This simulator couples fracture geomechanics with fluid-flow and proppant-transport considerations to enable the fracture geometry and proppant distribution in the main hydraulic fracture to be determined. For two typical shale-reservoir cases, the proppant placement and width distribution have been determined, allowing comparison at the hydraulic-fracture scale, including effects observed at the particle scale. This allows for optimization of the treatment to a specific application, and the results are presented in oilfield units, considered more familiar to our readers.
Two key benefits of downhole-gauge (DHG)-data analysis are identifying and minimizing the root causes of any failures that might occur during gravel packing and calibrating or verifying friction-pressure data for gravel-placement simulations. Although downhole pressure and temperature gauges are used often in openhole gravel packing, and expertise in analyzing the data certainly exists in companies that routinely use DHGs, to our knowledge, there is no publication that comprehensively discusses the method of analysis. DHG-data analysis, in general, requires more information than the gauge data themselves. This includes logs, wellbore schematic, pumping schedule, fluid properties, return-flow measurements, daily rig reports, and data relevant to displacements.
The objective of this paper is to provide guidelines for DHG-data analysis to completion engineers, who are not routinely involved and thus are not experts in such analysis, by detailing the factors that must be kept in mind, offering a method, and demonstrating this method with several examples.
Limited-entry (LE) plug-and-perforate (PnP) fracture designs were pioneered in the early 1960s as a cost-effective technique to stimulate multiple pay zones with varying stress regimes (Murphy and Juch 1960). Conventional completion techniques involved blanket perforating the entire interval at a certain number of shots per foot (spf). The LE technique was revolutionary in that it recommended “limiting” the number of perforations to distribute fracture-stimulation fluids into multiple intervals with differing stress regimes. However, diagnostics have shown that LE-treatment distribution during the slurry phase is uneven, and is highly affected by several key parameters that may change significantly during treatment. Several papers have been published on the inefficiencies associated with LE design and what can be performed to overcome them (Ugueto et al. 2016; Somanchi et al. 2016).
Shell Canada Limited recently tested extreme limited-entry (XLE) designs to determine if additional pressure drop across the perforations would improve treatment distribution. Stages were alternated with differential perforation friction (ΔP) pressures of 2,000, 2,500, and 3,000 psi to determine if there was a threshold ΔP that would result in a more-optimal treatment distribution. However, because of wellhead-pressure limitations, actual ΔPs were below the design values. There were no placement issues associated with fewer perforations and higher treatment pressures.
The trial well was completed with thirteen three-cluster stages. All clusters were spaced evenly at 50 m and fracture-stimulated with a slickwater system with 31 tons/cluster (93 tons/stage). The fracture stimulation was monitored with an externally clamped fiber-optic (FO) cable. Treatment distribution and production were quantified by using distributed acoustic sensing (DAS) (Molenaar and Cox 2013).
Post-job analysis indicates a 40% improvement in distribution compared with previously stimulated three-cluster standard LE completions. With the XLE design, 100% of the clusters received some proppant. There is a 33% increase in cluster activity at IP90 (initial production on the 90th day) from the XLE design compared with a previously completed three-cluster conventional LE well. Improvement in distribution is minimal beyond ΔP of 1,200 psi during the pad phase. However, this threshold could be rock-specific and needs to be validated with trials in different play types. Data also suggest that treatment pressure should be maintained at a maximum throughout the pad and slurry placements, within equipment and wellhead limitations. During the pad, this is important to ensure breakdown and fracture extension. In the slurry phase, maximizing out pressure helps to maintain ΔP across eroding perforations.
In some plays, insufficient ΔP may prevent all clusters from breaking down. In Groundbirch, typically all clusters break down and take fluid from the start but screen out as soon as sand hits. Typically, slurry rate was not increased to compensate for the loss in ?P associated with an increase in perforation diameter. These factors are mainly responsible for the heel-vs.-toe bias in LE designs, which results in undertreatment of toe clusters (Ugueto et al. 2016).
An oil and gas operator in the Gulf of Mexico (GOM) planned to drill a deepwater well section in one run by concurrently drilling and enlarging a 12¼- to 14½-in. hole while deviating from 60 to 30° inclination and crossing expected depleted formations. At section total depth (TD), the rathole below the underreamer needed to be eliminated to help ensure successful cementing of the liner. A bottomhole assembly (BHA) was designed to allow achieving these objectives in one run, and the field results obtained with the system are described.
The first step in determining the best BHA design was to compile drilling experiences through the target formations and perform a review of all pertinent offset-well information. Weaker zones had been encountered in the 12¼ × 14½-in. section, and an at-bit reamer (ABR) had to be included in the BHA to allow the liner to be set on the bottom of the section, rather than leaving an 85- to 135-ft rathole. Because the ABR placement in the BHA is between the bit and the rotary-steerable-system (RSS) tool, it was important to ensure that directional control could be maintained in the section and make certain no interference existed between the ABR and the wellbore that could compromise control. Stabilization and placement of the underreamer were also crucial to ensure that the necessary directional performance was obtained without overstressing the BHA components, and modeling was performed to optimize the design. Hydraulics and torque-and-drag modeling ensured that the BHA design could drill the depleted zone without premature activation of either reamer.
The modeling and analysis of offset performance resulted in successfully drilling the section and opening the rathole in one run. The BHA was steered to the final desired angle, and reached the section TD without incident and at the desired rate of penetration (ROP). After the section TD was reached, the ABR successfully opened the 12¼-in. rathole to the desired 14 in., allowing the liner to be set 3 ft from the bottom. Normally, this type of operation would require a separate dedicated hole-opening run. Using the new design eliminated the additional trip and the time necessary to open the hole, which was estimated at 56 hours.
A BHA solution was developed through modeling that allowed the operator to not only maintain the steerability needed to achieve directional requirements with an ABR between the bit and the RSS while drilling depleted formations but also to concurrently perform underreaming.
Perforation with shaped charges as a conventional well-completion technique is widely used in the oil industry. Different phenomena influence perforation performance and depth of penetration (DOP). The authors examined the effect of in-situ stresses and shot density on DOP and created fracture patterns in concrete and limestone samples with surface and polyaxial/triaxial-stress-loading conditions. To achieve this aim, we designed and developed a polyaxial-perforation test machine. We optimized the number of experimental tests using the Taguchi-design test method. The Taguchi orthogonal scheme is well-known and is a highly recommended method to optimize the number of required experiments (Taguchi 1990; Ross 1996; Jeyapaul et al. 2005; Gupta et al. 2014). Our experimental setup resembles vertical wells in the strike/slip-faulting regions and horizontal wells in the reverse-faulting regions. The results show that DOP is more controlled by stresses normal to the shooting direction in polyaxial tests than by the stress in the direction of penetration. DOP and the maximum hole diameter from the second charge had a direct relation with shot density. The DOP observed in polyaxial-loading conditions was a little lower than in the triaxial-loading mode, where the mean value of stresses normal to the shooting direction in the polyaxial tests was the same as the horizontal stresses in the triaxial tests. In both surface and triaxial-loading conditions, the patterns of perforation fractures were radial and regular, whereas the cracks created were oriented along the direction of maximum horizontal stress in the polyaxial tests.