Aranha, Pedro Esteves (Petrobras) | Colombo, Danilo (Petrobras) | Fernandes, André Alonso (Petrobras) | Vanni, Guilherme Siqueira (Petrobras) | Tomita, Reinaldo Akio (Petrobras) | Lima, Cláudio Benevenuto de Campos (Petrobras) | Lima, Gilson Brito Alves (Federal Fluminense University) | Wasserman, Júlio César de Faria Alvim (Federal Fluminense University)
The demand for ultradeepwater scenarios invoked the frequent application of managed pressure drilling (MPD) in the last few years. In an ultradeepwater scenario, oil companies face issues such as narrow pressure windows and severe loss zones. Many wells are considered undrillable without the aid of MPD technology. MPD operations need to be correctly evaluated with consideration given to increased time and cost/benefit analysis. In this paper, we propose a probabilistic model to evaluate MPD demand by estimating the optimal number of rigs equipped with MPD and a rotating control device (RCD), and we analyze which intervention strategy is the most cost- and time-effective. Reducing uncertainty is an important factor when making decisions about drilling. We adopted a Monte Carlo simulation using loss-zone estimation, probability of prediction error, the number of rigs equipped with MPD, and several strategies. Better MPD strategies were determined on the basis of available data and the optimal number of rigs equipped with an MPD system and RCD equipment, reducing subjectivity in the decision-making process. The originality of our paper lies in the new quantitative approach to dealing with uncertainty in the prediction of fluid losses and the cost and duration of different MPD strategies, numerically simulating the possible scenarios.
A new drillstring model has been developed that determines the static and dynamic behavior of bottomhole assemblies (BHAs) in 3D wellbores. An attempt at validating this model with field data is presented, and it shows a close agreement between observed and calculated downhole BHA behavior.
Validation tests were conducted using high-frequency downhole data measured within a motor-assisted rotary-steerable BHA. The gathered data were used to verify the calculated mechanical loads, predicted lateral natural frequencies of the BHA, estimated directional performance of the downhole assembly, and the torsional resonance resulting from high-frequency torsional oscillations (HFTOs).
Results from the field tests show a strong correlation between measured and calculated bending-moment values, as well as lateral natural frequencies of the BHA, with an average of 3% error across all data sets. The primary source of error is thought to be borehole spiraling, which is quantified through analysis of the downhole bending-moment data. In addition, the model is shown to provide close estimates of the actual directional performance of both steerable mud motors and rotary-steerable BHAs. However, the directional-calculation vs. -measurement comparison does reveal a need to incorporate a rate-of-penetration (ROP) dependency within the directional-prediction algorithms.
The occurrence of reversible mud losses and gains while drilling in naturally fractured formations (NFFs) is of primary concern. Borehole breathing can complicate the already difficult practice of fingerprinting the changes in the return-flow profile, hence undermining the reliability of kick detection. Issues can also derive from misdiagnosing a kick and attempting to kill a breathing well. The objective of this work is to correctly address the phenomenon and increase insights regarding its physical characterization. The fluid progressively flows in and out of fractures as a consequence of three mechanisms: bulk volume deformation, fluid compressibility, and fracture-aperture variation. To represent this complex scenario, a model involving a continuously distributed fracture network is developed. A time-dependent, 1D dual-poroelastic approach is coupled with a variable fracture aperture and a passive porous phase. Finite fracture network length is considered, and no limitation on the number of fractures is posed. The latter permits us to analyze long openhole sections intersecting several fissures, which is a more realistic approach than the available single-fracture models. The proposed model is able to quantify pressure distribution in fractures and pores, together with the flow rate entering or exiting the fractures. Furthermore, a useful application of the model is proposed by suggesting its application as a breathing discriminator during kick diagnosis. The shut-in drillpipe pressure (SIDPP), recorded from a real kick, has been compared with one caused by a simulated breathing case. Although the two SIDPPs show significant similarities, the correct modeling of breathing can help the identification of the major differences between a kick and breathing.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Dalton, Laura E. (US Department of Energy National Energy Technology Laboratory and Oak Ridge Institute of Science and Education) | Brown, Sarah (US Department of Energy National Energy Technology Laboratory, AECOM) | Moore, Johnathan (US Department of Energy National Energy Technology Laboratory, AECOM) | Crandall, Dustin (US Department of Energy National Energy Technology Laboratory) | Gill, Magdalena (US Department of Energy National Energy Technology Laboratory, AECOM)
The operational use of nanoparticles (NPs) in drilling and completion fluids is still limited at the present time, in part because of a lack of consistent evidence for and clarification of NP interactions with rock formations, formation fluid, and other fluid additives. For instance, previous fluids research emphasized that NPs bring about pore plugging, which reduces pressure transmission and, in turn, fluid inflow, into the shale pore matrix, which ultimately helps stabilize the borehole. However, it is difficult to understand how pore plugging might be accomplished in the absence of any substantial filtration in shales, considering that the minimal permeability of shales does not allow for any appreciable Darcy flow. This paper addresses the crucial question: “How, when, and why do NPs plug shale pore throats?”
Zeta-potential (ZP) measurements were carried out on aqueous NP dispersions and on intact thin shale sections exposed to nanofluids to determine the degree of interaction behavior between NPs and shale. The experimental data were then used to calculate Derjaguin-Landau-Verwey-Overbeek (DLVO) curves (describing the force between charged surfaces interacting through a liquid medium) to determine if the total potential energy was sufficient for NPs to diffuse through the repellent barrier and attach to the shale surface. Calculated DLVO curves were used to demonstrate the NPs ability to contribute to borehole stability, but did not directly correlate the effects the NPs had on shale stability. Experiments, including pore pressure-transmission tests (PTTs), which measure fluid pressure penetration in shale, and modified thick-walled-cylinder (TWC) collapse tests, which explore the influence of NPs on the collapse pressure of shale samples, were conducted to directly investigate the effects of NPs on borehole stability in shale.
Our investigation showed that NPs can reduce fluid pressure penetration and delay borehole collapse in shale, but only under certain conditions. Electrostatic/electrodynamic interaction between NPs and shale surfaces, governed by DLVO forces, is the main mechanism that leads to pore-throat plugging, reducing pressure transmission, which in turn benefits borehole stability by slowing down near-wellbore pore-pressure elevation and effective-stress reduction. For Mancos Shale, 20-nm anionic nanosilica particles were effective in partially plugging the pore-throat system, depending on the pH of the nanofluid, which affects the surface potential and ZP of both NPs and shale. Furthermore, cationic nanosilica showed better results for pore-plugging capabilities than the anionic nanosilica.
Our findings lead to interesting challenges for the practical field application of NP-based drilling fluids for borehole stability, given that efficacy depends on the specific type of shale; the specific type, size, and concentration of NP; the interaction between NPs and shale; and external factors, such as pH, salinity, and temperature. Therefore, NP use for practical shale stabilization requires a dedicated, thoroughly engineered solution for each particular field application, and is unlikely to be “one size fits all.”
Ernens, Dennis (Shell Global Solutions International BV and University of Twente) | van Riet, Egbert J. (Shell Global Solutions International) | de Rooij, Matthias B. (University of Twente) | Pasaribu, Henry R. (Shell Global Solutions International) | van Haaften, Willem M. (Shell Global Solutions International) | Schipper, Dirk J. (University of Twente)
D. Ernens, Shell Global Solutions International BV and University of Twente; E. J. van Riet, Shell Global Solutions International; M. B. de Rooij, University of Twente; H. R. Pasaribu and W. M. van Haaften, Shell Global Solutions International; and D. J. Schipper, University of Twente Summary Phosphate-conversion coatings are widely used on (premium) casing connections for protection against corrosion. These coatings provide galling protection in conjunction with lubricant. The friction and wear that occur during makeup and subsequent load cycling strongly influence the sealing performance of the metal/metal seal. An extensive test program was set up to investigate the role of phosphate coatings during makeup and in the subsequent sealing of the metal/metal seal. With pinon-disk, anvil-on-strip, and ring-on-ring tests, the interactions between the substrate, lubricant, and phosphate coating were investigated. A comparison was made between uncoated and coated specimens using base greases and formulated greases: API-modified lubricant and two commercially available yellow dopes. The results indicate a strong influence of the phosphate coating leading to damage-free makeup, low wear, and less dependence on the lubricant for optimal sealing ability. This is attributed to the formation of a hard and smooth dissimilar surface, the ability to adsorb the lubricant, and the generation of a transfer layer on the uncoated countersurface. It is concluded that taking the interaction with phosphates into account could enable lubricants to be tailored for sealing performance, and thus can ease the transition to environmentally friendly rated lubricants. Introduction Phosphate-conversion coatings (Rausch 1990; Narayanan 2005) were initially applied on (premium) casing connections for protection against corrosion during storage. A side effect of the presence of the phosphate coatings was improved galling resistance (Ertas 1992). Phosphate-conversion coatings therefore play an important role in the proper makeup of casing connections and their subsequent sealing performance. The premium connection (Figure 1), and for this paper its metal/metal seal, should be considered as a (tribo)system (Salomon 1974; Czichos and Winer 1978), which is defined as the combination of lubricant (dope), coating, surface finish, and casing-material grade under sliding conditions. The contact conditions are determined by the pin/box interference and the mechanical properties of the pipe material.
Modern multifractured shale-gas/oil wells are horizontal wells completed with simultaneous-fracturing, zipper-fracturing, and (in particular) modified-zipper-fracturing techniques. An analytical model was developed in this study for predicting the long-term productivity of these wells under conditions of pseudosteady-state (PSSS) flow, considering the cross-bilinear flow in the rock matrix and hydraulic fractures. Performance of the model was verified with the well-productivity data obtained from a shale-gas well and a shale-oil well. Sensitivity analyses were performed to identify key parameters of hydraulic fracturing affecting well productivity. The conducted field case studies show that the analytical model overpredicts shale-gas-well productivity by 2.3% and underpredicts shale-oil productivity by 7.4%. A sensitivity analysis with the model indicates that well productivity increases with reduced fracture spacing, increased fracture length, and increased fracture width, but not proportionally. Whenever operational restrictions permit, more fractures with high density should be created in the hydraulic-fracturing process to maximize well productivity. The benefit of increasing fracture width should diminish as the fracture width becomes large. Increasing fracture length by pumping more fracturing fluid can increase well-production rate nearly proportionally. Therefore, it is desirable to create long fractures by pumping high volumes of fracturing fluid in the hydraulic-fracturing process.
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.
Sawaryn, Steven J. (Consultant) | Wilson, Harry (Baker Hughes, a GE company) | Bang, Jon (Gyrodata Incorporated) | Nyrnes, Erik (Equinor ASA) | Sentance, Andy (Dynamic Graphics Incorporated) | Poedjono, Benny (Schlumberger) | Lowdon, Ross (Schlumberger) | Mitchell, Ian (Halliburton) | Codling, Jerry (Halliburton) | Clark, Peter J. (Chevron Energy Technology Company) | Allen, William T. (BP)
The well-collision-avoidance separation rule presented in this paper is a culmination of the work and consensus of industry experts from both operators and service companies in the SPE Wellbore Positioning Technical Section (WPTS). This is the second of two papers and complements the first paper, SPE-184730-PA (Sawaryn et al. 2018), which described the collision-avoidance management practices. These practices are fundamental in establishing the environment in which a minimum allowable separation distance (MASD) (in m) between two adjacent wells can be effectively applied. A standardized collision-avoidance rule is recommended, complete with parameter values appropriate to the management of health, safety, and environment (HSE) risk, and benchmarks for testing it. Together, these should help eliminate the disparate and occasionally contradictory methods currently in use.
The consequences of an unplanned intersection with an existing well can range from financial loss to a catastrophic blowout and loss of life. The process of well-collision avoidance involves rules that determine the allowable separation and the management of the associated directional planning and surveying activities. The proposed separation rule is dependent on the pedal-curve method and is expressed as a separation factor, a dimensionless number that is an adjusted center-to-center distance between wells divided by a function of the relative positional uncertainty between the two. The recommended values for the rule’s parameters result from a comparison of various industry models and experience. The relationships between key concepts such as the MASD and allowable deviation from the plan (ADP) are discussed, together with their interpretation and application. The dependency on the error distributions of the survey-instrument performance models used to establish the tolerance lines is also discussed.
The consequences of implementing a standardized separation rule across the industry are far-reaching. This affects slot separations, trajectories, drilling practices, surveying program, and well shut-in. We show how the MASD can be related to a probability of crossing and being in the unacceptable-risk region of an offset well. We show why this qualification is required for safe drilling practices to be preserved. Examples are presented in Appendices A through D to help the reader validate the calculations and the directional-drilling software necessary to perform them. The geometrical and statistical limitations of the methods are explained and areas are highlighted for further work. The methods outlined here, taken together with SPE-184730-MS, will improve efficiency in planning and executing wells and promote industry focus on the associated collision risks during drilling. The WPTS also supports the current development of API RP 78, Recommended Practices for Wellbore Positioning. Mathematical derivations or references are shown for all the calculations presented in the paper.