SUMHOLE DRILLING: WELLBORE STABILITY CONSIDERATIONS BASED UPON FIELD AND LABORATORY DATA

1996 ◽  
Vol 36 (1) ◽  
pp. 544
Author(s):  
M.A. Addis ◽  
R.G. Jeffrey
Keyword(s):  
Field Data ◽  
Drilling Fluid ◽  
Laboratory Data ◽  
Petroleum Industry ◽  
Cost Savings ◽  
Wellbore Stability ◽  
Wellbore Instability ◽  
Attractive Option ◽  
Different Diameters ◽  
Fluid Design

Slimhole drilling is becoming an attractive option as it provides significant cost savings in the petroleum industry. Furthermore, many of the technical obstacles in adapting slimhole drilling for the petroleum industry have been addressed, such as rig modifications, small volume kick detection, drilling fluid design, etc. However, wellbore stability in slimholes is largely taken for granted, when it could potentially increase costs dramatically. In this paper, a review of the available information on the effects of hole size on hole stability is presented. Wellbore stability in holes of different diameters is discussed qualitatively based on published laboratory data and unpublished field data. The quantitative assessment of wellbore instability in slimholes is addressed using observations of instability in a well in which the far field stresses were measured.The field data presented here suggest that slimhole wells are not more stable than conventional wells. The slimhole drilled in NSW shows that even using the most conservative prediction model, wellbore instability would not be predicted—instability was however, observed.

Interdisciplinary Approach for Wellbore Stability During Slimhole Drilling at Volga-Urals Basin Oilfield

2021 ◽  
Author(s):  
Anna Vladimirovna Norkina ◽  
Sergey Mihailovich Karpukhin ◽  
Konstantin Urjevich Ruban ◽  
Yuriy Anatoljevich Petrakov ◽  
Alexey Evgenjevich Sobolev
Keyword(s):  
Drilling Fluid ◽  
Interdisciplinary Approach ◽  
Wellbore Stability ◽  
Vertical Wells ◽  
Wellbore Instability ◽  
Water Based ◽  
Chemical Studies ◽  
Fluid Rheology ◽  
Selection Of

Abstract The design features and the need to use a water-based solution make the task of ensuring trouble-free drilling of vertical wells non-trivial. This work is an example of an interdisciplinary approach to the analysis of the mechanisms of instability of the wellbore. Instability can be caused by a complex of reasons, in this case, standard geomechanical calculations are not enough to solve the problem. Engineering calculations and laboratory chemical studies are integrated into the process of geomechanical modeling. The recommendations developed in all three areas are interdependent and inseparable from each other. To achieve good results, it is necessary to comply with a set of measures at the same time. The key tasks of the project were: determination of drilling density, tripping the pipe conditions, parameters of the drilling fluid rheology, selection of a system for the best inhibition of clay swelling.

Risk Due to Wellbore Instability

2014 ◽  
pp. 23-46
Author(s):  
Nediljka Gaurina-Medjimurec ◽  
Borivoje Pasic
Keyword(s):  
Risk Assessment ◽  
Early Recognition ◽  
Petroleum Industry ◽  
Wellbore Stability ◽  
Effective Solution ◽  
Wellbore Instability ◽  
Drilling Operation ◽  
General Overview ◽  
Well Design ◽  
Exploration And Production

Exploration and production as one of the most important parts of the petroleum industry encounters different problems, usually resulting in nonproductive time and additional expenses. The most common and most expensive of them are related to wellbore instability and associated problems. Wellbore instability problems are usually related to drilling operation, but they can also appear during completion, workover, or the production stage of a certain well. The traditional solution for wellbore instability problems is composed from the early recognition of specific wellbore instability problems, the main cause identification and swift response. For more effective solution it is necessary to incorporate wellbore stability and risk assessment in the early phase of well design. This chapter gives one general overview of wellbore instability problems and their causes as well as an overview of actual approaches and methods in wellbore stability and risk assessment.

Optimization of Drilling Fluid Design for Managing Wellbore Instability in K-Shale in the Malay Basin of Peninsular Malaysia

2002 ◽  
Author(s):  
C.P. Tan ◽  
Mohd Azriyuddin Yaakub ◽  
X. Chen ◽  
D.R. Willoughby ◽  
Pauziyah Abdul Hamid ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Peninsular Malaysia ◽  
Wellbore Instability ◽  
Fluid Design

scholarly journals Oil-Based Drilling Fluid Plugging Method for Strengthening Wellbore Stability of Shale Gas

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Pengcheng Wu ◽  
Chengxu Zhong ◽  
Zhengtao Li ◽  
Zhen Zhang ◽  
Zhiyuan Wang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Fluid System ◽  
Horizontal Drilling ◽  
Wellbore Instability ◽  
Filtration Loss ◽  
Treatment Agent ◽  
Stability Method

Finding out the reasons for wellbore instability in the Longmaxi Formation and Wufeng Formation and putting forward drilling fluid technical countermeasures to strengthen and stabilize the wellbore are very crucial to horizontal drilling. Based on X-ray diffraction, electron microscope scanning, linear swelling experiment, and hot-rolling dispersion experiment, the physicochemical mechanism of wellbore instability in complex strata was revealed, and thus, the coordinated wellbore stability method can be put forward, which is “strengthening plugging of micropores, inhibiting filtrate invasion, and retarding pressure transmission.” Using a sand bed filtration tester, high-temperature and high-pressure plugging simulation experimental device, and microporous membrane and other experimental devices, the oil-based drilling fluid treatment agent was researched and selected, and a set of an enhanced plugging drilling fluid system suitable for shale gas horizontal well was constructed. Its temperature resistance is 135°C and it has preferable contamination resistibility (10% NaCl, 1% CaCl2, and 8% poor clay). The bearing capacity of a 400 μm fracture is 5 MPa, and the filtration loss of 0.22 μm and 0.45 μm microporous membranes is zero. Compared with previous field drilling fluids, the constructed oil-based drilling fluid system has a greatly improved plugging ability and excellent performance in other aspects.

scholarly journals COMPARATIVE ANALYSIS OF CARBOXYMETHYL CELLULOSE AND PARTIALLY HYDROLYZED POLYACRYLAMIDE – LOW-SOLID NONDISPERSED DRILLING MUD WITH RESPECT TO PROPER-TY ENHANCEMENT AND SHALE INHIBITION

2020 ◽  
pp. 24-33
Author(s):  
B. Das ◽  
B. Borah ◽  
S. Bhattacharyya
Keyword(s):  
Comparative Analysis ◽  
Carboxymethyl Cellulose ◽  
Drilling Fluid ◽  
Petroleum Industry ◽  
Solid Content ◽  
Wellbore Stability ◽  
Drilling Mud ◽  
Partially Hydrolyzed Polyacrylamide ◽  
Fluid Properties ◽  
Hydrolyzed Polyacrylamide

During drilling, different problems are encountered that can interfere with smooth drilling processes, including the accumulation of cuttings, reduced penetration rates, pipe sticking, loss of wellbore stability, and loss of circulation. These problems are generally encountered with conventional drilling mud, such as the bentonite–barite mud system. Formation damage is the most common problem encountered in bentonite mud systems with high solid content. In this work, we aimed to formulate two low-solid nondispersed (LSND) muds: carboxymethyl cellulose (CMC)–LSND mud and partially hydrolyzed polyacrylamide (PHPA)–LSND mud. A comparative analysis was performed to evaluate their property enhancements. LSND muds aid in maintaining hole stability and proper cutting removal. The results of this work show that the addition of both CMC and PHPA helps to improve drilling fluid properties; however, the PHPA–LSND mud was found to be superior. Shale swelling is a major concern in the petroleum industry, as it causes various other problems, such as pipe sticking, low penetration rates, and bit wear. The effect of these two LSND polymer muds in inhibiting shale swelling was analyzed using shale collected from the Champhai district of Mizoram, India.

Treatment of Prodigious Reactive Shale in the Permian Basin Using High-Performance Drilling Fluid: A Successful Case Study

2021 ◽  
Author(s):  
Almostafa Alhadi ◽  
Musaab Magzoub
Keyword(s):  
Emulsion Stability ◽  
Drilling Fluid ◽  
Treatment Plan ◽  
Wellbore Stability ◽  
Wetting Agent ◽  
Water Phase ◽  
Permian Basin ◽  
Wellbore Instability ◽  
Hole Cleaning ◽  
Rock Samples

Abstract In the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems. During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events. The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.

Development Field First - Directionally Drilling Through Challenging Muderong Shale and Highly Depleted Reservoir Sand with HPWBM

2021 ◽  
Author(s):  
Tylan John Lambert ◽  
Shiv Aanand Mj ◽  
Courtney Clark
Keyword(s):  
High Performance ◽  
Chemical Interaction ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Robust Solution ◽  
Fluid Analysis ◽  
Well Design ◽  
Design Selection ◽  
Fluid Design

Abstract Advancement in High Performance Water Based Mud (HPWBM) coupled with a deeper understanding of shale and chemical interaction has taken a leap in recent years enabling the drilling of challenging wells whilst replacing Synthetic Based Mud (SBM) as the preferred technical option. The exceptional inhibition properties, versatility to chemical manipulation and stability, as well as being an environmentally beneficial alternative to SBM, HPWBM has proven to be a robust solution for drilling the challenging Muderong shale and highly depleted reservoir sands in the field. Through a detailed field wide offset review focusing on wellbore stability and shale reactivity relationship observations, time dependent shale reactivity and an engineered bridging package was the basis of a successful fluid formulation and selection which then resulted in a flawless execution of the challenging well. Various testing of shale cuttings from the field paired with an offset review was key to understanding the extent of shale reactivity in relation to the type of shale being drilled and cause of shale instability in the area. These results were imperative in providing technical justification to utilise HPWBM for drilling through the Muderong shale. Applying detailed reservoir drilling fluid analysis to the overburden drilling fluids design and incorporating previous offset fluid design learnings, provided a robust and versatile drilling fluid system. This paper will review the steps undertaken to validate the selection of HPWBM over SBM through detailed analysis of wellbore stability, shale reactivity, permeability assessment, pore throat sizing and pore pressure transmission. It will present the misnomer of comingling the wellbore stability requirement, primarily mud weight, with shale reactivity in the field as well as the relation between the plateauing of shale reactivity curves to near well wellbore swelling. Extensive laboratory testing was performed to formulate and demonstrate the efficacy of the bridging package in addressing differential sticking, losses and wellbore strengthening in highly depleted sands. In addition, this paper will also present actual field results on stability of the fluid properties along with resultant torque and drag throughout drilling of a directional well with no requirement for lubricants. This paper should be of interest to all engineers and technologists who are involved in shale reactivity analysis, well design, drilling fluids design, selection and interaction as well as highly depleted reservoir sand drilling.

Effect of Drilling Fluid on Rock Mechanical Properties at Near-Drilling Conditions: An Implication of Fluid Design on Wellbore Stability

2016 ◽  
Author(s):  
Prahlad Kumar Yadav ◽  
Syed Shujath Ali ◽  
Najeeb Ahmed Al Tawat ◽  
Ali Abdullah Al Dhamen ◽  
Guodong Jin
Keyword(s):  
Mechanical Properties ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Fluid Design ◽  
Rock Mechanical Properties ◽  
Drilling Conditions

Application of Artificial Clay Samples (Pellets) in Laboratory Testing of Shale/Drilling Fluid Interaction

2013 ◽  
Author(s):  
Borivoje Pasic ◽  
Nediljka Gaurina-Medjimurec ◽  
Bojan Moslavac
Keyword(s):  
Laboratory Testing ◽  
Drilling Fluid ◽  
Petroleum Industry ◽  
Drilling Fluids ◽  
Surface Sampling ◽  
Laboratory Equipment ◽  
Wellbore Instability ◽  
Research Activities ◽  
Physico Chemical ◽  
Fluid Interaction

Wellbore instability was and is one of the most frequent problems in petroleum industry, especially in the drilling operations. It is mainly caused by the shale formations which represent 75% of all drilled formations. The wellbore instability problems involve tight hole spots, wellbore diameter enlargement, the appearance of cavings, the inability of carrying out wireline operations, poor hole cleaning, unsuccessful wellbore cementing operations and other. The wellbore instability is the result of mechanical and physico-chemical causes mostly acting concurrently. The shale instability basically comes out of its mineralogical composition (especially clay minerals content) and physico-chemical properties. Shale-mud interaction includes water/ions movement in and out of the shales due to pressure differential, osmosis, diffusive flow and capillary pressure. Many research activities about shale instability causes and shale properties (affecting shale behavior) definition have been carried out by now. Different shale samples, laboratory equipment and inhibitive muds have been used. Laboratory tested shale samples are provided by the wellbore cores, surface sampling or, which is the simplest method, by collecting the samples at the shale shakers during drilling operation. The amount of these samples is not enough for laboratory testing. Another problem is closely connected to sample quality and preservation. There are also differences in drilling fluids used in these laboratory tests, especially in their composition (sometimes containing more than one shale inhibitor). It is difficult to compare test results and conclusions made by different authors. The laboratory study presented within this paper are done with artificial clay samples (pellets) made by compacting the powderish material containing exact quantity of quartz, montmorillonite and kaolinite. The laboratory testing is done by treating the powderish samples inside the desiccator (24 hours), compacting (30 minutes), swelling (24 hours) and drying samples (24-hour). Sample swelling is tested by using different mud types and the sample mass is measured in each above mentioned phase. Special attention is directed to preparation and pellets content definition as a good replacement for the original shale in laboratory testing of shale and drilling fluid interaction. The influence of used muds on the total pellet swelling and swelling intensity, especially at the early phase of testing was determined.

The Influence of SiO2 and TiO2 Nanoparticles on the Properties of Water-Based Mud

2017 ◽  
Author(s):  
Petar Mijić ◽  
Nediljka Gaurina-Međimurec ◽  
Borivoje Pašić
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Drilling Mud ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Water Based ◽  
Fluid Properties

About 75% of all formations drilled worldwide are shale formations and 90% of all wellbore instability problems occur in shale formations. This increases the overall cost of drilling. Therefore, drilling through shale formations, which have nanosized pores with nanodarcy permeability still need better solutions since the additives used in the conventional drilling fluids are too large to plug them. One of the solutions to drilling problems can be adjusting drilling fluid properties by adding nanoparticles. Drilling mud with nanoparticles can physically plug nanosized pores in shale formations and thus reduce the shale permeability, which results in reducing the pressure transmission and improving wellbore stability. Furthermore, the drilling fluid with nanoparticles, creates a very thin, low permeability filter cake resulting in the reduction of the filtrate penetration into the shale. This thin filter cake implies high potential for reducing the differential pressure sticking. In addition, borehole problems such as too high drag and torque can be reduced by adding nanoparticles to drilling fluids. This paper presents the results of laboratory examination of the influence of commercially available nanoparticles of SiO2 (dry SiO2 and water-based dispersion of 30 wt% of silica), and TiO2 (water-based dispersion of 40 wt% of titania) in concentrations of 0.5 wt% and 1 wt% on the properties of water-based fluids. Special emphasis is put on the determination of lubricating properties of the water-based drilling fluids. Nanoparticles added to the base mud without any lubricant do not improve its lubricity performance, regardless of their concentrations and type. However, by adding 0.5 wt% SiO2-disp to the base mud with lubricant, its lubricity coefficient is reduced by 4.6%, and by adding 1 wt% TiO2-disp to the base mud with lubricant, its lubricity coefficient is reduced by 14.3%.

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