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.

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.

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.

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.

Sodium Silicate Based Drilling Fluid Application in Gulf of Thailand to Stabilise Wellbore: A Case Study

2021 ◽  
Author(s):  
Waleepon Sukarasep ◽  
Rahul Sukanta Dey ◽  
Visarut Phonpuntin
Keyword(s):  
Sodium Silicate ◽  
High Performance ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Gulf Of Thailand ◽  
Hole Cleaning ◽  
Water Based ◽  
Wellbore Strengthening ◽  
Effective Seal

Abstract Sodium Silicate were first used in water-based drilling fluids to stabilize claystone formations in the 1930's, but found favour in the 1990's in high performance, non dispersed water based systems for drilling problematic claystone formations as an alternative to oil-based drilling fluids. In Bongkot South field, Gulf of Thailand, sodium silicate-based drilling fluid (SSBDF) were used with mixed success in shallow gas drilling. Typically, platform WP-33, the claystone formation of the 12¼" section were drilled with 5% v/v Sodium Silicate in the water based drilling fluid together with excessive circulation as intention to improve hole cleaning frequently result in a wellbore that was overgauge by upto 18.9% in some case. This led to further hole cleaning problem that also compromised cement job quality. A further 6 well campaign on WPS-16 required a re-evaulation of the SSBDF coupled to an understanding of the wellbore instability mechanisms that leads to hole enlargement. To overcome better wellbore stability, sodium silicate has been designed by increased concentration to 8% v/v sodium silicate treated drilling fluid showed optimal design for application base on application of SSBDF has been used on platform WP-11 in 2002. Rheology, hydraulic and flow regime was adjusted for laminar flow that reduced the erosion of fragile claystone formation in the wellbore. The revised SSBDF formulation at WPS-16 result in a significant reduction of hole enlargement to 3.2% in the claystone section through a combination of chemicals and mechanical inhibition that contribute improved hole cleaning. The addition of wellbore strengthening material also provide an effective seal to minimize gas invasion. This paper describes the field trials in the Gulf of Thailand drilled with revised sodium sodium silicate based drilling fluid, the use of wellbore strengthening materials to manage gas influxes, better drilling practice and hydraclic simulation concluded that high performance water based drilling fluid of this nature have wider application where oil-base drilling fluid have traditionally been used.

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%.

Gel Breaking Affecting Factors Analysis on Polymer Bio-Degradation

2012 ◽  
Vol 550-553 ◽  
pp. 1369-1373
Author(s):  
Ji Hua Cai ◽  
Sui Gu ◽  
Hao Liu
Keyword(s):  
Substrate Concentration ◽  
Coalbed Methane ◽  
Drilling Fluid ◽  
Enzyme Concentration ◽  
Wellbore Stability ◽  
Affecting Factors ◽  
Horizontal Drilling ◽  
Wellbore Instability ◽  
Soft Coal ◽  
Soft Coal Seam

Recent years have witnessed a renewed interest in the development of coalbed methane (CBM) reservoirs. However, horizontal drilling in unconsolidated and soft coal seam for CBM drainage and exploitation often results in wellbore instability. This paper proposed degradable drilling fluid in CBM horizontal drilling which not only can maintain wellbore stability, but also minimize formation damages caused by drilling fluid. Its factors of gel breaking ratio were systematically studied from the aspects as substrate concentration, pH, temperature, enzyme concentration and reaction time. We found that in a condition when enzyme concentration is abundant, increasing of substrate concentration would result in higher gel breaking ratio. Furthermore, nearly neutral pH (pH≈7), moderate temperature (40°C~60°C), enzyme with higher concentration and longer action time (more than 3 hours) could enhance gel breaking ratio.

scholarly journals New insight on studying the effect of both chemical sensitivity and rock mechanical properties in shale formation to minimize wellbore instability problems

2020 ◽  
Vol 205 ◽  
pp. 03012
Author(s):  
Mohammad H. Alqam ◽  
Hazim H. Abass ◽  
Abdullah M. Shebatalhmad
Keyword(s):  
Drilling Fluid ◽  
Wellbore Stability ◽  
High Porosity ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Testing Procedures ◽  
Shale Formation ◽  
Rock Mechanical Properties ◽  
Core Volume ◽  
Shale Permeability

Historically, many of the wells drilled in in shale formations have experienced a significant rig downtime due to wellbore instabilities. Most of the instability problems originated from the encountered shale formations. The objectives of this study include (1) to measure the properties governing shale strength and drilling fluid/shale interaction, and (2) to establish a reliable and efficient rock mechanical testing procedures related to wellbore stability. Preserved shale core has been recovered from shale formation and special core handling procedure was implemented. Mineral oil was used for plugging and core preservation. Rock mechanical characterization was conducted on core samples using both XRD/SEM techniques to study the core mineralogy. In addition, shale permeability was determined by two methods: flow testing and pressure transition methods. The results indicated that shale has high percentage of quartz (30-40%) which causes the shale to have high porosity and high permeability. The unconfined compressive strength of shale is very low which any drilling fluid that contains water phase further reduces. The Young’s modulus is very low which makes near wellbore deformation high. Based on the shale swelling testing, the all-oil fluid show no volume change occurred to the shale. When the same shale was exposed to the 7% KCl, about 16% increase in core volume occurred in 48 hours. This means that all samples allowed the water to flow into the shale formation.

scholarly journals Probabilistic Approach in Wellbore Stability Analysis during Drilling

2016 ◽  
Vol 2016 ◽  
pp. 1-13 ◽  
Author(s):  
Mahmood R. Al-Khayari ◽  
Adel M. Al-Ajmi ◽  
Yahya Al-Wahaibi
Keyword(s):  
Deterministic Model ◽  
Drilling Fluid ◽  
Probabilistic Approach ◽  
Fluid Pressure ◽  
Wellbore Stability ◽  
Rock Properties ◽  
Well Drilling ◽  
Collapse Pressure ◽  
Wellbore Instability

In oil industry, wellbore instability is the most costly problem that a well drilling operation may encounter. One reason for wellbore failure can be related to ignoring rock mechanics effects. A solution to overcome this problem is to adopt in situ stresses in conjunction with a failure criterion to end up with a deterministic model that calculates collapse pressure. However, the uncertainty in input parameters can make this model misleading and useless. In this paper, a new probabilistic wellbore stability model is presented to predict the critical drilling fluid pressure before the onset of a wellbore collapse. The model runs Monte Carlo simulation to capture the effects of uncertainty in in situ stresses, drilling trajectories, and rock properties. The developed model was applied to different in situ stress regimes: normal faulting, strike slip, and reverse faulting. Sensitivity analysis was applied to all carried out simulations and found that well trajectories have the biggest impact factor in wellbore instability followed by rock properties. The developed model improves risk management of wellbore stability. It helps petroleum engineers and field planners to make right decisions during drilling and fields’ development.

scholarly journals An Assessment of the Causes of Wellbore Instability and Stuck Pipe Occurrences in an Offshore Field, Niger Delta, Nigeria

2020 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Cation Exchange ◽  
Niger Delta ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Swelling Potential ◽  
Offshore Drilling ◽  
Wellbore Instability ◽  
Clay Swelling ◽  
Drilling Operations ◽  
Cationic Exchange

Wellbore instability and consequential stuck pipe issues are a common challenge associated with offshore drilling. Usually, the effect of wellbore instability is an increase in nonproductive time, possible loss of tools and costly drilling operations. Hence, there is a need for wellbore stability analyses before and during drilling operations. In “Agaza Field”, offshore Niger Delta, wellbore instability problems were encountered at various depths between 3,696-4,270 ft.; 5,000-5,425 ft. and 7,600-8000 ft. intervals. Sixty-five ditch-cutting samples and composite log plots obtained from both wells were and analyzed to determine the clay swelling potential and the cationic exchange between the formation and the drilling fluid as well as causes of formation instability. Agaza-1 well showed evidence of tight hole at intervals between 4,200 and 7,600 ft. In Agaza-2, there were indications of wellbore stresses from 1,908 ft. to 2,030 ft. However, deeper than 4,225ft depth, high fluctuation of pore pressure coincided with wellbore instability between 4,810 ft. and 5,200 ft. The principal clay minerals present within the formations are Illite, Smectite and Smectite/Illite interlayered types. Result of the cation exchange analysis showed that high concentration of calcium and sodium in the shale is responsible for high dissociation of the constituent minerals hence making the shales unstable. Analysis has shown that samples at some intervals from both wells are associated with high swelling potential while average cation exchange value is 40 meq/100g. Therefore, the primary cause of wellbore instability and stuck pipe within the studied intervals are attributed to high swelling and reactivity over time due to fluidformation interaction. Keywords: Clay cationic exchange, Clay swelling potential, Offshore drilling challenges, Reactive shales. African

THE EFFECTS OF DRILLING FLUID-SHALE INTERACTIONS ON WELLBORE STABILITY

1995 ◽  
Vol 35 (1) ◽  
pp. 678 ◽  
Author(s):  
C.P Tan ◽  
E.M. Zeynaly-Andabily ◽  
S.S. Rahman
Keyword(s):  
Chemical Potential ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Chemical Potential Difference ◽  
Wellbore Instability ◽  
Laboratory Techniques ◽  
In Situ Stresses ◽  
Physico Chemical ◽  
Mud Pressure

Wellbore instability, experienced mainly in shale sections, has resulted in significant drilling delays and suspension of wells in major Australian petroleum basins. These instabilities may be induced by either in-situ stresses that are high relative to the strength of the formations or physico-chemical interactions of the drilling fluid with the shales.This paper describes fundamental concepts of mud pressure penetration and flow of water between the wellbore and formation due to their chemical potential difference, and associated mud support changes as the drilling fluid interacts with shales. Due to the low permeability of shales, the penetration of the drilling fluid filtrate would result in an increase in pore pressure over a considerable distance from the wellbore. This instability mechanism strongly depends on properties of the drilling fluid filtrate and pore fluid, and the rock material composition.In addition to mud pressure penetration, water would be induced to either flow into or out of the formation depending on the relative chemical potential of the drilling fluid and the formation. A more stable wellbore condition could be achieved by optimising the chemical potential of drilling fluids.Drilling fluid and shale properties required for the models, which are determined using analytical and laboratory techniques, are presented herein. The effects of the time-dependent mechanisms on wellbore stability are demonstrated for a polyacrylamide, an ester-based and an oil-based mud. The results demonstrate that a more effective mud support can be obtained by optimising the adhesion and viscosity of the drilling fluid filtrate, and chemical potential of the drilling fluid.

Sign in / Sign up

Export Citation Format

Share Document