Drilling Fluids Optimization – A Case Study in Overcoming Drilling Challenges in Excessive Over Balanced, Loss Circulation and Wellbore Instability Environment

2020 ◽  
Author(s):  
M Solehuddin B A Razak ◽  
Sheau Hun Ong
Keyword(s):  
Drilling Fluids ◽  
Wellbore Instability

scholarly journals Experimental study of Zubair shale stability of east Baghdad oil field using different additives in water based mud

2019 ◽  
Vol 10 (3) ◽  
pp. 1215-1225
Author(s):  
Asawer A. Alwassiti ◽  
Mayssaa Ali AL-Bidry ◽  
Khalid Mohammed
Keyword(s):  
Drilling Fluid ◽  
Oil Field ◽  
Oil Fields ◽  
Drilling Fluids ◽  
Fluid Type ◽  
Wellbore Instability ◽  
Immersion Period ◽  
Shale Formation ◽  
Shale Recovery ◽  
Polymer Type

AbstractShale formation is represented as one of the challenge formations during drilling wells because it is a strong potential for wellbore instability. Zubair formation in Iraqi oil fields (East Baghdad) is located at a depth from 3044.3 to 3444 m. It is considered as one of the most problematic formations through drilling wells in East Baghdad. Most problems of Zubair shale are swelling, sloughing, caving, cementing problem and casing landing problem caused by the interaction of drilling fluid with the formation. An attempt to solve the cause of these problems has been adapted in this paper by enhancing the shale stability through adding additives to the drilling fluid. The study includes experiments by using two types of drilling fluids, API and polymer type, with five types of additives (KCl, NaCl, CaCl2, Na2SiO3 and Flodrill PAM 1040) in different concentrations (0.5, 1, 5 and 10) wt% and different immersion period (1, 24 and 72 h) hours. The effect of drilling fluids and additive salts on shale has been studied by using different techniques: (XRD, XRF, reflected and transmitted microscope) as well shale recovery. The results show that adding 10 wt% of Na2SiO3 to API drilling fluid results in a high percentage of shale recovery (78.22%), while the maximum shale recovery was (80.57%) in polymer drilling fluid type gained by adding 10 wt% of Na2SiO3.

scholarly journals Chemical Effect on Wellbore Instability of Nahr Umr Shale

2013 ◽  
Vol 2013 ◽  
pp. 1-7 ◽  
Author(s):  
Baohua Yu ◽  
Chuanliang Yan ◽  
Zhen Nie
Keyword(s):  
Drilling Fluid ◽  
Ionic Concentration ◽  
Chemical Effect ◽  
Drilling Fluids ◽  
Collapse Pressure ◽  
Wellbore Instability ◽  
Sealing Capacity ◽  
Engineering Data ◽  
Forward Engineering ◽  
Rock Mechanical Properties

Wellbore instability is one of the major problems that hamper the drilling speed in Halfaya Oilfield. Comprehensive analysis of geological and engineering data indicates that Halfaya Oilfield features fractured shale in the Nahr Umr Formation. Complex accidents such as wellbore collapse and sticking emerged frequently in this formation. Tests and theoretical analysis revealed that wellbore instability in the Halfaya Oilfield was influenced by chemical effect of fractured shale and the formation water with high ionic concentration. The influence of three types of drilling fluids on the rock mechanical properties of Nahr Umr Shale is tested, and time-dependent collapse pressure is calculated. Finally, we put forward engineering countermeasures for safety drilling in Halfaya Oilfield and point out that increasing the ionic concentration and improving the sealing capacity of the drilling fluid are the way to keep the wellbore stable.

Hollow-Glass Sphere Application in Drilling Fluids: Case Study

2015 ◽  
Author(s):  
Arminder Minhas ◽  
Brandon Friess ◽  
Farid Shirkavand ◽  
Barry Hucik ◽  
Teresa Pena-Bastidas ◽  
...  
Keyword(s):  
Glass Sphere ◽  
Drilling Fluids ◽  
Hollow Glass ◽  
Hollow Glass Sphere

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.

Bridging Agents Optimization Based on Predicting Induced Fracture Model for Deviated Wells – A Case Study

2021 ◽  
Author(s):  
Mohammad Saeed Karimi Rad ◽  
Mojtaba Kalhor Mohammadi ◽  
Kourosh Tahmasbi Nowtarki
Keyword(s):  
Size Distribution ◽  
Drilling Fluid ◽  
Average Pore Size ◽  
Drilling Fluids ◽  
Average Pore ◽  
Actual Case ◽  
Seepage Loss ◽  
Seepage Losses ◽  
Induced Fractures

Abstract Applying bridging agents to prevent seepage losses is a common practice during drilling reservoir sections which limits the invaded zone and reduces stuck pipe possibility. Unfortunately, the initial particle size distribution (PSD) design of bridging agents based on static models does not prevent actual seepage losses due to the induced fractures which have different sizes comparing to the initial reservoir pore sizes. This paper reviews an actual case study with provided solutions in an offshore field located in the Middle East which had a seepage loss circulation problem through induced fractures. It also presents analyzing natural and induced fractures size of the reservoir layer to choose optimized possible bridging agents’ PSD to cure/prevent loss circulation problems. The maximum/average pore size of formation can be measured from routine core analyses. A geological method to estimate the induced fracture widths with geo-mechanical data were used. Finally, optimum blends of bridging agents for loss circulation pills or background treatment to prevent mentioned problems were designed. Based on the laboratory testing on cores taken from previously-drilled wells in the mentioned field, the maximum size of pore throats was measured as 20 microns. Therefore, using the Ideal Packing Theory (IPT) method, the result for selecting bridging agents through pore throats (for seepage loss) indicates that optimum treatment is using of bridging agents with D50 and D90 6.5 and 16 microns, respectively. Also, for improving the treatment selection through parameters such as PSD of bridging agents, investigation on behavior of fracture growth were done. As a result, induced fracture width in studied well, with provided geo-mechanical (such as Poisson's Ratio & Young Modulus) and drilling fluid data was calculated approximately to be 230 microns through the porous medium in the near-wellbore region. Therefore, optimization for bridging these new fractures while drilling was performed again and it was concluded that optimum bridging agent size distribution at the tip of these newly-created induced fractures is applying bridging agents with D50 and D90 of 64 and 170 microns respectively, which are approximately 10 times higher than normal treatment in size. This paper describes the historical seepage circulation and related problems in the mentioned field and presents a methodology to prevent these issues by predicting induced fractures and optimizing bridging agent PSD to block them. Considering this methodology, the gap between the design and actual drilling is reduced and both rig downtime and related drilling and drilling fluids costs can be saved.

Wellbore Shielding Technique Increases Operative Window, Avoiding Formation Instability and Losses, Minimizing NPT, and Optimizing Drilling Operations in the Unconventional Plays

2021 ◽  
Author(s):  
Gaston Lopez ◽  
Gonzalo Vidal ◽  
Claus Hedegaard ◽  
Reinaldo Maldonado
Keyword(s):  
Drilling Fluid ◽  
Drilling Fluids ◽  
Wellbore Instability ◽  
Lost Circulation ◽  
Drilling Performance ◽  
Drilling Parameters ◽  
Vaca Muerta ◽  
Drilling Operations ◽  
Fracture Gradient ◽  
Vaca Muerta Formation

Abstract Losses, wellbore instability, and influxes during drillings operations in unconventional fields result from continuous reactivity to the drilling fluid causing instability in the microfractured limestone of the Quintuco Formation in Argentina. This volatile situation becomes more critical when drilling operations are navigating horizontally through the Vaca Muerta Formation, a bituminous marlstone with a higher density than the Quintuco Formation. Controlling drilling fluids invasion between the communicating microfractures and connecting pores helps to minimize seepage losses, total losses, wellbore fluid influxes, and instabilities, reducing the non-productive time (NPT) caused by these problems during drilling operations. The use of conventional sealants – like calcium carbonate, graphite, asphalt, and other bridging materials – does not guarantee problem-free drilling operations. Also, lost circulation material (LCM) is restricted because the MWD-LWD tools clearances are very narrow in these slim holes. The challenge is to generate a strong and resistant seal separating the drilling fluid and the formation. Using an ultra-low-invasion technology will increase the operative fracture gradient window, avoid fluid invasion to the formation, minimize losses, and stop the cycle of fluid invasion and instability, allowing operations to maintain the designed drilling parameters and objectives safely. The ultra-low-invasion wellbore shielding technology has been applied in various fields, resulting in significantly improved drilling efficiencies compared to offset wells. The operator has benefited from the minimization of drilling fluids costs and optimization in drilling operations, including reducing the volume of oil-based drilling fluids used per well, fewer casing sections, and fewer requirements for cementing intervals to solve lost circulation problems. This paper will discuss the design of the ultra-low-invasion technology in an oil-based drilling fluid, the strategy for determining the technical limits for application, the evaluation of the operative window with an increase in the fracture gradient, the optimized drilling performance, and reduction in costs, including the elimination of NPT caused by wellbore instability.

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