Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Drilling and fracturing fluids can interact with reservoir rock and cause formation damage that impedes hydrocarbon production. Tight sandstone reservoir with well-developed natural fractures has a complex pore structure where pores and pore throats have a wide range of diameters; formation damage in such type of reservoir can be complicated and severe. Reservoir rock samples with a wide range of fracture widths are tested through a multistep coreflood platform, where formation damage caused by the drilling and/or fracturing fluid is quantitatively evaluated and systematically studied. To further mitigate this damage, an acidic treating fluid is screened and evaluated using the same coreflood platform. Experimental results indicate that the drilling fluid causes the major damage, and the chosen treating fluid can enhance rock permeability both effectively and efficiently at least at the room temperature with the overburden pressure.

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Damage Mechanism of Oil-Based Drilling Fluid Flow in Seepage Channels for Fractured Tight Sandstone Gas Reservoirs

Geofluids ◽

10.1155/2019/2672695 ◽

2019 ◽

Vol 2019 ◽

pp. 1-15 ◽

Cited By ~ 1

Author(s):

Peng Xu ◽

Mingbiao Xu

Keyword(s):

Drilling Fluid ◽

Damage Control ◽

Damage Mechanism ◽

Formation Damage ◽

Drilling Fluids ◽

Gas Reservoirs ◽

Tight Sandstone ◽

Stabilization Effect ◽

Potential Damage ◽

Physical And Chemical

Oil-based drilling fluids (OBDFs) have a strong wellbore stabilization effect, but little attention has been paid to the formation damage caused by oil-based drilling fluids based on traditional knowledge, which is a problem that must be solved prior to the application of oil-based drilling fluid. For ultradeep fractured tight sandstone gas reservoirs, the reservoir damage caused by oil-based drilling fluids is worthy of additional research. In this paper, the potential damage factors of oil-based drilling fluids and fractured tight sandstone formations are analyzed theoretically and experimentally. The damage mechanism of oil-based drilling fluids for fractured tight sandstone gas reservoirs is analyzed based on the characteristics of multiphase fluids in seepage channels, the physical and chemical changes of rocks, and the rheological stability of oil-based drilling fluids. Based on the damage mechanism of oil-based drilling fluids, the key problems that must be solved during the damage control of oil-based drilling fluids are analyzed, a detailed description of formation damage characteristics is made, and how to accurately and rapidly form plugging zones is addressed. This research on damage control can provide a reference for solving the damage problems caused by oil-based drilling fluids in fractured tight sandstone gas reservoirs.

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Formation Damage Avoidance by Reducing Invasion with Sodium Silicate-Modified Water-Based Drilling Fluid

Energies ◽

10.3390/en12081485 ◽

2019 ◽

Vol 12 (8) ◽

pp. 1485 ◽

Cited By ~ 3

Author(s):

Salaheldin Elkatatny ◽

Tural Jafarov ◽

Abdulaziz Al-Majed ◽

Mohamed Mahmoud

Keyword(s):

Rheological Properties ◽

Sodium Silicate ◽

Filter Cake ◽

Drilling Fluid ◽

Formation Damage ◽

Ct Scanner ◽

Tight Sandstone ◽

Ct Number ◽

Mechanical Removal ◽

Before And After

Drilling multilateral and horizontal wells through tight gas reservoirs is a very difficult task. The drilling fluid should be designed to reduce both fluid and solid invasion into the tight formation to avoid formation damage by aqueous phase trapping. The objective of this paper is to assess the effect of sodium silicate on the drilling fluid properties such as rheological and filtration properties. Rheological properties (RPs) were measured at different temperatures while the filtration test was performed at 300 °F and 300 psi differential pressure. A retained permeability calculation was determined to confirm the prevention of solid invasion. The rheological properties results confirmed that the optimal concentration of sodium silicate (SS) was 0.075 wt.% and at the same time, the temperature has no effect on the SS optimum concentration. Using 0.075 wt.% of SS reduced the filtrate volume by 53% and decreased the filter cake thickness by 65%. After mechanical removal of the filter cake, the return permeability of the tight sandstone core was 100% confirming the prevention of solid invasion. The computer tomography (CT) scanner showed that the CT number before and after the filtration test was very close (almost the same) indicating zero solid invasion and prevention of the formation damage.

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Preventing Drilling Fluid Induced Reservoir Formation Damage

10.2118/202187-ms ◽

2021 ◽

Author(s):

Karl Ronny Klungtvedt ◽

Mahmoud Khalifeh ◽

Arild Saasen ◽

Bjørn Berglind ◽

Jan Kristian Vasshus

Keyword(s):

Filter Cake ◽

Drilling Fluid ◽

Reservoir Rock ◽

Formation Damage ◽

Fluid Loss ◽

Lost Circulation ◽

Ceramic Disc ◽

Filtration Loss ◽

Small Pore ◽

The Impact

Abstract During drilling of permeable reservoirs, drilling fluid may penetrate the formation and induce damage to the reservoir rock. Specifically, solids present in the drilling fluid may enter the formation and cause subsequent reduction in reservoir permeability in the area near the wellbore. When drilling with a water-based drilling fluid in a reservoir, various polymer-based additives are normally applied to reduce the filtration loss. These additives, such as Xanthan Gum, Poly Anionic Cellulose (PAC) and Starch may help in reducing losses to the formation in presence of small pore-throats and low differential pressures. If the pore throats exceed e.g. 20μm and differential pressures reach 500psi, these additives have little effect on reducing loss of drilling fluid to the formation and thereby little effect in preventing solids from entering the formation. Lost circulation is particularly challenging when losses occur in the reservoir section. This is because LCM treatment may create formation damages. Green et al. (SPE-185889) showed the nature of drilling fluid invasion, clean-up, and retention during reservoir formation drilling. They also showed the lack of direct relation between fluid loss and formation damage. In light of such ideas, a development of new Non-Invasive Fluid (NIF) additives was conducted. These additives were able to handle downhole pressure differences and create a preventative sealing of a permeable formation when applied into a solids-free drilling fluid. Ceramic discs of various permeability and mean pore-throat size were installed into a HTHP pressure cell. Drilling fluid was pumped through the cell and a filter cake was formed across the ceramic disc. A pressure of 500psi was applied and filtration loss was measured over a 30-minute period. Examples are herein presented showing how filter cake materials were applied into the drilling fluid and effectively sealing the permeable surface of the ceramic disc. Also, it will be shown how the filter cake was effectively removed from the discs using a breaker solution. Furthermore, a selection of experiments is presented, showing the possibility to heal lost circulation in permeable reservoirs without the presence of weighing materials, clays or drill-solids in the drilling fluid. A test was also conducted in such a way that the disc was fractured inside the test cell to investigate the impact on fluid loss.

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Assessing the Relation between Mud Components and Rheology for Loss Circulation Prevention Using Polymeric Gels: A Machine Learning Approach

Energies ◽

10.3390/en14051377 ◽

2021 ◽

Vol 14 (5) ◽

pp. 1377

Author(s):

Musaab I. Magzoub ◽

Raj Kiran ◽

Saeed Salehi ◽

Ibnelwaleed A. Hussein ◽

Mustafa S. Nasser

Keyword(s):

Machine Learning ◽

Rheological Properties ◽

Nearest Neighbor ◽

Drilling Fluid ◽

Gradient Boosting ◽

K Nearest Neighbor ◽

Wide Range ◽

Machine Learning Approach ◽

Drilling Operations

The traditional way to mitigate loss circulation in drilling operations is to use preventative and curative materials. However, it is difficult to quantify the amount of materials from every possible combination to produce customized rheological properties. In this study, machine learning (ML) is used to develop a framework to identify material composition for loss circulation applications based on the desired rheological characteristics. The relation between the rheological properties and the mud components for polyacrylamide/polyethyleneimine (PAM/PEI)-based mud is assessed experimentally. Four different ML algorithms were implemented to model the rheological data for various mud components at different concentrations and testing conditions. These four algorithms include (a) k-Nearest Neighbor, (b) Random Forest, (c) Gradient Boosting, and (d) AdaBoosting. The Gradient Boosting model showed the highest accuracy (91 and 74% for plastic and apparent viscosity, respectively), which can be further used for hydraulic calculations. Overall, the experimental study presented in this paper, together with the proposed ML-based framework, adds valuable information to the design of PAM/PEI-based mud. The ML models allowed a wide range of rheology assessments for various drilling fluid formulations with a mean accuracy of up to 91%. The case study has shown that with the appropriate combination of materials, reasonable rheological properties could be achieved to prevent loss circulation by managing the equivalent circulating density (ECD).

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Development of Digital Twins for Drilling Fluids: Local Velocities for Hole Cleaning and Rheology Monitoring

10.1115/omae2021-62987 ◽

2021 ◽

Author(s):

Mehrdad Gharib Shirangi ◽

Roger Aragall ◽

Reza Ettehadi ◽

Roland May ◽

Edward Furlong ◽

...

Keyword(s):

Machine Learning ◽

Rheological Properties ◽

Drilling Fluid ◽

Training Data ◽

Drilling Fluids ◽

Hole Cleaning ◽

Digital Twins ◽

Wide Range ◽

Drilling Operations ◽

Cuttings Bed

Abstract In this work, we present our advances to develop and apply digital twins for drilling fluids and associated wellbore phenomena during drilling operations. A drilling fluid digital twin is a series of interconnected models that incorporate the learning from the past historical data in a wide range of operational settings to determine the fluids properties in realtime operations. From several drilling fluid functionalities and operational parameters, we describe advancements to improve hole cleaning predictions and high-pressure high-temperature (HPHT) rheological properties monitoring. In the hole cleaning application, we consider the Clark and Bickham (1994) approach which requires the prediction of the local fluid velocity above the cuttings bed as a function of operating conditions. We develop accurate computational fluid dynamics (CFD) models to capture the effects of rotation, eccentricity and bed height on local fluid velocities above cuttings bed. We then run 55,000 CFD simulations for a wide range of operational settings to generate training data for machine learning. For rheology monitoring, thousands of lab experiment records are collected as training data for machine learning. In this case, the HPHT rheological properties are determined based on rheological measurement in the American Petroleum Institute (API) condition together with the fluid type and composition data. We compare the results of application of several machine learning algorithms to represent CFD simulations (for hole cleaning application) and lab experiments (for monitoring HPHT rheological properties). Rotating cross-validation method is applied to ensure accurate and robust results. In both cases, models from the Gradient Boosting and the Artificial Neural Network algorithms provided the highest accuracy (about 0.95 in terms of R-squared) for test datasets. With developments presented in this paper, the hole cleaning calculations can be performed more accurately in real-time, and the HPHT rheological properties of drilling fluids can be estimated at the rigsite before performing the lab experiments. These contributions advance digital transformation of drilling operations.

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Hydraulic fracturing stimulation techniques and formation damage mechanisms—Implications from laboratory testing of tight sandstone–proppant systems

Geochemistry ◽

10.1016/j.chemer.2010.05.016 ◽

2010 ◽

Vol 70 ◽

pp. 107-117 ◽

Cited By ~ 101

Author(s):

Andreas Reinicke ◽

Erik Rybacki ◽

Sergei Stanchits ◽

Ernst Huenges ◽

Georg Dresen

Keyword(s):

Hydraulic Fracturing ◽

Laboratory Testing ◽

Formation Damage ◽

Tight Sandstone ◽

Damage Mechanisms

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Shining a Light on the Formation Damage Bogeyman: A Case Study of Low Loadfluid Recovery and Enhanced Hydrocarbon Production in the Tight Gas Montney Formation of Western Canada

10.2118/191444-18ihft-ms ◽

2018 ◽

Cited By ~ 1

Author(s):

J. Jensen ◽

R. V. Hawkes ◽

J. Behr ◽

H. Quintero

Keyword(s):

Formation Damage ◽

Western Canada ◽

Tight Gas ◽

Hydrocarbon Production ◽

Montney Formation

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Subglacial hydrology modulates basal sliding response to climate forcing of the Antarctic ice sheet

10.5194/egusphere-egu21-14907 ◽

2021 ◽

Author(s):

Elise Kazmierczak ◽

Sainan Sun ◽

Frank Pattyn

Keyword(s):

Water Pressure ◽

Ice Sheet ◽

Effective Pressure ◽

Rcp Scenarios ◽

Overburden Pressure ◽

Antarctic Ice Sheet ◽

Surface Mass ◽

Wide Range ◽

Basal Sliding ◽

The Antarctic

Sliding laws determine to a large extent the sensitivity of the Antarctic ice sheet on centennial time scales (Pattyn, 2017, Bulthuis et al, 2019, Sun et al, 2020). Especially the contrast between linear and plastic sliding laws makes the latter far more responsive to changes at the grounding line. However, most studies neglect subglacial processes linked to those sliding laws. Subglacial hydrology may also play a role in modulating the amplitude of the reaction of marine ice sheets to forcing. Subglacial processes influence the effective pressure at the base. For a hard bed system, the latter can be defined by the ice overburden pressure minus the subglacial water pressure determined by routing of subglacial meltwater through a thin film. For soft-bed systems, the effective pressure is determined from till properties and physics. Here we investigate a wide range of subglacial processes and hydrology used in ice sheet models and implemented them in one ice sheet model (f.ETISh).&#160;The subglacial hydrology models and till deformation models are coupled to different sliding and friction laws (linear, power law, Coulomb), leading to 24 different representations. The Antarctic ice sheet model was then forced by the ISMIP6 forcing in surface mass balance and ocean temperature until 2100 for different RCP scenarios (Seroussi et al., 2020). Furthermore, to sample the intrinsic sensitivity we performed the ABUMIP experiments (Sun et al., 2020) for the full set of subglacial characteristics. &#160;Results demonstrate that the type of sliding law is the most determining factor in the sensitivity of the ice sheet, modulated by the subglacial hydrology.

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