Oil-based Mud Research Articles

Artificial Neural Networks to Predict Lost Circulation Zones at Southern Iraq Oilfield

Drilling soft and fragile areas such as (high permeable, cavernous, fractured, and sandy formations) have several problems. One of the most critical problems is the loss of drilling fluid into these formations in whole or part of the well. The loss of drilling fluid can lead to more significant and complex problems, such as pipe sticking, well kick, and closing the well. The drilling muds are relatively expensive, especially oil-based mud or those that contain special additives, so it is not economically beneficial to waste and lose these muds. Artificial neural networks (ANN) can predict drilling fluid losses before they occur based on drilling parameters data and drilling fluid properties of wells effected by lost circulation problems located in the same area. This paper developed two artificial neural network models to predict drilling fluid losses in the Dammam formation- Rumaila oil field in southern Iraq. The two models have the same topology and structure. The first model used the early stopping technique to stop the training when we get the global minimum and the second model used specific epochs to complete the training. The models could predict various types of losses with high accuracy. The accuracy of implementing R2 for the first and second models was 0.9302 and 0.9493, respectively. The early stopping technique lead to obtain a model with acceptable accuracy in a short time without relying on a specific number of epochs.

Evaluations of Polyacrylamide Water-Based Drilling Fluids for Horizontal Drilling in the Shaly Wolfcamp Formation

Summary The Permian Basin, located in southeastern New Mexico and west Texas, is treated as the largest province of oil and gas production in the United States (US). The majority of hydrocarbon production from the Permian Basin is from the Wolfcamp shaly formation. Drilling horizontal and extended reached wells is continuously increasing day after day in the Permian Basin. Oil-based mud (OBM) is used to drill these horizontal wells for enhancing shale inhibition, reducing torque and drag, and supporting thermal stability of mud rheology. Due to environmental regulation for limiting use of OBM, the petroleum industry has tried to develop water-based fluid (WBF) that approaches the performance advantages of OBM. The main objective of this research is to formulate and develop WBF by using polyacrylamide anionic friction reducer (AFR) for drilling the lateral sections of horizontal wells in the shaly Wolfcamp formation. Shale inhibition, barite sagging, lubricity, and thermal stability of the formulated WBF with AFR will be studied to evaluate the developed WBF. Laboratory experiments were conducted to develop and evaluate the performance of the formulated WBF with AFR. The shale inhibition capabilities of the developed WBF with AFR were evaluated by using zeta potential, shale dispersion test, and immersion test. The results prove the capability of the formulated WBF with AFR to prevent both shale swelling and shale dispersion. AFR limits water penetrations to shale through encapsulation. The mixing procedures of AFR with WBF affect both the thermal stability of mud rheology and shale inhibition. Adding AFR to WBF helps to suspend weighting materials and mitigate barite sag. Besides, AFR decreases torque and drag by decreasing the coefficient of friction (COF). Furthermore, AFR supports enhanced stability of mud rheology with time up to 14 days at temperatures up to 180°F. The formulated WBF with AFR can be used for enhancing shale inhibition, supporting thermal and time stability of fluid rheology, improving lubricity, and minimizing barite sagging for drilling shaly Wolfcamp formations. This study presents a promising WBF to replace OBM to drill lateral sections in the Permian Basin.

Fatty Alcohol Polyoxyethylene Ether Sodium Sulfate–Modified Cement to Improve the Bonding and Sealing of Cement to Oil-Wet Casing or Formation Surface in Shale Gas Wells

Summary In shale gas wells, oil-based mud (OBM) changes the casing and rock surface wettability during drilling. It negatively affects the bonding and sealing of cement sheaths with casing or formation rock. Although the spacer is widely used in primary cementing, the casing and formation rock surface are wetted by OBM or oil phase due to poor displacement. For this work, a novel oleophilic cement slurry modified by fatty alcohol polyoxyethylene ether sodium sulfate (AES) was investigated to decrease the negative effect of OBM- or oil-wetted surface. The contact angle of nonpolar solvent 1-bromonaphthalene on the cement surface decreased from 35° to 8°, showing an ideal oleophilic property. The hydraulic isolation capacity; microstructure of the cement-casing or cement-rock interface; and the pore structure, hydration, and mechanical property of AES-modified cement were investigated by interfacial hydraulic isolation test device, computed tomography (CT), mercury intrusion porosimetry (MIP), X-ray diffraction (XRD), thermogravimetric analyses (TGAs), and mechanical test. The results showed that the oleophilic cement could directly bond with an oil- or OBM-wetted surface and significantly eliminate the microchannel and connected pores caused by the oil phase or OBM on the interface. The fluid channeling on the OBM-wetted cement-rock and casing interface was prevented, and the sealing pressure of the interface was increased from approximately 3 to 7 MPa/m (fluid channeling occurred) to higher than 275 MPa/s (fluid channeling did not occur), respectively. Besides, the hydration degree, porosity, and mechanical property of the oleophilic cement remained at the same level as the conventional cement, indicating that the AES has no adverse effect on cement hydration and properties. The findings of this study can contribute to the cement slurry design in shale gas well cementing to improve the interface bonding and sealing when poor displacement happens.

Surface-Modified Graphite Nanoplatelets to Limit Deteriorative Impacts of Oil-Based Mud Residuals on Cement Bonding

Summary Successful cementing relies on the effective removal of oil-based muds (OBMs), especially from rock and casing surfaces. However, most OBMs are heavily absorbed onto the mineral surfaces as well as casing, deteriorating the interfacial bonding of cement to these surfaces. We present a novel cement additive using graphite nanoplatelets (GNPs) to minimize the impact of mud residuals on the bonding strengths of cement. To benefit from the individual superior mechanical properties of GNPs, we develop surface modification techniques to modify their surface properties and make them compatible with the aqueous medium of cement. Surface treatment of GNPs is critical to provide a uniform dispersion of them within the cementitious matrix and also create a strong interfacial bonding between them and cement hydrates. A series of push-out tests are conducted to evaluate how the addition of surface-modified GNPs affects the bonding strength at the cement/rock interfaces corresponding to different scenarios of OBM residues. The effect of different kinds of rocks, including sandstone, limestone, and shale, is also incorporated in the push-out tests. The experimental results show that after spacer flushing for the cases of limestone and sandstone cores, treated GNPs not only limit the impact of mud residuals at the interfaces but also raise the bonding strength beyond that corresponding to water saturated cores by about 357% and 194%, respectively. For the case of shale after spacer flushing, the bonding strength recovers about 70% as compared to the water saturated cores, and this strength is about 429% higher than that measured for the water saturated case when cement is plain (without surface-modified GNPs).

Fully transient coupled prediction model of wellbore temperature and pressure for multi-phase flow during underbalanced drilling

Considering gas-liquid-solid three-phase flow and heat transfer, the accurate simulation of wellbore temperature and pressure profile while underbalanced drilling (UBD) has been predicted significantly in deep well drilling. Firstly, the research presents a fully transient coupled prediction model of wellbore temperature and pressure field and the thermophysical properties of circulating fluid are taken into consideration, and a double-cycle iterative algorithm for the axial and radial coupled solution of wellbore temperature and pressure is proposed. The model is discretized by using the finite volume method and is verified by the two-phase flow temperature and pressure data from the Louisiana full-size experiments. Then, qualitatively and quantitatively comparisons with water-based mud (WBM) and oil-based mud (OBM) to analyze the coupled variation of transient wellbore temperature and pressure. The sensitivity analysis between WBM and OBM is carried out and WBM is more sensitive to the thermophysical properties compared with OBM. Finally, the feasibility study of calculating bottom-hole pressure according to simple linear temperature is launched. It is found that the average of formation temperature and linear cyclic temperature (AFLT) model that a simplification of the temperature model due to the approximate method is more accurate and convenient between WBM and OBM. This research on wellbore temperature and pressure profile intuitively understands the complex problems of wellbore multi-phase flow, and further provides a theoretical reference for controlling well kick and extending to horizontal, highly deviated well and geothermal wells.

First Hexa-Combo Logging-While-Drilling Run in Kuwait: A Case Study

Directional wells through the 6-in. production-hole sections in the Marrat Reservoir of the Jurassic formations have traditionally required several wireline-logging and hole-conditioning runs for comprehensive petrophysical interpretation and completion design. As the planned well inclinations increase to maximize reservoir exposure and sweep efficiency, wireline deployment poses significant challenges due to the increased risk of losing the bottomhole assembly (BHA) in the hole. Over time, logging-while-drilling (LWD) tools have become preferable for the asset team, where the tools are run either in the drilling BHA or during a dedicated wiper trip after the section has been drilled to total depth (TD). Using LWD tools in this application also reduces well delivery times and costs. A comprehensive logging solution was required to drill the 6-in. reservoir section of a study well. The complex LWD string, consisting of gamma ray, resistivity, neutron porosity, azimuthal density, azimuthal sonic, and nuclear magnetic resonance (NMR) tools, was deployed on a motorized rotary steerable system (MRSS) BHA. In addition, a prototype high-resolution acoustic imaging and caliper tool, designed to be run in both water-based mud (WBM) and oil-based mud (OBM), was also included. The acquired logging data were used for enhanced formation evaluation. Fracture and borehole breakout interpretation from the image data played a key role in the successful completion design. This ultimately led to Kuwait’s first successful “hexa-combo” LWD drilling run and the country’s first LWD ultrasonic imaging tool run in OBM in this hole size, with 13.3 ppg OBM with a maximum downhole temperature of 275°F.

Toxicological and Genotoxic Effects of Used Drilling Fluid: Histopathology and Genotoxicity Assessment

During the process of extracting crude oil from the subsurface of the earth, drilling fluids play a crucial role. To evaluate the toxic and genotoxic characteristics of used oil-based drilling fluid, experiments were conducted using Clarias gariepinus (a type of fish) and Allium cepa (an onion). Prior to the experiments, the test subjects were acclimatized and stored for a period of 14 days. Following acclimatization and storage, test solutions were prepared in different concentrations based on the results of a range-finding test. After 96 hours of exposure, the LC50 values for the drilling fluid were determined as follows: 71.589% at 24 hours, 96.052% at 48 hours, 96.052% at 72 hours, and 59.508% at 96 hours. The mortality rate was recorded, revealing a direct relationship between the concentration of the drilling fluid and the mortality of the test subjects. The EC50 values also indicated a correlation between root tip-growth inhibition and increased toxicant concentration. Furthermore, histopathological studies conducted on the gills and livers of Clarias gariepinus after 96 hours of exposure revealed noticeable alterations. To analyze the content of polycyclic aromatic hydrocarbons (PAHs) present in the oil-based drilling mud, substances such as Naphthalene, Acenaphthylene, Acenaphthene, Fluorene, Phenathrene, Anthracene, Fluoranthene, Benzo (K), Pyrene, Benz (a) anthracene, Chrysene, Benzo (b) fluoranthene, Benzo (k) fluoranthene, Benzo (a) pyrene, Indeno (1,2,3-cd) pyrene, Dibenz (a,h), anthracene, and Benzo (g,h,i) perylene were analyzed using GC-MS mode S4 = 71096. These parameters are believed to be responsible for the toxic effects observed in fish and onion root tips. Considering the toxic effects and alterations observed, it is crucial to closely monitor the disposal of drilling fluids after the recovery of crude oil. Compliance with the necessary regulatory standards established by regulatory bodies should be ensured to prevent adverse environmental impacts.

Method development for in-situ radiological characterization of oil-based mud originating from oil industry

Method development for in-situ radiological characterization of oil-based mud originating from oil industry

Artificial Intelligent Models for Detection and Prediction of Lost Circulation Events: A Review

Lost circulation or losses in drilling fluid is one of the most important problems in the oil and gas industry, and it appeared at the beginning of this industry, which caused many problems during the drilling process, which may lead to closing the well and stopping the drilling process. The drilling muds are relatively expensive, especially the muds that contain oil-based mud or that contain special additives, so it is not economically beneficial to waste and lose these muds. The treatment of drilling fluid losses is also somewhat expensive as a result of the wasted time that it caused, as well as the high cost of materials used in the treatment such as heavy materials, cement, and others. The best way to deal with drilling fluid losses is to prevent them. Drilling fluid loss is a complex problem that is difficult to predict using simple and traditional methods. Artificial intelligence represents a modern and accurate technology for solving complex problems such as drilling fluid loss. Artificial intelligence through supervised machine learning provides the possibility of predicting these losses before they occur based on field data such as drilling fluid properties, drilling parameters, rock properties, and geomechanical parameters that are related to the loss of circulation of the wells suffered from losses problem located in the same area. In this paper, several supervised machine learning models have been reviewed that were used for detecting and predicting of loss of drilling fluids during the drilling process. The paper provides an inclusive review of drilling fluid prediction and detection from simplest to more complected intelligent models.

Study on the Influence of Tripping Operation on Annular Transient Surge-Swab Pressure of Herschel–Bulkley Fluid

Abstract The accurate prediction of transient surge-swab pressure, during the tripping operation under a narrow pressure window, is an important premise to ensure the safety of tripping operation and drilling. Different rheological modes of drilling fluid will have a great influence on the surge-swab pressure in wellbore, while the Herschel–Bulkley mode can simulate the rheological characteristics of actual drilling fluid in a better way. Therefore, the influence of drilling fluid flow friction under different rheological modes was mainly considered according to the transient flow model. Meanwhile, the influence of pumpage on transient surge-swab pressure during tripping operation was also considered with Herschel–Bulkley fluid-based tripping operation bottomhole transient surge-swab pressure calculation model established and model verification carried out. The following research results were obtained. First, compared with the Herschel–Bulkley mode, the power-law mode and Bingham mode will overestimate the flow friction of drilling fluid. Second, the surge-swab pressure peak values of different mud systems are water-based mud > polymer mud > oil-based mud. Third, the peak value of bottomhole transient surge-swab pressure increases with the increase of drilling fluid yield value, consistency coefficient, and flow behavior index, and the influence law is similar. Fourth, the tripping velocity and pumpage will directly affect the peak value and variation rule of bottomhole transient surge-swab pressure. Herschel–Bulkley fluid-based tripping operation bottomhole transient surge-swab pressure study helps control the surge-swab pressure during tripping operations and it is of great significance for lean, safe, and efficient drilling in narrow pressure window formations.

SVR-based weighted processing method for electrical imaging logging in oil-based mud

Electrical imaging logging in high-resistivity oil-based mud (OBM) has been one of the hotspots in petroleum exploration and development recently. Compared with the traditional electrical imaging logging in water-based mud (WBM), the core issue restricting the application of electrical imaging logging in OBM is that the mud-layer with high impedance prevents the emitted current from flowing into the formation and seriously disturbs the measurement of formation properties. Here, a SVR (support vector machine regression)-based weighted processing method is proposed to resolve the intractable problem and three key parameters are obtained simultaneously. First, the equivalent circuit model of electrical imaging logging in OBM is established and the drawback especially occurring in low-resistivity formation is analyzed. Then, a weighted coefficient applied to the mud-layer impedance is introduced for the quantitative calculation of formation resistivity, and the change of relative formation permittivity and mud-layer thickness can also be depicted with weighted processing. Next, a SVR model is established to inverse the weighted coefficient and then figure out the inversed parameters including the formation resistivity, the relative formation permittivity, and the mud-layer thickness. A stochastic parameter model is adopted to verify the validity of SVR model. Finally, two deviated formation models further test the advantage and robustness of SVR model. The results demonstrate that the SVR-based weighted processing method possesses a terrific performance and all the three parameters can be calculated simultaneously regardless of the borehole wall condition. This study will provide a new approach to the data processing and interpretation of electrical imaging logging in OBM.

Integrated Approach Determines Formation-Water Salinity

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22548, “Integrated Approach for Formation-Water-Salinity Determination,” by Tariq Alshaikhmubarak, SPE, and Laila Mira, SPE, Saudi Aramco, and Sherif Ghadiry, Schlumberger, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ In the complete paper, two methodologies are tested to achieve measurement of formation-water salinity. First, a novel dry-weight chlorine (DWCL) measurement from an advanced spectroscopy tool is used to estimate the formation salinity at the depth of investigation of the device. The second methodology uses a new downhole induction resistivity cell in the formation-tester tool. The chlorine measurement, along with the flowline-induction-resistivity measurement, helps enhance the quality of saturation evaluation for quick decision making during logging operations and acceleration of evaluation studies instead of waiting on laboratory results. Chlorine Work Flow The ability to quantify chlorine concentration can help derive formation salinity as a continuous curve. Because chlorine has a large capture cross section, it is possible to extract it from capture gamma ray spectra with acceptable uncertainty, but the real challenge is to split the total chlorine signal seen by the tool into formation chlorine signal and borehole contribution. The chlorine signal split is a fundamental step in this work flow, outlined in Fig. 1. Once the chlorine concentration in the formation is obtained—expressed as DWCL—several petrophysical applications are enabled. The first is computation of water volume assuming a known formation-water salinity. The second is computation of the sodium chloride (NaCl) equivalent salinity from an independent volume of water and DWCL. Finally, one can solve for the NaCl equivalent water salinity. Equations to achieve these steps are provided in the complete paper. Interpretation Considerations Capture spectroscopy measurements have a shallow depth of investigation (DOI) in the range of 8–10 in., which means sensitivity to mud-filtrate invasion in the volume of rock probed by the tool. The mud-filtrate invasion is controlled by several factors, including mud overbalance, formation exposure time to mud, formation porosity and permeability, and mudcake-formation process and efficiency. These factors must be considered when using the chlorine work flow to assess the effect of the invading water-based-mud (WBM) filtrate, which normally has a different salinity than the formation water. The main effect of oil-based-mud (OBM) filtrate invasion, assuming that only the oil phase is invading the formation, is a reduction of water volume at the measurement DOI, degrading the statistical precision of the DWCL and increasing the uncertainty in the computed salinity.

Comparison between double caliper, imaging logs, and array sonic log for determining the in-situ stress direction: A case study from the ultra-deep fractured tight sandstone reservoirs, the Cretaceous Bashijiqike Formation in Keshen8 region of Kuqa depression, Tarim Basin, China

The tight sandstone in the Tarim Basin has the characteristics of large burial depth and development of nature fractures due to concentrated in-situ stress. Identifying the present-day in-situ stress orientation is important in hydrocarbon exploration and development, but also a key scientific question in understanding naturally fractured reservoirs. This paper presents a case study where we integrate various methods using wireline and image-log data, to identify present-day in-situ stress direction of ultra-deep fractured tight sandstone reservoirs, in the Kuqa depression. We discuss the formation mechanism of the elliptical borehole, compares the advantages and applicable conditions of the double caliper method, resistivity image logs and array sonic logs method. The well borehole diameter is measured orthogonally, then the ellipse is fitted, and the in-situ stress orientation is identified by the azimuth of the short-axis borehole, but it fails in the borehole expansion section, the fracture development section and the borehole collapse section. The micro-resistivity image logs method reveals the borehole breakouts azimuth, and also the strike of induced fractures, which are used to determine the orientation of in-situ stress. However, under water-based mud conditions, it's hard to distinguish natural fractures from induced fractures by image logs. Under oil-based mud conditions, the induced fractures are difficult to identify due to the compromised image quality. As for the sonic log, shear waves will split when passing through an anisotropic formation, shear waves will split during propagation, and the azimuth of fast shear waves is consistent with the orientation of in-situ stress. However, it is usually affected by the anisotropy caused by the excessively fast rotation of the well log tools, so that the azimuth of fast shear wave cannot effectively reflect the orientation of the in-situ stress. Based on comprehensive assessment and comparison, in this paper we propose a method integrating various logging data to identify the orientation of in-situ stress. Among various types of logging data, the breakouts azimuth identified by image logs is proved to be the most credible in identifying the orientation of in-situ stress, while using the direction of induced fractures under water-based mud conditions is also viable. However, the azimuth of the fast shear wave is consistent with the orientation of maximum in-situ stress only when the rotation speed of the logging tool is low. The caliper method can be used as a reference for verifying the other two methods. Using this integrated method to study the orientation of in-situ stress in the Keshen 8 trap, the results show that faults are an important factor affecting the direction of in-situ stress, while multi-level faults will produce superimposed effects that cause the current direction of in-situ stress to change.

Lost Circulation Prediction Using Decision Tree, Random Forest, and Extra Trees Algorithms for an Iraqi Oil Field

Drilling soft and fragile areas such as high permeable, cavernous, fractured, and sandy formations are often accompanied by many problems. One of the most important of these problems is the loss of drilling fluid into these formations in whole or in part. The loss of drilling fluid can lead to bigger and more complex problems, including pipe stucking or kicking and finally closing the well. The drilling muds are relatively expensive, especially the muds that contain oil-based mud or that contain special additives, so it is not economically beneficial to waste and lose these muds. The treatment of drilling fluid losses is also somewhat expensive as a result of the wasted time that it caused, as well as the high cost of materials used in the treatment such as heavy materials, cement, and others. The best way to deal with drilling fluid losses is to prevent them. Artificial intelligence through supervised machine learning provides the possibility of predicting these losses before they occur based on equivalent circulating density, yield point, plastic viscosity, rate of penetration, flow rate, and losses rate of wells suffered from losses problem located in the same area. In this paper, three supervised machine learning models, namely, decision tree, random forest, and extra trees, were built to predict drilling fluid losses in the Rumaila oil field in southern Iraq. The results show that the extra trees model with an R2 of 0.9681was able to predict the new lost circulation events with high accuracy.

Evaluation of the Rheological Properties of Raphia Sese Oil Based Mud (Ester Oil) for Oil Field Drilling Applications

Purpose: The environmental challenges posed by oil-based drilling fluids along with legislation associated with their use have necessitated the development of synthetic organic liquids that are able to both meet the technical and environmental requirements of the industry. In this regard, an environmentally friendly vegetable oil-based mud from Raphia Sese oil (ester oil) was formulated and its rheological properties and economics abilities analyzed.
 Methodology: The rheological properties of the mud such as plastic viscosity, yield point, flow index, apparent viscosity, consistency index, dial readings, density, and pH were evaluated at unaged conditions from 80 oF to 200 oF.
 Findings: The results showed that Raphia sese oil base mud was compatible with the conventional oilfield additives. Though its mud naturally recorded a low pH (8.3) due to the low pH of the Raphia sese oil (5.53), with improved extraction process and with the addition of pH additives, this could be enhanced. When compared with diesel-based mud, the Raphia sese based oil mud recorded higher density values and promising rheological properties. Though the initial cost of conditioning Raphia sese oil for mud formulation purposes was high, it was offset by its disposal cost as compared to that of diesel oil (saves about 34% the cost of using diesel).
 Recommendation: From the findings, it is recommended that the recovery process of the Raphia sese oil as well as its thermal oxidation stability should be improved. Again, higher thermal conditioning testing must be done to ascertain the stability of the Raphia sese oil at higher temperatures. Also, the Congolese nation could consider the domestication of the Raphia sese palm to increase the production of its oil and the nation could go into the improved cultivation to promote local content and participation policy of the oil.

Composition and Origin of Surface Casing Fluids in a Major US Oil- and Gas-Producing Region.

Fluids leaked from oil and gas wells often originate from their surface casing─a steel pipe installed beneath the deepest underlying source of potable groundwater that serves as the final barrier around the well system. In this study, we analyze a regulatory dataset of surface casing geochemical samples collected from 2573 wells in northeastern Colorado─the only known publicly available dataset of its kind. Thermogenic gas was present in the surface casings of 96.2% of wells with gas samples. Regulatory records indicate that 73.3% of these wells were constructed to isolate the formation from which the gas originated with cement. This suggests that gas migration into the surface casing annulus predominantly occurs through compromised barriers (e.g., steel casings or cement seals), indicative of extensive integrity issues in the region. Water was collected from 22.6% of sampled surface casings. Benzene, toluene, ethylbenzene, and xylenes were detected in 99.7% of surface casing water samples tested for these compounds, which may be due to the presence of leaked oil, natural gas condensate, or oil-based drilling mud. Our findings demonstrate the value of incorporating surface casing geochemical analysis in well integrity monitoring programs to identify integrity issues and focus leak mitigation efforts.

Experimental investigation of the cementation and tensile properties of cement to formation interface considering surface irregularity and drilling mud residue

Cement sheath is an annular structure situated between casing and formation, which is designed to seal the formation and reinforce the borehole. However, owing to the surface irregularity and drilling mud residue, the interface between the cement sheath and the formation is one of the weakest parts for fluid leakage causing well integrity issues, which would also affect the reliability of the cement bond logs. To evaluate the cementation state and tensile properties of the cement-formation interface, rock-cement composite disc specimens are prepared, considering key factors such as lithology, interface irregularity, treatment of oil-based drilling mud contamination, and flushing fluid washing. Flushing efficiency of the drilling mud contaminated rock surface, interface cementation characteristic, referenced tensile strength, and tensile fracture morphology are acquired and analysed comparatively. Results show that (1) the flushing efficiencies of shale and sandstone are 74.1 ~ 61.9% and 52.4 ~ 28.4%, respectively, decreasing with the increase in surface irregularity. (2) The rock-cement interface gradually becomes poorly cemented as the surface cleanliness decreasing and the irregularity increasing. (3) Under the condition of drilling fluid contamination, there exists a transitional area at the cemented interface, where microcracks and pores are developed. (4) With the influence of drilling mud contamination, the referenced tensile strengths of shale-cement and sandstone-cement interfaces drop from 2.716 to 0.586 MPa and from 2.840 to 0.007 MPa, respectively. The effects of underground temperature and pressure environment are not particularly considered in this study and would be investigated systematically in future research.

Effect of low OBM contamination on long-term integrity of API class H cement slurries – Experimental study

Drilling mud acts as an important primary barrier during the well construction phase, while the integrity of cement sheath is critical throughout the life cycle of the well. The mud-spacer-cement interactions highly affect the long-term integrity of the cement sheath and in other words the well integrity. Even today, the spacers are not capable of displacing all the drilling mud present in the wellbore before performing cementing operations and the cement slurry is contaminated with a small amount of drilling fluid and/or spacers. Oil based mud (OBM) is highly preferred over water-based mud (WBM) as a drilling fluid when drilling in challenging environments, but with current push for more environmentally drilling fluids the Water Base Muds (WBM) are preferred.The detrimental effects of high OBM contamination (>5%) on the mechanical and rheological properties of API Cement slurries have been fairly studied in the previous decade. This study focuses on the strength development of low OBM contaminated (0.8%, 1.6%, 3.2%, 6.3%) API Class H cement slurries cured for up to 28 days at ambient temperature as well as the elevated temperature of 75 °C. The Ultrasonic Pulse Velocity (UPV) was measured by performing the non-destructive tests before performing the destructive tests which measure the actual Unconfined Compressive Strength (UCS). Based on the 141 samples tested in this study, even for 0.8% OBM contamination the strength of Class H cement samples cured for 7 days at 75 °C was reduced by 23%, and for 3.2% OBM contamination it was reduced by 39%. Novel correlations of UCS vs time and UCS vs UPV were developed to accurately simulate the downhole conditions and predict the long-term integrity of the wellbore cement. A reliable dataset for developing cement data repositories was established which also can be merged with existing databases.

Rheological studies and numerical investigation of barite sag potential of drilling fluids with thermochemical fluid additive using computational fluid dynamics (CFD)

The growing advancement in drilling technology had necessitated the development of self-destructive mud cake, which is composed of encapsulated thermochemical fluids (TCF) to facilitate dissolution of filter cake. However, segregation of weighting component, commonly the Barite particles, can lead to various operational problems that should be avoided. In this investigation, the segregation potential of Barite particles (“Barite Sag”) in drilling fluids has been investigated. The experimental data from rheological studies have been employed to guide CFD modeling and simulation of multiphase flow of a dense suspension mimicking the conventional oil-based mud (OBM), water-based mud (WBM), and those comprises thermochemical additives viz. OBM_TCF and WBM_TCF. The results revealed that the drillings fluids conform to the shear thinning pseudoplastic behavior within the conditions operated in this study. Notably, the apparent viscosity of the WBM was observed to decrease with increasing temperature between 25 and 50 °C but increased afterwards. Evaluation of gravitational settling characteristics revealed that the conventional OBM might have lower sagging potential, at lower temperature, compared with the conventional WBM, due to higher settling velocity of Barite particles in the later. In comparison, at higher temperature, which corresponds to the conditions of the newly formulated muds (i.e., the OBM_TCF and WBM_TCF), it was found that the WBM_TCF exhibit lower potential for Barite sag due to lower settling velocity of the particles compared with that of OBM_TCF. The reason essentially has to do with higher viscosity of the WBM_TCF. The CFD studies have considered both the hydrodynamic forces and shear induced migration of the particles. Analyses of various simulation results including particle flux, particle mass fraction, mixture viscosity, and the pressure drop, consistently revealed that the WBM_TCF might have lower Barite segregation potentials compared with other types of drilling fluids considered in this study.

Influence Laws for Hydraulic Sealing Capacity in Shale Gas Well Cementing

SummaryEnsuring the sealing integrity of cement sheaths used for shale gas wells during hydraulic fracturing processes has become a major challenge. The sustained casing pressure, strong temperature difference stress, and cyclic loading and unloading affect the safe long-term production of shale gas wells. In this paper, we propose a new hydraulic sealing capacity (HSC) evaluation system for cementing interfaces. Specifically, this study aimed at understanding the influence law and failure mechanism of the interface sealing of shale gas wells before hydraulic fracturing. The results showed that the HSC improved with an increase in the flushing time and velocity. The HSC of the cement-formation interface was likely to be compromised if the cement slurry was contaminated with a spacer and oil-based mud (OBM). When the cement slurry was mixed with more than 10% OBM, channels formed easily in the cement sheath body. Moreover, the preflush injection sequence of “flushing fluid + spacer + flushing fluid” significantly improved the HSC of the cement-formation interface. Based on the experimental results and field operation experience, we determined that the optimal flushing time and flushing displacement were 15–20 minutes and 1.8 m3/min, respectively. Finally, the microstructure and distribution characteristics of the cement-formation interface under different conditions were obtained by computed tomography (CT) analysis, which explains the formation and failure mechanism of the cement-formation interface HSC. The development of harmful pores (R > 1 mm) was the main factor affecting the HSC of the cement-formation interface. The number of harmful pores in cement-formation interface increased significantly after being polluted by OBM. Combined with the field operation experience, the prefluid injection sequence of “6 m3 flushing fluid + 25 m3 spacer fluid + 6 m3 fresh water” is adopted, and the displacement volume is 1.4–1.6 m3/min, and the cement slurry is injected 10–15 m3 more, which can greatly improve the HSC of the cement-formation interface. Our findings highlight the need for more explicit considerations regarding the impact of cementing technology and actual operation on the HSC of an interface under the requirements of efficient production and extended well life.