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Drilling challenges in the Mesopotamian Basin, Southern Iraq, are varied and include such issues as mud loss, bit damage, and differential sticking. This study aims to analyze these problems across the stratigraphic column in the study area. The results show that the MMD65R, EQH16R, and SF74R bits were successfully used for the 16” section, while the MSi616L bit was the most efficient for the 12¼” section. The MMD65R was suitable for the 8½” section, with the EQH12DR bit being used for the remaining parts of this section. The MMD54 bit showed excellent performance, achieving the highest rate of penetration (ROP) of 26.9 m/hr in well horizontal sections. Mud losses were most commonly observed at the base of the Dammam, Rus, Tanuma, Mishrif, Hartha, Shuaiba, and Zubair Formations. An appropriate drilling mud density is 1.28 sg is recommended for Zubair and Mishrif Formations. Additionally, tripping in/out operations must be conducted at controlled speed to prevent surging or swabbing the well. Potassium Chloride concentrations should be maintained between 3 to 5%. A 7” production liner must be run and properly seated to isolate the Mishrif and Zubair Formations, with overlap to prevent potential communication between lower water-bearing zones and shallow loss zones.

The formations in the Bayan block are complex in nature, mud losses, borehole wall collapse and pipe sticking etc. have long been problems hindering the drilling efficiency. Using laboratory methods such as X-Ray, electron microscopy and particle size analysis etc., the lithology, micromorphology and particle size distribution of the rock samples taken from the unstable section of the formations were studied. The primary cause of wellbore instability is identified as the inadequate sealing capability of the drilling fluid concerning the micro-nano fractures within the formation, which leads to fluid invasion and results in the dissolution and detachment of salt and gypsum from the Linhe Formation. To deal with these problems, a powdered rigid micrometer and nanometer resin plugging agent XNZD and a flexible high molecular weight modified paraffin XNEP were introduced into the drilling fluid to improve its plugging capacity. The self-developed XNZD plugging agent has a particle size distribution that is compatible with the fractures’ sizes of the unstable formations encountered in the Bayan block. Also introduced into the drilling fluid was a selfdeveloped amine-based compound shale inhibitor XNYZ which was used in combination with potassium formate or other organic salts to improve the inhibitive capacity of the drilling fluid. In laboratory experiment with the optimized drilling fluid on a mud loss tester with fracture size of 0.03 mm, the amount of the drilling fluid lost was reduced by 98% because of the good plugging capacity of the drilling fluid. In core expansion test, the percent linear expansion of shale cores tested with the drilling fluid was reduced by 89.2%. These experimental results indicate that the drilling fluid has good plugging capacity and inhibitive capacity, and has provided an important technical support for the high efficiency drilling in the complex formations in the Bayan Hetao block. [ABSTRACT FROM AUTHOR]

The well Yuejin-3-3XC is drilled to a measured depth of 9,432 m, with length of the horizontal section exceeding 3,400 m. This depth and length of horizontal drilling has broken the record of the longest horizontal section in the deepest and ultra-deep horizontal drilling in Asia. The well Yuejin-3-3XC penetrated formations with complex geologic characteristics, and was difficult to drill. Requirements for the properties of cement slurries are high; high temperature, high pressure, low pressure bearing capacity of the formations drilled have all to be considered to avoid losses of the cement slurries. To deal with these difficulties, three low density cement slurries, which are C-Lo PSD (1.30 g/cm³), C-Lite STONE (1.60 g/cm³ ) and C-Hi PSD (1.40 g/cm³), are formulated. These cement slurries can be used in medium-low and high temperature conditions, and have been successfully used in cementing the well Yuejin-3-3XC. Compared with the cement slurries previously used, these three new slurries have mixing efficiency, rheology, suspension stability and compressive strength of set cement that are significantly improved. Among the three cement slurries, the C-Lite STONE (TBHC = 75 ℃/TTOC = 30 ℃) and the C-Hi PSD (TBHC = 145 ℃/TTOC = 105 ℃) have the strengths of the top slurries in 48 h of 81 MPa and 14.3 MPa under the temperature differences of 45 ℃ and 40 ℃, respectively. During drilling operation, the well Yuejin-3-3XC has encountered several times of mud losses. Use the self-made new lost circulation materials C-B62 and C-B66, the fractures into which the mud was lost were successfully sealed off, ensuring the smooth progress of the cementing operation. [ABSTRACT FROM AUTHOR]

In shale gas drilling in the Fuxing area, downhole troubles, such as mud losses in the Lianggaoshan formation, coexistence of well kick and mud losses in the Dongyuemiao member of the Ziliujing formation as well as borehole wall collapse which resulted in frequent pump and top drive halt, have frequently been encountered. To solve these problems, rock samples of the Lianggaoshan formation taken from the well Xingye-L2HF and the well Xingye-1002HF as well as rock samples from the Dongyuemiao member of the Ziliujing formation are analyzed with XRD diffraction for their mineral composition. Using SEM, the micromorphology of these rock samples is analyzed. By studying the field operational data, the mechanisms of borehole wall collapse and mud losses are summarized. The oil-based drilling fluid previously used is improved based on the studies for its emulsion stability, friction reduction and plugging capacity. The new oil-based drilling fluid for the drilling operation in the Fuxing area has plugging PPA of less than 2 mL and invasion depth into the sand tube of less than 2 cm. Based on the sand blocking effect in fracturing job, a mud loss control slurry formulated with compound lost circulation material, inducing agent and suspending agent was developed. The pressure bearing capacity of the mud cakes formed by this mud loss control slurry is 7 MPa, making it suitable for controlling mud losses into formations with multiple fractures. Compared with the high density diesel oil-based drilling fluid used in drilling a well in the Fuxing area previously, this new oil-based drilling fluid has lower viscosity, lower gel strengths and higher lubricity, and the occurrence of the complex situations, such as mud losses and borehole wall instability, has significantly been reduced. [ABSTRACT FROM AUTHOR]

Drilling into fractured formations can easily lead to mud loss, which significantly affects drilling efficiency and increases drilling costs. In high-temperature and high-pressure environments, changes in mud properties render mud loss more uncontrollable. On the basis of a mud performance test in a high-temperature and high-pressure environment, and considering the time-varying characteristics of wellbore temperature and pressure and the distribution law of fracture temperature and pressure, a coupling model of temperature and pressure in the wellbore and fracture was established in this study. The developed model was solved numerically using the finite difference approximation, and the characteristics of the mud loss were analyzed. The effects of geothermal gradient, fracture parameters (fracture width, fracture length, and deformation capacity), mud properties (viscosity, yield value, and specific heat capacity), and operating conditions on mud loss were investigated. The model was validated using field measurement-while-drilling tool data of the LD1 well in the South China Sea. The results show that the average errors between the calculated temperature and pressure results of the numerical model and the actual data are 2.45% and 0.57%, respectively, which proves that the model has high accuracy in the prediction of the bottom hole temperature and pressure. A comparison of the predicted data of mud loss with the actual measured data indicates that the average error of the mud leakage model is 4.23%. This also demonstrates that the model has a high accuracy in predicting mud loss. In addition, the results show that the mud performance changes significantly under high-temperature and high-pressure conditions, which has a significant influence on mud loss. The geothermal gradient affected the mud properties and thus significantly affected the mud loss characteristics. The larger the mud pumping rate, the larger the bottomhole pressure difference and the more serious the mud loss. Blindly increasing mud viscosity is not advisable because it may lead to more serious losses. With an increase in the mud yield value, the mud flow resistance in the fractures can be significantly increased to inhibit mud loss. The larger the mud-specific heat capacity, the less mud loss is affected by the temperature. With an increase in the fracture width, the degree of mud loss gradually decreased. The larger the fracture length and deformation capacity, the more serious the mud loss. The fracture length and width could be inverted using the developed model.

The Sha-3 member V reservoir in the Gaoliu block, Nanpu sag is a typical interlayered thin sandstone and thin claystone tight reservoir with complex formation pressure systems and densely distributed artificial fractures resulted from many years of fracturing and injection operations. Horizontal drilling in this area is faced with problems such as mud losses, oil and water kicks as well as collapse of borehole walls. This paper describes, based on the formation characteristics of the Gaoliu block, the technical difficulties in horizontal drilling, and points out the causes of mud losses and borehole wall collapse. To solve these problems, an oil based drilling fluid was formulated with a nanometer/micrometer sized emulsified borehole wall collapse preventing agent, graphite microspheres, a micrometer flexible plugging agent and calcium carbonate of ultrafine particles, which render the drilling fluid capacities such as plugging, high pressure bearing and borehole wall stabilizing. The oil based drilling fluid has low filtration rate and has the ability of maintaining the strengths of the claystones that is 5 times higher than other drilling fluids. With this drilling fluid, the pressure bearing capacity of the sandstones of medium and high permeability can be increased to 18 MPa. Bridging and solidification mud loss control techniques were used to control mud losses. Using this drilling fluid, horizontal drilling through the tight reservoirs in the Gaoliu block was safely performed and no borehole wall collapse was encountered during drilling in more than ten wells. In formations where mud losses were encountered, the mud losses were controlled and the pressure bearing capacity of the formation was increased by 5.4 MPa, satisfying the requirement of subsequent drilling. [ABSTRACT FROM AUTHOR]

In the Kuche piedmont structure in the Tarim Basin where complex geological conditions prevail, frequent mud losses into the salt/gypsum formations and the target zones cause huge economic losses. To identity the types of the mud losses, a judgement model is established using the LightGBM algorithm. The LightGBM model, with good discriminative performance, has average recall rate of 85%, precision of 91% and F1-Score of 86.7%. In analyzing the types of mud losses, the interpretable machine learning techniques based on SHAP values are adopted to analyze a single mud loss event and all mud loss events as a whole. The SHAP value method, which is based on Cooperative Game Theory, breaks down the occurrence of mud loss events into contribution values of different features, and explains the effects of each feature on the mud loss event. Studies show that the main factors affecting mud losses include the difference between the mud density and the equivalent density calculated from the fracture pressure of the formation, the flow rate of mud, the well depth and the formation drilled. For the geology of the salt/gypsum formations and the target zones in the Kuche piedmont structure, the effects of the formation geology and the vertical distribution of the interlayer are in depth analyzed. This study enables the field engineers to fast and accurately determine the types of mud losses, and provides a strong support to the design of measures for preventing and controlling mud losses. [ABSTRACT FROM AUTHOR]

The well Tian-X is an exploratory well located at the Anjihai anticline (an anticline in the Huomatu anticline zone) in the south edge thrust belt in the Junggar Basin. The 6th interval (Ф139.7 mm) penetrates a long open hole section of the well with coexistence of high and low pressure zones and narrow annular clearance, and the sandstone reservoir is developed with abundant pores and has active oil and gas. The safe drilling window in this interval is only 0.02 g/cm3 , and mud losses have frequently happened during drilling. Narrow safe drilling window also causes difficulties in dynamically balancing the formation pressures and problems such as well kick and mud losses during casing running are quite prone to happen, resulting in poor cementing quality. To solve these problems, precise pressure management during casing running has been performed. Using the precise pressure management equipment, pressures at the wellhead during casing running and well cementing can be precisely controlled an the pressures at the points of mud losses an points of well kicks along the borehole were controlled in the scope of the safe window, thereby realizing pressure balance inside the wellbore. In cementing the liner string, the wellhead pressure was precisely controlled and the cement slurry returned to the designed depth in one circulation, and the cementing techniques were designed specifically to suit for the wellbore conditions. The well cementing job was performed successfully. IBC well logging interpretation shows that the job quality of the cementing section is 100% qualified, no gas channeling occurred at the bell nipple when mud density was reduced. This technology has provided a precious experience and reference significance for cementing wells with narrow drilling windows at the south edge of the Junggar Basin. [ABSTRACT FROM AUTHOR]

The block Wushi17-2 is an important part of the Nanhai West Oilfield and has significant exploration and development prospects. However, there are severe potential downhole problems encountered during drilling operations, such as borehole wall instability, mud losses and formation damage, has imposed serious challenges to the properties of drilling fluids. Since this block is located nearby a national nature reserve, the environmental friendly performance of drilling fluids remains a great challenging. To deal with these problems, this study proposes the research idea of formulating high performance synthetic based drilling fluid with gas-to-liquid (GTL), followed by optimizing with a primary emulsifier, a secondary emulsifier and a high efficiency plugging agent OSD-2, eventually formulating a synthetic based drilling fluid with a density of 1.5 g/cm³, a temperature resistance of 150 ℃, a high temperature high pressure filtration rate of less than 5 mL and an electric stability of greater than 400 V. The synthetic based drilling fluid has excellent rheology, lubricity, inhibitive capacity and resistance to clay contamination (resistant to contamination of 10% poor-quality clay). The synthetic based drilling fluid satisfied the demands of field operation and helped to solve drilling fluid-related problems during drilling process. [ABSTRACT FROM AUTHOR]

Conventional well logs cannot detect fractures in hydrocarbon reservoirs. Drilling core data are costly and this puts a significant limitation on data acquisition. The image logs, with their specific technology and by implementing electrical and sonic characteristics of the formation, can recognise various features in the borehole wall, including bedding, fracture, sedimentary structures, faults, condition of fractures, whether mineral-filled, etc. This investigation uses image logs (FMI, OBMI, and UBI) of five wells in different Iranian oil fields. The studied area is located in the central part of the northern Dezful embayment. The fracture values in each zone of the Asmari Formation of studied wells were calculated, and each zone's fracture density histogram was drawn. The maximum and the minimum number of fractures were recognised, and reservoir zones with a high production potential were defined. Mud loss and cumulative oil production data were converted to histograms and compared with fracture density histograms. The results showed that there was a good correlation between the three histograms. Based on these research results, well log image diagrams can determine the exact location and calculate the fractures density to determine the appropriate reservoir zones. [ABSTRACT FROM AUTHOR]

Mechanisms of loss of oil based drilling fluids were analyzed taking the shale oil development in the Jiyang Depression as an example to solve the frequent occurrence of mud losses in shale oil development. The analytical results have shown that natural fractures are highly developed in shale oil reservoir formations, and this is one reason why the mud is easy to lose in shale oil drilling. The shales drilled are very brittle, and their surfaces are oil wet, pressure losses in long horizontal sections are therefore high, resulting in induced fractures into which the mud is lost. Lost circulation materials (LCM) in oil based drilling fluids have low friction coefficients, making it difficult to control the mud losses. Based on the studies on the mechanisms of mud losses occurred in shale oil drilling, a one-bag lost circulation material made from a surface-modified elastic mesh material and an optimized filling material. Laboratory long-fracture sealing and plugging experiment and field application have shown that the one-bag LCM has good sealing and plugging capacity; fractures of 2 mm × 1 mm has pressure bearing capacity of 10 MPa after being plugged with the LCM. Mud losses in field operations were brought under control in the first try of the LCM. The application of the one-bag LCM helped solve the losses of oil based drilling fluids in shale oil drilling, providing a technical support to the safe and fast drilling in shale oil reservoirs. [ABSTRACT FROM AUTHOR]

Geometric analysis of fractures in calcareous reservoirs containing hydrocarbon resources is of particular importance. Knowing the location and distribution of fractures in such reservoirs can play an effective role in providing field development plans, determining suitable sites for new drilling and reducing exploration costs. This study was carried out to evaluate the relative frequency of fractures method to identify regional fractures in the Bibihakimeh oilfield. The required data have been extracted by analyzing the underground countor maps in the Bibihakimeh oilfield. Then, the accuracy of the fracture map prepared based on this method was evaluated with the relevant data of reservoir parameters in the studied oilfields. Data on mud loss, thermal gradient, overburden thickness, total organic carbon and production index confirm results obtained from the relative frequency of fractures in the center of the oilfield. Comparison of the results with the map of basement faults in the study area shows that the performance of these regional fractures has caused curvature development and fractures concentration in some parts of the Bibihakimeh oilfield. These regional fractures act as a conduit for heat transfer from the depth to the surface, which in turn has led to a sharp increase in thermal gradient and production in wells in the central parts of the studied oilfield. [ABSTRACT FROM AUTHOR]

Abstract Loss of drilling fluid commonly known as mud loss is considered as one of the critical issues during the drilling operation as it can cause severe formation damage. To minimize fluid loss, researchers introduced numerous additives but did not get the expected result. Recently, the use of nanoparticles (NPs) in drilling fluid gives a new hope to control the fluid loss. A basic KCl–Glycol–PHPA polymer-based mud is made, and six different concentrations of 0.1, 0.5, 1.0, 1.5, 2.0, 3.0 wt% iron (III) oxide or Hematite (Fe2O3) NPs are mixed with the basic mud. The experimental observations reveal that fluid loss of basic mud is 5.9 ml after 30 min and prepared nano-based drilling mud results in a less fluid loss at all concentrations. Nanoparticles with a concentration of 0.5 wt% result in a 5.1 ml fluid loss at the API LTLP filter press test. On the other hand, nanoparticles with a concentration of 3.0 wt% enhance the plastic viscosity, yield point, and 10 s gel strength by 15.0, 3.0, and 12.5%, respectively. The optimum concentration of hematite NPs is found to be 0.5 wt% which reduces the API LPLT filtrate volume and filter cake thickness by 13.6 and 40%, respectively, as well as an improvement of plastic viscosity by 10%.

Loss of drilling fluid commonly known as mud loss is considered as one of the critical issues during the drilling operation as it can cause severe formation damage. To minimize fluid loss, researchers introduced numerous additives but did not get the expected result. Recently, the use of nanoparticles (NPs) in drilling fluid gives a new hope to control the fluid loss. A basic KCl–Glycol–PHPA polymer-based mud is made, and six different concentrations of 0.1, 0.5, 1.0, 1.5, 2.0, 3.0 wt% iron (III) oxide or Hematite (Fe2O3) NPs are mixed with the basic mud. The experimental observations reveal that fluid loss of basic mud is 5.9 ml after 30 min and prepared nano-based drilling mud results in a less fluid loss at all concentrations. Nanoparticles with a concentration of 0.5 wt% result in a 5.1 ml fluid loss at the API LTLP filter press test. On the other hand, nanoparticles with a concentration of 3.0 wt% enhance the plastic viscosity, yield point, and 10 s gel strength by 15.0, 3.0, and 12.5%, respectively. The optimum concentration of hematite NPs is found to be 0.5 wt% which reduces the API LPLT filtrate volume and filter cake thickness by 13.6 and 40%, respectively, as well as an improvement of plastic viscosity by 10%. [ABSTRACT FROM AUTHOR]

Abstract The fracture gradient is a critical parameter for drilling mud weight design in the energy industry. A new method in fracture gradient prediction is proposed based on analyzing worldwide leak-off test (LOT) data in offshore drilling. Current fracture gradient prediction methods are also reviewed and compared to the proposed method. We analyze more than 200 LOT data in several offshore petroleum basins and find that the fracture gradient depends not only on the overburden stress and pore pressure, but also on the depth. The data indicate that the effective stress coefficient is higher at a shallower depth than that at a deeper depth in the shale formations. Based on this finding, a depth-dependent effective stress coefficient is proposed and applied for fracture gradient prediction. In some petroleum basins, many wells need to be drilled through long sections of salt formations to reach hydrocarbon reservoirs. The fracture gradient in salt formations is very different from that in other sedimentary rocks. Leak-off test data in the salt formations are investigated, and a fracture gradient prediction method is proposed. Case applications are examined to compare different fracture gradient methods and validate the proposed methods. The reasons why the LOT value is higher than its overburden gradient are also explained.

Abstract Lost circulation during well drilling and completion wastes productive time, and even kills the well in severe cases. Timely identifying lost circulation events and taking countermeasures has been the focus of related study. However, a real prediction of lost circulation risk before drilling would be an active response to the challenge. In this paper, a technical solution is proposed to evaluate geological lost-circulation risk in the field using 3D seismic data attributes and machine learning technique. First, four seismic attributes (variance, attenuation, sweetness, RMS amplitude) that are the most correlated with lost circulation incidents are recommended. Then a prediction model is built by conducting supervised learning that involves a majority voting algorithm. The performance of the model is illustrated by six unseen drilled wells and shows the ability and potential to forecast lost circulation probability both along well trajectory and in the region far away from the drilled wells. The prediction resolution in the lateral and vertical direction is about 25 m and 6 m (2 ms), respectively, which are distinct advantages over the traditional description of geological structures using seismic data. It shows that the lost circulation risk can be hardly recognized by interpreting one specific seismic attribute, which is a common practice. Finally, the challenges in predicting lost circulation risk using seismic data are summarized. Overall, the study suggests that machine learning would be a practical solution to predict various construction risks that are related to seismic-based geological issues. Knowing in advance the risks, people could avoid or at least minimize the losses by optimizing well deployment in the field and taking preventive measures. Graphical abstract Workflow of predicting lost circulation risk in 3D underground space using seismic data and machine learning technique. Image 1 Highlights • Regional lost circulation risk is predicted in the field by using seismic data attributes and machine learning algorithm. • Four seismic attributes (variance, attenuation, sweetness and RMS amplitude) are highly correlated with mud loss event. • The machine learning prediction allows us to take active measures to combat lost circulation before a well is drilled. [ABSTRACT FROM AUTHOR]

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The fracture gradient is a critical parameter for drilling mud weight design in the energy industry. A new method in fracture gradient prediction is proposed based on analyzing worldwide leak-off test (LOT) data in offshore drilling. Current fracture gradient prediction methods are also reviewed and compared to the proposed method. We analyze more than 200 LOT data in several offshore petroleum basins and find that the fracture gradient depends not only on the overburden stress and pore pressure, but also on the depth. The data indicate that the effective stress coefficient is higher at a shallower depth than that at a deeper depth in the shale formations. Based on this finding, a depth-dependent effective stress coefficient is proposed and applied for fracture gradient prediction. In some petroleum basins, many wells need to be drilled through long sections of salt formations to reach hydrocarbon reservoirs. The fracture gradient in salt formations is very different from that in other sedimentary rocks. Leak-off test data in the salt formations are investigated, and a fracture gradient prediction method is proposed. Case applications are examined to compare different fracture gradient methods and validate the proposed methods. The reasons why the LOT value is higher than its overburden gradient are also explained. [ABSTRACT FROM AUTHOR]

The reopening and propagation of natural closure fracture is one of the key causes of lost circulation in the fractured formation, which is directly related to safe and efficient drilling. In this paper, considering dip angle and dip direction of the fracture, the stress state on closed fracture surface near borehole is analyzed. Meanwhile, combining the critical mechanics condition of fracture reopening and propagation, a new model of the critical pressure for reopening and propagation of natural closure fracture is established based on rock mechanics theory and Linear Elastic Fracture Mechanics (LEFM), and the corresponding solution algorithm is proposed. Furthermore, the new model is utilized in investigating reopening and propagation of natural closure fracture, which intersects with the horizontal well along direction of the minimum horizontal principal stress σ h , for R1 formation of HF oilfield in the Middle East. And the stress distribution on the fracture surface and critical pressure contour is presented. The result indicates that the normal stress and shear stress on the fracture surface near the wellbore are of central symmetry. Moreover, critical pressure distribution of reopening and propagation of closed fracture is symmetrical. The critical reopening pressure of natural closure fracture of R1 formation is consistent with the actual mud loss pressure, therefore the new model is reliable. This work provides a scientific foundation for drilling fluid density design for fractured formation. It can effectively avoid drilling and completion leakage, which eventually prevents drilling problems and dwindles drilling cost, as well as offer a theoretical support for fast, safe and efficient drilling. [ABSTRACT FROM AUTHOR]

When encountered with naturally fractured formations, the knowledge of the location and the aperture of the fractures intersecting the wellbore has a strong technical and economical impacts on drilling engineering, oil production and reservoir management strategies. So far no method has been well-developed for predicting fracture aperture to optimize particle size of lost circulation materials (LCMs) based on mud loss data, which is the primary source of information retrieved from the drilling process. The typical curve in traditional analytical model, which has been the predominant tool in the assessment of fracture aperture in the past several decades, has two major deficiencies: (1) no consideration of the mechanical properties of fracture and (2) incapable of providing accurate fracture aperture in the case of fracture networks. Based on the mathematic model previously published in JPSE (Xia et al., 2015. J. Pet. Sci. Eng. 129, 254–267), this paper develops a methodology that optimizes the fracture characteristics based on recording mud loss data. The methodology poses the prediction problem as history matching, where the outer optimization shell involves the length and the aperture of the fractures intersecting the wellbore. The proposed methodology systematically integrates a Fracture Generation Module, a Mud Loss Simulator, and a Global Optimization Module. The suggested methodology is automated and accurate for field development. We end this paper with some case studies to illustrate the applicability of this methodology. [ABSTRACT FROM AUTHOR]

In drilling engineering, the knowledge and control of mud loss are significant. Previous models of mud-loss exhibit two deficiencies: (1) fracture networks were not considered and (2) the fluid flow between the fracture and the matrix was not considered. In these regards, this study adopted a Monte Carlo stochastic simulation method to construct a geological model of discrete fracture networks of naturally fractured reservoirs and then found leakage tunnels. The coupling of discrete fractures and matrix was considered to establish the mathematical model. Consideration of the mud compressibility and the yield-power-law of fluid rheology have produced a more general model compared with previous ones. The finite element method and finite difference method were selected to deduce the numerical format of the matrix and fracture. The laws of mud loss in naturally discrete fractured reservoirs can be mastered through numerical calculation based on MATLAB. A sensitivity analysis is conclusively performed to identify the most influential factors on mud loss. The current model, which is more realistic compared with previous models, was validated by application to practical projects. [ABSTRACT FROM AUTHOR]

The article presents information on theoretical framework developed for the radial flow of mud with yield-power-law (YPL) rheology used in a single isolated deformable horizontal circular fracture. It mentions that during drilling operations, borehole ballooning-breathing is used to describe reversible mud losses and gains. It reveals that the model of fracture-induced ballooning-breathing helps in mud optimization and improves the drilling in naturally fractured reservoirs.

Abstract: This paper reports the well design, drilling and completion operation as well as the coring technique applied in the CO2SINK project. Three boreholes, one injection well and two observation wells have been drilled to a total depth of about 800 m. 200 m of recovered 6” core material has been real-time analysed in a research field lab. The wells have been completed as “smart” wells, containing a variety of permanently installed down-hole sensors for the continuous monitoring of the CO2 in the reservoir. All wells were cased with stainless final casings equipped with pre-perforated sand filters in the reservoir zone and wired on the outside with fiber-optical and multi-conductor copper cables. The reservoir casing section is externally coated with a fiber-glass-resin wrap for electrical insulation. [Copyright &y& Elsevier]

In this article, polyurethanes have been selected as potential lost circulation materials (LCMs) that will be introduced in wellbores having experienced serious drilling mud losses. The chemicals will be mixed at surface, pumped downhole, let to bridge/foam and seal open fractures/channels. Different tests have been carried out to investigate better ways of mixing and handling polyurethanes before pumping. In that, prospects of slowing down polyurethane reactions by decreasing the amount of activator and adding different proportions of diesel were investigated. Testing the effect of moisture on polyurethanes also was tested. Furthermore, testing using diesel, toluene, xylene, Musol, acetone, glycol, light crude oil, Safrasol as carrier fluids was undertaken. The mixing sequence of diluents and polyurethanes also was thought of and the effect of mixing water on foaming reaction also was investigated. Placement under pressure of pumped polyurethanes also was investigated. It was revealed that pressure enhances polyurethane sealing capability. Adhesion and sealability experiments, in open fractures with apertures of 0.5 mm and 1.5 mm, also indicated that tested polyurethanes are the best candidates guaranteeing a good spreadability within open fractures. Bridging and sealing fracture apertures of up to 5 mm have been achieved with success. Sealability of even larger fracture apertures amounting to 2 inches also has been accomplished. [ABSTRACT FROM AUTHOR]

Drilling in the naturally fractured formations always encounters severe mud loss, which endangers the drilling safety. In oil & gas layers, a larger quantity of mud loss has great adverse effects on later oil and gas production. Therefore, it makes the knowledge of mud loss very important, and after that, it is instructive to control the mud loss in the oil layer. In this paper, we first consider the mud loss process using a two-phase flow model. A discrete fracture network model is employed to describe the fluid transfer between fractures and matrix pores. And different relative permeability curves and capillary pressure functions are used in matrix pores and natural fractures. The finite element method and "upwind" scheme are employed to deduce the numerical discretized formulas. The correctness of our model is verified with the published literature. Then a sensitivity analysis is performed to study the laws of mud loss in naturally fractured oil-wet formation. Compared with single-phase flow models, the mud loss rate of two-phase flow model is lower. The two-phase flow model is used to identify the most influential factors on mud loss and predict the distribution of water saturation in oil formation during the drilling process. We find that: since the pressure increase zone is much larger than the water saturation increase zone, the size of the water invasion zone is unknown in the single-phase flow model. The most important influential factors of mud loss in the oil layer are fracture connection, drilling fluid density and matrix permeability. Once the natural fractures are connected to the wellbore, the mud loss rate is much higher than that when the natural fractures are not connected to the wellbore. The capillary pressure has little effect on the mud loss. The larger the capillary pressure, and the lower the mud loss rate. The model in this paper is instructive to learn the law of mud loss and contamination range of drilling fluids in oil layers. • The mud loss process is considered as two-phase flow. • The finite element method and "upwind" scheme are employed to solve the mathematical model. • The connection between fractures and the wellbore is considered using the discrete fracture model. [ABSTRACT FROM AUTHOR]

Due to the uniqueness of deep-water shallow formations, there is no fracture system around the wellbore when borehole breathing is observed in this part of the formation. Therefore, the inducing mechanism of the opening/closing of the fracture network cannot reasonably explain this type of borehole breathing. In this study, a new mechanism of permeability-induced is proposed to explain borehole breathing, based on the fact that there is no fracture system around the well and the formation has the characteristics of high permeability and porosity. By using the stress and seepage coupling method in the porous elastic medium, a new model is established to simulate and describe permeability-induced borehole breathing. Through comparison with actual cases, this model can effectively simulate the typical characteristics of fluid loss-flow back in borehole breathing. This study also analyzed the influence of factors such as formation parameters and mud rheological parameters on the borehole breathing caused by permeability. According to the results of the study, the use of a smaller diameter wellbore and agents that can adjust related parameters (such as loss-reducing circulating material) can effectively inhibit wellbore breathing while drilling. • A new mechanism of permeability-induced is proposed to explain borehole breathing. • A novel model is established to simulate and describe the borehole breathing caused by mechanism of permeability-induced. • The typical characteristics of fluid loss and return in wellbore breathing are simulated. • Analysis of the effects of different factors on borehole breathing. [ABSTRACT FROM AUTHOR]

Mud filtration happens during an overbalanced drilling operation that causes mud invasion into pores and fractures. The productivity of a formation is significantly affected by the invasion of the mud into the near-wellbore area during the mud loss process. A considerable number of studies have evaluated mud filtration statically; however, a few studies have considered the dynamic behavior of a mud loss process during overbalanced drilling, which results in the inadequate prediction of the mud loss volume and inflicted damage to the formation. In this study, a near-wellbore simulation system (NeWSS) was designed to evaluate the dynamic mud loss behavior using dimensionless parameters and introduced correlation. In this setup, the mud was introduced into the porous media with a series of overbalanced pressure steps. The volume of the effluent fluid and pressure of the outlet ports were recorded. The results show the presence of solid limestone particles increases the performance of mud, while up to 100% mud loss is observed in the absence of solid limestone particles. The return permeability of 70–95% was achieved along the length of the well after mud circulation, which shows the invasion of mud into the formation. The filtration rate shows a decreasing trend with increasing overbalanced pressure. A series of dimensionless parameters are developed to investigate the filtration mechanism, where it is found that the mechanism of filtration is changed within the 50–100 psi of overbalanced pressure. In addition, dynamic filtration is controlled by different mechanisms, where in the early time, the filtrate rate is dependent on the mud cake creation. While the changes in thickness and permeability are not significant over time. A new correlation is developed to predict filtrate rate changes with respect to time in a series of overbalanced pressures, where the constants are a function of overbalanced pressure. The value of the dynamic mud loss coefficient is significantly decreased with increasing overbalanced pressure due to the dynamic behavior of the mud loss coefficient. The results of the images analysis technique approved that the mud cake is formed on the formation wall. • Dynamic mud loss during an overbalanced drilling is studied by designing a near-wellbore simulation system. • Different mechanisms of mud loss filtration are shown using dimensionless parameters. • A new model has been developed to predict the filtrate rate during dynamic filtration. • A new model has been proposed to predict the dynamic loss coefficient. [ABSTRACT FROM AUTHOR]

Quantitative analysis of mud losses is a direct method for prediction of fracture width, which offers a criterion for designing lost preventive materials and guides early remedial actions. This study presents a mathematical model for prediction of mud loss in naturally fractured formations in two parts. First, a mathematical model is developed considering the fracture deformation and leak-off from the fracture faces to describe the trend of mud loss in fractured formations. The fracture deformation is described as a linear function of exerted differential pressure. An explicit approximate equation is also proposed to predict the fracture width from mud loss data for yield power-law drilling fluids. Second, a mathematical model is developed, which describes mud losses in fractured formations taking into account the pressure drops in mud bank and formation fluid bank. The governing equations are solved numerically using an implicit finite difference method for the first part and an iterative method with variable time-step for the second part. The comparison of approximate equation with the complete model indicates that the predicted fracture width of the approximate equation only differs 5% from that of complete numerical model. The substantial new finding is that depending on the magnitude of leak-off coefficient, three major type-curves of mud loss can be identified. It is found that formation fluid viscosity can affect mud loss volume in early times and thinner drilling fluids tend to increase the mud losses in fractured formations. However, the ultimate mud loss volume is governed by the mud-invasion factor, which is a direct function of drilling fluid yield stress. The validity of the model is examined using published data of mud loss measurement in the Gulf of Mexico. Automatic curve-fitting technique is adapted to find the fracture width by matching the model prediction with mud loss data. The results of this study is beneficial to predict the volume of mud loss for qualitative purposes during well planning and more importantly to quantify the conductive fractures for design of effective blend of lost circulation materials. • A mathematical model is developed considering the fracture deformation and leak-off to describe the mud loss in fractures. • A mathematical model is developed which takes into account the pressure drops in the mud bank and formation fluid bank. • An approximate equation is proposed to predict the fracture width from mud loss data for yield power-law drilling fluids. [ABSTRACT FROM AUTHOR]

On account of mud loss occurred during drilling in Dengying formation in Gaomo district of Sichuan Basin, factors affecting mud loss and optimization of acid system for acidizing in Mud-damaged deep fractured carbonated formation were studied. Carbonate core plugs with a diameter of 25.4 mm and a length of 50 mm were used as experimental samples to simulate natural fractures by artificially splitting, and experiments of mud loss in fractures varying from 10 μm to 250 μm were carried out. Results showed that fractures wider than 150 μm are main channels for mud loss. As fractures widen, the volume of mud loss increases while mud damages intensify first and then relieve; when the width is 150 μm, damages reach the top rate of 95.8%. When the fracture surface become rougher, the volume of mud loss decreases; in this case, the surface roughness has less impact on mud loss with widening of fractures. Then acidizing experiments of gelled acid, divert acid, and compound acid were carried out respectively in order to optimize acidizing system. Results are as follows: when fractures are narrower than 50 μm, acidizing has poor effect since all acid can hardly break through the mud damage zone to enter fractures; fractures at the width of 50 μm–200 μm enjoy better acidizing effect, and the fracture permeability recovery rate reaches 100%~400%. Since acidizing by gelled acid caused the most obvious wormholes that were thick and deep, gelled acid shows better acidizing effect than divert acid and even compound acid. As the width of fractures wider than 200 μm increased, wormholes parallel to the direction of oil and gas seepage changed into uniform etching that was wide and shallow, thus acidizing has poorer effect. Hence, selection of acid system for acidizing of mud-damaged deep fractured carbonate formation can take reference from this study. • Acidizing experiments were carried out on mud-damaged natural fractures. • Relationships between mud loss and natural fractures' width and surface roughness were analyzed. • Width of natural fractures has great impact on acidizing effect. • Gelled acid has the best acidizing effect compared with divert acid and compound acid. [ABSTRACT FROM AUTHOR]

In carbonate reservoirs, the leakage path is complex and the law of mud loss is not clear, which brings difficulties to the implementation of plugging measures. Carbonate reservoir is a naturally fractured vuggy media. One of the key scientific problems is that the fluid mass transfer among matrix pores, natural fractures and vugs is not well understood. In this paper, a discrete fracture and discrete vug model is presented to study the law of mud loss in the naturally fractured reservoir wherein natural fractures and vugs developed. The model solved the fluid flow in the discrete fracture and vug network, consisting of 1) Darcy flow in lowly permeable rock matrix and highly permeable natural fractures; 2) free flow in macro vugs. A physically-based boundary is applied to ensure the mass continuity on interfaces between vugs and matrix pores, vugs and natural fractures. A good agreement with analytical results for Poiseuille flow in a porous/free connected media is achieved. Two numerical examples using the commercial software COMSOL provide validation of the new model. When simulating the mud loss process, we find that as soon as vugs are connected to wellbore through natural fractures, total loss is observed. The size and number of vugs play prominent roles in increasing mud loss rate and accumulated mud loss. The numerical results show that the discrete fracture and discrete vug model provides a reliable way to model realistic fluid flow in fractured vuggy porous media. The model in this paper can not only simulate the mud loss process, but also the production process of carbonate reservoirs. • A discrete fracture and discrete vug model is built. • Free flow in macro vugs is described with N–S equations. • A physically based boundary is applied to ensure the mass continuity among vugs, matrix pores and natural fractures. • The model can not only simulate the mud loss process, but also the production process of carbonate reservoirs. [ABSTRACT FROM AUTHOR]

In this paper, the effect of transverse faults on the orientation, density and fractures apertures and amount of mud loss is investigated in Asmari Formation as a major oil reservoir in Zagros folded belt zone, Iran. This carried out on three selected anticlines as the surface Kuh-e-Kamarab, and subsurface Marun and Aghajari oil fields. Subsurface data on fracture characteristics were obtained from Image logs, mud losses, and reported drilling data. These are compared with outcrop fracture characteristics gathered from fieldwork and satellite image interpretation. The results show that fracture orientations are almost identical in both outcrops and subsurface data, whereas the fractures density and aperture are different along and across the folded layers and are generally governed by their location with respect to the transverse faults. The closest sector to the faults displays the highest fracture density and greater aperture. Quantitative analysis of fractures from the Kuh-e-Kamarab Anticline indicates average fracture density almost two times greater close to the Izeh-Hendijan transverse (IZH) fault than the other parts of the fold. In the Marun and Aghajari oil fields, fracture density shows three to five times greater close to the transverse faults. Analysis of the Breakout (BO) and Drilling Induce Tensile Fractures (DITF) indicate that the directions of maximum horizontal stress (SH max) in the wells located in the bent part of the Marun field consistent with the stress state of the Mn transverse fault. Moreover, the SH max orientation of wells in the southern periclinal closure of the Aghajari Field is also affected by the IZH transverse fault. The result of Iso-mud loss maps in the oil fields reveals that the severe mud loss occurred in areas close to the transverse faults. • The effect of transverse faults on fractures density and aperture in Dezful Embayment anticlines of Zagros is presented. • Comparison of fracture characteristics of reservoir rocks show that transverse faults control borehole instability. • The transverse faults have more impact on fracture characteristics and severe mud loss than the folding and thrust faulting. • Analysis of SH max orientation in oil fields shows fractures affected by the transverse faults are stress-sensitive. [ABSTRACT FROM AUTHOR]

Borehole breathing observed while drilling naturally fractured formations was often mistakenly interpreted as the influx of formation fluid or the loss of drilling fluids. Amongst several mechanisms that were caused for borehole ballooning, the opening and closing of finite fractures played a major role in naturally fractured formations. In this study, a novel experimental setup was designed to simulate the borehole breathing under different conditions. In this experiment, the typical characteristics of borehole breathing event under different pressure conditions and rock types were studied. Additionally, the influence of three important parameters on the cumulative loss of mud caused by borehole breathing was also investigated in detail. The results show that mud circulation pressure, fracture opening pressure and rock type had important influences on the maximum loss of mud and the speed at which the borehole breathing event occurs of borehole breathing, and were the key parameters for predicting the cumulative loss of mud. Based on analysis of the results, a new parameter, breathing coefficient α b which can be used to evaluate the borehole breathing event, was proposed, and its magnitude was proportional to the severity of the borehole breathing. This study provides theoretical support for the study of borehole breathing. • A new experimental device is designed to simulate the borehole breathing events. • Experimental simulation and analysis of the process of borehole breathing event. • Analysis of the effects of different pressures and rock types on borehole breathing. • A new breathing coefficient α b is proposed for borehole breathing evaluation. [ABSTRACT FROM AUTHOR]

Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density. • Presented a new assessment of the flow of non-Newtonian drilling mud in a fractured system based on experimental data. • Explained the discrepancy between the existed models and the experiment observations. • Showed that the fracture opening/deformation has a critical impact on the pressure response. • Introduced a new analytical solution to describe the mud invasion distance in a fracture at the steady-state. [ABSTRACT FROM AUTHOR]