An effective drilling operation relies substantially on a reliable drilling fluid system, significantly impacting its success. Drilling fluids, particularly reservoir drill-in fluids (RDF), are crucial for minimizing formation damage and maximizing output. As soon as the reservoir is drilled, formation deterioration starts; thus, an optimized RDF with minimal harm is essential considering geology, reservoir fluids, and other factors. This study aims to improve reservoir drilling fluid to minimize skin damage by comparing nanoparticle-based RDFs with conventional drilling fluids used in the Mishrif formation, drilled horizontally 3000 meters. Employing nanoparticles in drilling fluids can improve performance and thermal resistance up to 300°F. Laboratory tests and field data were compared in this study. Nanoparticles in both freshwater and saltwater drilling fluids showed significant enhancements in filtration parameters and rheological qualities. Results indicated that the RDF with Fe2O3 nanoparticles enhanced filtration properties and stability. Optimal Fe2O3 concentrations were 1g at 300°F and 1.5g at 400°F. Adding Fe2O3 nanoparticles to reservoir drilling fluid resulted in a 40% reduction in fluid loss rate and decreased mud cake thickness. Additionally, nanoparticles improved the flow properties of the drilling fluid at high temperatures up to 200°F, ensuring a controlled and more consistent decrease in parameters such as plastic viscosity (PV), yield point (YP), and gel strength without any indication of thermal deterioration.

This research paper uses pipesim software to reproduce and evaluate well performance, comparing vertical and horizontal wells using hydraulic fracturing. It examines the impact of key parameters, such as fracture length, width, permeability, and fracture number, on production improvement. In low-permeability reservoirs, simulation studies indicate that horizontal wells often achieve higher production rates than vertical wells, largely due to improved reservoir and fracture connectivity. Productivity in the vertical well increased to 300(stb/d), while in the horizontal well, it increased to over 9,000 (stb/d) after using hydraulic fracturing. The results indicate that fracture width has less of an impact on the performance of vertical wells than horizontal wells, although fracture length and fracture number significantly influence horizontal well productivity. This disparity underscores the need for strategic fracture design and well selection to optimize oil production under changing reservoir conditions. The research paper emphasizes the need to use advanced modeling tools such as PIPESIM to accurately predict well performance and guide decision-making in hydraulic fracturing operations. Tailor-made fracturing techniques based on reservoir properties can significantly enhance continuous production efficiency and extend well life.

In recent years, the Eridu oil field has emerged as a key player in the petroleum industry in southern Iraq as it is the biggest Iraqi oil discovery in 20 years. Extending along a vast area of 5806 km2, the field has commercial oil reserves in formations such as Mishrif, Nahr Umr, Zubair, and Yamama. However, drilling operations in this field have faced significant challenges, including delays and suspensions caused by wellbore instability. One of the main obstacles encountered during drilling operations in the Eridu oil field is the occurrence of partial losses in weak vugs dolomite formations, as well as issues related to sever borehole instabilities such as drilling in tight holes, caving, and breakout due to shear failure in the borehole wall. To address these challenges, a 1 D Geomechanical model (1-D MEM) was constructed using data from vertical wells to better understand the underlying causes of drilling problems. The findings of the 1-D MEM, particularly in relation to mechanical rock properties, rock Elasticity factors, pore pressure, and fracture gradient complex formations like Tanuma and Mishrif, were instrumented in planning drilling operations for inclined and highly deviated wells. By utilizing open hole well logging data and calibrating the model with various resources of data including drilling observations, core mechanical analyses, and pore pressure measurements, a more accurate assessment of wellbore instabilities was achieved. The analysis revealed that many of the wellbore instabilities, such as pack-off, breakout, and stuck pipe, were attributed to the insufficient mud weight that failed to support the rock in the borehole wall. To avoid these issues, it was determined that a safe mud weight range of 11-12.5 ppg is necessary to prevent wellbore instability in shale formations. The study also highlighted the importance of using proper mud weight to prevent shear failure and other drilling complications. The findings of this study provide insights that can be utilized as a cost-effective tool for planning directional and horizontal drilling operations in the Eridu oil field. The accuracy of the failure criteria and geomechanical model is significantly superior and aligns with the analysis of breakouts observed in the caliper and image logs.

Aphron drilling fluids (ADFs) are finding increasing application in science engineering fields because of their distinctive characteristic. As the interest in the application of aprons-based fluids continues to grow, there is a decisive need to advance a deeper understanding of the factors affecting their behavior and properties, especially for successful petroleum industries, such as drilling depleted reservoirs and production. This study delves into investigating the density, rheological behavior and properties, filtration properties, bubble size, and their distribution of Aphrons-drilling fluids utilizing two ionic surfactants. Sodium Dodecyl Benzene Sulfate (SDBS) as an anionic surfactant, Cetyl Trimethyl Ammonium Bromide (CTAB) as a cationic surfactant, described as environmentally friendly, in Iraqi depleted reservoirs drilling. With an emphasis on the concentrations balance between Aphron generator (SDBS) and Aphron stabilizer (CTAB), the study analyzes the behavior and characteristics of Aphron drilling fluid. The investigation demonstrates that adding SDBS and CTAB reduces system density by 28%, owing to microbubbles production which is utilized with near-balance drilling. Rheological testing reveals that shear-thinning behavior in all Aphron samples improved, and the presence of SDBS affects the fluid's internal friction, gel strength, and short-term gel structure. Filtering control characteristic study demonstrates that the presence of microbubbles significantly minimizes fluid loss by 33% with 0.20% SDBS during filtering. Bubble size and dispersion studies demonstrate that 0.20% SDBS concentration, along with 0.30% CTAB, gives the best microbubble size and distribution. These findings suggest that Aphron fluids will be a promising innovation in petroleum industries, during actual drilling operations in Iraqi depleted oilfields.

Increasing oil production from a reservoir can be achieved by decreasing the distance between the injector and the producer through a process known as infill drilling, which involves a pattern water flood. The main objective of this study is to provide a comprehensive overview of the optimal infill well location and the research and applications available to enhance the oil recovery factor, leading to increased economic profits. one effective empirical approach used in this study is based on decline curve analysis, which analyzes the production history of the well to determine the final economic recovery. Additionally, a numerical method that combines numerical simulation and optimization techniques has been proven to be successful in determining optimal infill drilling locations. The research results show that the volumetric computation of oil in place is a useful method for estimating the number of infill wells needed, but it does not consider heterogeneity and continuity. On the other hand, the numerical simulation and optimization techniques can quantify the remaining mobile oil post-infill drilling and establish optimal pattern configurations for maximum recovery at their centers.

Nanoparticles (NPs) have unique capabilities that make them an eye-opener opportunity for the upstream oil industry. Their nano-size allows them to flow within reservoir rocks without the fear of retention between micro-sized pores. Incorporating NPs with drilling and completion fluids has proved to be an effective additive that improves various properties such as mud rheology, filtration, thermal conductivity, and wellbore stability. However, the biodegradability of drilling fluid chemicals is becoming a global issue as the discharged wetted cuttings raise toxicity concerns and environmental hazards. Therefore, it is urged to utilize chemicals that tend to break down and susceptible to biodegradation. This research presents the practical application of bio-based Zinc Oxide nanoparticles (ZnO NPs) prepared chemically from celery leaf plant extract as green additive in water-based mud drilling fluid (WBM). The study aimed to evaluate the filtration and thermal stability of WBM using green-synthesized ZnO NPs. The results showed that the ZnO NPs have minimal effect of mud density, but significant improvement in mud thermal stability and filtration properties were attained with concentrations lower than 1g. The fluid loss rate was reduced by 33% with 0.45g of ZnO nanoparticles, and the thinnest mud cake was obtained as well. In terms of thermal stability, the bio-based ZnO NPs greatly enhanced the rheological properties of WBM at elevated temperatures. The rate of increment in plastic viscosity (PV) or decrement in yield point (YP) and gel strength occurred in a controllable manner compared to the rheological properties of base mud at high temperatures reaching 90°C. This study provides insight into the effect of green-synthesized ZnO nanoparticles on the performance of water-based mud and highlights their potential as an effective and environmentally friendly additive for the oil and gas industry.

Efficient and cost-effective drilling of directional wells necessitates the implementation of best drilling practices and advanced techniques to optimize drilling operations. Failure to adequately consider drilling risks can result in inefficient drilling operations and non-productive time (NPT). Although advanced drilling techniques may be expensive, they offer promising technical solutions for mitigating drilling risks. This paper aims to demonstrate the effectiveness of advanced drilling techniques in mitigating risks and improving drilling operations when compared to conventional drilling techniques. Specifically, the advanced drilling techniques employed in Buzurgan Oil Field, including vertical drilling with mud motor, managed pressure drilling (MPD), rotary steerable system (RSS), and expandable liner hanger (ELH), are investigated and evaluated through case study analyses, comparing their performance to that of conventional drilling techniques. The findings indicate that vertical drilling with mud motor exhibits superior drilling performance and wellbore verticality compared to conventional rotary drilling bottom hole assemblies (BHA) for drilling the 17 ½" hole section. MPD systems employed in the 12 ¼" hole section demonstrate safe drilling operations and higher rates of penetration (ROP) than conventional drilling methods. Rotary steerable systems exhibit reduced tortuosity and achieve higher ROP when compared to mud motor usage in the 8.5" and 6" hole sections. Lastly, investigations of expandable liner hanger cases reveal subpar cement quality in the first case and liner remedial work in the second case, highlighting the successful implementation of ELH techniques in the offset field. Overall, this paper highlights the advantages of utilizing advanced drilling techniques in Buzurgan Oil Field, showcasing their ability to mitigate drilling risks and enhance drilling operations when compared to conventional drilling approaches.

Wellbore instability is a main challenge and contribute to suspending the drilling operations that lead to over-well time, known as Non-productive time (NPT). The cost of drilling operation can be reduced by using a geomechanical model that contributed enormously to the design of an appropriate mud weight window and determined the optimum well trajectory for the plan well. Several wellbore instability encountered while drilling operations in the Eridu oil field, such as (hole collapse, losses, caving, and tight hole). In this study, a geomechanical model (MEM) was developed by using the related data (open hole log measurements, core analysis data, drilling observation data), then these data were utilized in software (Techlog, version 2021). Two failure criteria (Mogi –Coulomb and Stassi d’ Alia failure criteria) were used for the prediction the breakdown and breakout profile; moreover, address the optimum mud window to mitigate wellbore instability-related issue for different well trajectory. The geomechanics results demonstrated that the Mogi failure criterion produced reasonable results when combined with the caliper log. Also, the Eridu oil field fault regime is divided into two regions: strike-slip faults in carbonate rocks and normal faults in clastic rocks. To avoid a majority of wellbore instability problems in shale formations, the safe mud weight range is 11-12.5 ppg. The failure analysis, especially shear failure, showed that the mud weight used previously in this field is improper to support the rock on the wellbore wall. This study’s finding could be used as a cost-effective tool when the plan to drill a direction and horizontal well in Eridu oil field..

This paper focuses on optimizing gas lift techniques in four wells located in the North Sea to overcome the common issue of low reservoir pressure. Gas lift is a common artificial lift technique used in wells with low reservoir pressure where the natural pressure of the reservoir is insufficient to bring the oil to the surface. The success of gas lift optimization depends on identifying the deepest injection point, gas injection rate, and pressure of the gas injected. The paper proposes the deepest injection points for wells A-03, A-09A, A-10T2, and A-12BT2 as 3809.38 ft, 6649.7 ft, 3559.88 ft, and 3979.04 ft, respectively. The injection rates analyzed in this paper range from 1-10 mmscf/day, and injection pressures of 500 psia, 1000 psia, and 1500 psia were used. The response of each well to gas lift was analyzed, and increasing injection rate and pressure were found to increase oil production rate. The optimal gas injection rate and pressure for wells A-03, A-09A, and A-12BT2 were found to be 10 mmscf/day and 1500 psia, while for well A-12BT2, the best oil recovery was obtained at an injection rate of 3 mmcsf/day and injection pressure of 1500 psia. Tubing size within the range of 1-5.5 inch was examined, and it was found that increasing tubing size enhances oil flow rate. The optimal tubing size for the wells was found to be 5.5 inch, taking into consideration factors such as flow rate, pressure, temperature requirements, and fluid type.

This research investigates factors influencing cuttings transport efficiency in air drilling operations, aiming to understand the underlying mechanisms, identify critical factors, and optimize drilling parameters for enhanced performance. The methodology includes a literature review, computational fluid dynamics (CFD) simulations, and sensitivity analysis of air velocity, drilling fluid properties, cuttings size, and outlet pressure. CFD simulations were employed to model the multi-phase flow in the annulus during air drilling, examining the effects of varying air velocities, cuttings sizes, and outlet pressures on cuttings transport and hole cleaning efficiency. Results show that increased air velocity improves cuttings transport and hole cleaning but may cause higher pressure drops and borehole erosion. Air drilling fluids' unique rheological properties significantly impact cuttings transportation, requiring careful consideration of factors like air velocity, aerodynamic lift, hole cleaning efficiency, annular pressure losses, and potential cuttings accumulation. The study reveals that cuttings size is crucial for transport efficiency, with larger cuttings necessitating higher air velocities for effective transport and being more prone to settling and accumulation. Moreover, the research demonstrates that increasing outlet pressure typically enhances cuttings transport efficiency in horizontal wells. In conclusion, this study offers valuable insights into factors affecting cuttings transport efficiency in air drilling operations, providing recommendations for optimizing drilling parameters to balance efficient cuttings removal, hole cleaning, and minimal pressure drop. The findings hold practical implications for air drilling operations' design and execution, with the potential to improve drilling performance and reduce operational risks.

One of the challenging issues encountered during drilling operations is the lost circulation. Numerous issues might arise because of losses, such as wasting of time and higher drilling cost. Several types of lost circulation materials have been developed and are being used to limit mud losses and avoid associated issues. Each solution has benefits and drawbacks. In this study, a core flooding test was performed to study the effectiveness of polyacrylamide (PAM) granular gel on the reduction of the circulation lost. One common type of fracture characteristic is fractures with tips, commonly known as partially open fracture (POF). However, PAM gel therapy in POFs received little attention in prior research. Models of partly open fractures were built using a cylindrical core. A series of processes are performed on a core to get a POF model. Overall, the PAM gel can decrease plug permeability, making it a useful material for lost circulation. The results indicate that the Polyacrylamide granular gel can decrease the permeability up to 193 times.

In Ahdeb oil wells, several unsuccessful acid-fracturing stimulation operations have been recorded (conducted). Strong variability in the Mishrif Formation results in a poor and rapidly declining single-well production rate following conventional acidizing. The optimal oil-field development strategy for such a reservoir will be suggested with the aid of treatment design and formation evaluations. After a well has been fractured, experts need to understand the treatment design and the formation to make accurate predictions of production or productivity-index ratio. The G-function and its diagnostic derivatives, the square root of time and its derivatives, and the log-log plot of pressure change after shut-in, will all be used to present the analysis. By examining the unique shapes of the derivative curves, leakoff processes and fracture closure locations may be identified. In the case of a typical leakoff, a fracture closes when the derivative curve of the g-function deviates from its tangent line (the best possible scenario). Both the pressure against the G versus time curve and its semilog derivative are shown in the G-function diagram.

Tubular buckling is caused by the axial compression load and is defined as a loss of the original rectilinear condition. Numerous studies have long been conducted to investigate the buckling of string in a borehole. Existing buckling theories, according to an increasing number of experts, need to be investigated because they are unable to accurately predict the buckling phenomenon. Indeed, current buckling theories frequently propose a flawless wellbore with a smooth trajectory profile. A pipe buckled in a deviated well trajectory can cause casing damage, decrease compression load to the bottom, drillpipe failure, trajectory change, severe catastrophic environmental problems, etc. As a result, it is critical to conduct research into the impact of tubular buckling inside horizontal wellbores to reduce or avoid the aforementioned issues. The Numerical Modeling Simulation was used in this study to forecast the critical buckling load for a pipe structure and how it will behave under different loads; these predictions were then confirmed by experimentation and a few analytical techniques. In terms of load transfer (helix prediction) and sinusoidal prediction, this paper presents experimental and theoretical findings for drill string and weight on bit (WOB). The findings of this study indicated a good Finite Element (FE) model which has been created and successfully validated using experimental data and an industry-standard simulator. Even though current models were unable to predict observed buckling behavior, the novel buckling model provided excellent forecasts for various drillstring configurations. Besides, the ability of this FE model to predict the onset and severity of buckling in a 3D trajectory has been successfully demonstrated.

Drilling well design optimization reduces total Authorization for Expenditures (AFE) by decreasing well constructing time and expense. Well design is not a constant pattern during the life cycle of the field. It should be optimized by continuous improvements for all aspects of redesigning the well depending on the actual field conditions and problems. The core objective of this study is to deliver a general review of the well design optimization processes and the available studies and applications to employ the well design optimization to solve problems encountered with well design so that cost effectiveness and perfect drilling well performance are achievable. Well design optimization processes include unconventional design(slimhole) compared with fat design, in addition to optimizing casing setting depth selection and casing string loads. Finally, we demonstrate well trajectory design considerations and optimization. The optimization process that mentioned above is significantly reduce drilling cost and time since, slimhole design with smaller casing and hole size reduce mud volume cost, steel cost and pump fuel cost. Optimum casing seat selection can ovoid serious problem such as kick and losses that increase nonproductive time (NPT) if kick tolerance and downhole pressure profile is not considered. Anticipating optimum stress loads in casing design is most effective way to reduce casing strings cost avoiding additional cost for designing with useless worst conditions. Wellbore trajectory optimization with geomechnic consideration is major concern to reduce the problem encountered with high torque, drag, formation collapse that result stuck pipe and non-productive time (NPT).

Low oil extraction and early high water production are caused in part by reservoir heterogeneity. Huge quantities of water production are prevalent issues that happen in older reservoirs. Polyacrylamide polymer gel systems have been frequently employed as plugging agents in heterogeneous reservoirs to regulate water output and increase sweep efficiency. Polyacrylamide polymer gel systems are classified into three classes depending on their composition and application conditions, which are in-situ monomer gel, in-situ polymer gel, and preformed particle gel (PPG). This paper gives a comprehensive review of PPG’s status, preparation, and mechanisms. Many sorts of PPGs are categorized, for example, millimeter-sized preformed particle gels, microgels, pH-sensitive cross-linked polymers, swelling polymer grains, and Bright Water®. In addition to this, the most important factors to consider while assessing gel performance, such as swelling capacity, PPG injectivity, and plugging efficiency, are studied carefully. Not only are the design considerations and field application of PPG mentioned, but also the advantages of PPG are demonstrated. Gels have been used in around 10,000 wells worldwide to reduce the fractures permeability or super-high permeability channels during water and polymer floods.

Today oil industry faces a lot of problems and lost money during drilling and completion operation, so that the studies and researches must including the ways and solutions that lead to decrease the costs. In this research we tried to find local alternative material instead of foreign drilling fluid materials that is used in drilling fluids and will help to save a lot of money by decrease oil well drilling cost because of the high cost of drilling fluid materials which represent now about 30 % of total cost for drilling oil well. The local alternatives is Ore polymers ( plant origin) called : TRAGACANTH GUM. In this study we investigated the local material and tested it under API Specification for Drilling Fluids Materials. Also tested sample of mud after add local material (TRAGACANTH GUM.) for weighted concentrations (0.5, 1.5, 2, 2.5 and 3 gm.) to show physical and rheological properties. The third part of this study tested sample of mud after add local material (TRAGACANTH GUM.) under different temperatures values and up to 70°C (this temperature is near for some formations temperature in Iraqi oil fields ) to show temperature effect on this material. A comparison between the local alternative and similar foreign materials for same sample was done to show physical and rheological properties. The results approved that, the local alternatives can used as filtration control materials for water based drilling fluid. Also the local alternatives increased viscosity as minimal for water based drilling fluids, So it can be used as part alternative for Bentonite to increase viscosity by increasing Yield point and decreasing solids concentration in drilling fluids so it have positive effect to save Rig equipment’s and Pay-zone.

Shale and shaly formations constitute about 70% to 80% of the total rock formations drilled worldwide, and the most of footage drilled in gas and oil wells is in shale and shaly rocks. Drilling in shale sections in many cases causes wellbore instability and slow drilling problems. In this study, cation exchange capacity of shale is estimated using a relatively simple petrophysical model. The validation of this model is achieved with experimental values of cation exchange capacity. The estimation of cation exchange capacity by this model and common logs data has exhibited potentiality for distinguishing effective/ineffective drilling in shale formations. Drilling and petrophysical data gathered at controlled condition is required in order to optimize the proposed technique. Have knowledge of properties and location of shales permits for remedial actions in future offset well or while drilling in case of logging while drilling (LWD) is used

Many southern Iraqi oil field formations, such as Dammam and Hartha, are characterised as loose formations, making overbalanced drilling difficult due to increased frequency and volume of mud losses. Managed pressure drilling techniques (MPD) may thus be applied. This process uses conventional hydrostatic column pressure and annular friction pressure in addition to the surface back pressure to generate a constant bottomhole pressure (CBHP) to drill such formations, which enables the use of the lowest mud weight (closest to pore pressure) and back pressure treatment utilising a choke manifold during the drilling process to maintain an equivalent circulating density (ECD) slightly greater than the pore pressure, reducing the risk of mud loss, and the concomitant stuck pipes and non-productive time (NPT), thus enhancing drilling efficiency. In this paper, Wellflo software was utilized to model multi-phase flow in wells to examine the use of aerated mud used at different injection rates for gas and liquid to identify the best injection rate for drilling operations without losses. Several cases were examined using various mud weights and surface back pressure of the assumed injection rates, to choose the appropriate mud weight and the surface back pressure ranges. The highest pore pressure gradient expected in such holes is 0.465 psi/ft, and consequently, the minimum required mud weight was 8.95 ppg, in order to ensure control and avoid loss; however, due to back pressure and friction pressure in the annular region, this weight leads to problems in some formations. A mud weight of 8.8 ppg was therefore chosen as the closest feasible weight to pore pressure, with back pressures of 200 and 250 psi. A gas injection rate of 1,200 gpm was selected as the best injection rate for various liquid rates (581, 631, 681,731, and 781 gpm). The use of aerated mud at 8.8 ppg mud weight increased the penetration rate, offering a more efficient cutting transportation ratio (CTR) and allowing more control over wellbore instability and formation damage, as well as limiting mud losses.