Oil-based mud is commonly used in drilling of the pay zones in sandstone formations as a less/non damaging fluid. Oil-based mud typically contain emulsifier, viscosifer and other additives including polymer blend and calcium carbonate to serve different functions. Presence of emulsifier may increase emulsion tendency upon interaction with downhole environment. The resulting emulsion might be tight to an extent that a thick sludge is formed which can impair well productivity. Identification of the sludge material will help in development of an effective chemical treatment to remove formation damage and restore well productivity. In this study, an extensive laboratory work was conducted to explore potential interactions of an oil-based mud with different contaminants encountered in downhole environment. A typical sludge sample was characterized using different analytical techniques including solvent extraction, XRD, TGA, ICP and viscosity. The results showed that the sludge sample contained calcium carbonate, dolomite quartz as the main components in the inorganic phase while the organic phase include polymers and oil. The source of calcium carbonate might the drilling additives while the source of quartz is the formation. Analysis of supernatants generated from solubility tests conducted for the sludge sample revealed in addition to the high amount of calcium presence of iron in considerable amount (nearly 1,000 mg/L). Interaction of ferric chloride, quartz with an invert-emulsion mud was investigated. A significant increase in viscosity was observed upon incorporation of these contaminates with the mud sample. This paper presents in detail the results of interactions of iron ions, quartz, and pipe dope. It also examined several chemical formulations for removal of sludge formed and filtercake.

In the recent decade, injection of nanoparticles (NPs) into underground formation as liquid nanodispersions has been suggested as a smart alternative for conventional methods in tertiary oil recovery projects from mature oil reservoirs. Such reservoirs, however, are strong candidates for carbon geo-sequestration (CGS) projects, and the presence of nanoparticles (NPs) after nanofluid-flooding can add more complexity to carbon geo-storage projects. Despite studies investigating CO 2 injection and nanofluid-flooding for EOR projects, no information was reported about the potential synergistic effects of CO 2 and NPs on enhanced oil recovery (EOR) and CGS concerning the interfacial tension (γ) of CO 2 -oil system. This study thus extensively investigates the effect of silica NPs on the γ of CO 2 /decane system at elevated pressure and temperature to recognise the potential impact of NPs-injection on the future CGS projects. To achieve this, a wide-ranging series of tests have been conducted to reveal the role of hydrophilic and hydrophobic silica NPs on γ of the CO 2 /oil system. n-decane was utilized as model oil and different amounts of NPs were mixed with the oil phase. Oil-NPs dispersions were formulated using an ultrasonic homogenizer. The γ of the CO 2 /oil system was measured at different pressures (0.1 to 20 MPa) and temperatures (25 to 70 °C) using a high-pressure temperature optical cell. The γ data were measured using the pendant drop technique via axisymmetric drop shape analysis (ADSA). The results showed that, generally, CO 2 /oil γ subjected mainly to pressure, temperature, and with less extent to NPs load in the oil phase. γ decreases with increased pressure until reaching a plateau where no more significant decrease in γ was observed. The γ trend with increased temperature, on the other hand, was more completed. No significant impact of temperature on γ was recorded with low pressure (≤ 5 MPa). Similarly, at relatively high pressure (≥ 25 MPa), only a slight variation of IFT with temperature change was recorded. However, for the pressure range from 5 – 25 MPa, IFT was increased remarkably with temperature. Furthermore, NPs in the oil phase exhibit a remarkable influence on IFT. In this context, the presence of hydrophilic silica NPs in the oil phase can significantly reduce the γ of the CO 2 /decane system. However, hydrophobic silica NPs showed less influence on IFT reduction. The outcomes of this work afford good understandings into applications of NP for EOR and CGS applications and help to de-risk CO 2 -geological storage projects.

Lost circulation is a major contributor to non-productive time (NPT). Any efforts to better understand the factors that lead to it and subsequently identify a suitable cure will translate to tremendous savings of time and money for operators. Conventional materials such as calcium carbonate, nut shells, graphites and fibers are successful in curing many cases of seepage and partial lost circulation. However, there is a practical limit to the concentration of these materials used to combat the most severe losses due to the limitation of pumps and drilling assembly. In porous formations, high fluid loss squeeze pills have seen some success in reducing losses by forming a high compressive strength plug, but these pills do not have a good success rate in large fractures or vugular formations. Such challenges are better addressed by cross-linking pills, but even this solution does not always have a high success rate due to the low compressive strength of the formed plug. The new phase-transforming loss circulation material (PTLCM) was designed to be pumped easily and achieve thixotropic behaviour under downhole conditions, resisting losses in the thief zone prior to setting as a rigid plug with high compressive strength. A setting-control additive ensures the LCM does not prematurely set. The additive is used at a concentration calculated by considering the time required for pumping and the bottom hole temperature (BHT) in the thief zone. After the LCM sets, a high compressive strength solid plug is formed that can resist fluid loss to the formation. The LCM has a high acid solubility of ~95%, making this system a viable option for deploying in reservoir sections, depending on the client requirement and well conditions. This paper describes two recent successful applications deploying this novel technology. Case Study #1: While drilling in sandstone, the well experienced total losses, which presented an immediate challenge to maintain hydrostatic pressure. The operator responded by pumping several conventional pills loaded with a broad particle size range of fibers, granules and polymers. These pills were unsuccessful at healing the losses, so the operator opted to deploy the new technology LCM. The losses were cured successfully with a single application. Case study #2: Wells drilled in the Western Desert have traditionally experienced severe to total losses while drilling fractured dolomite. Frequently, such events have been difficult to cure by conventional means. The only solution has been multiple applications of cement plugs to heal the losses. This case study describes a well with dynamic losses of more than 150 bbl/hr that were healed by spotting one pill through the circulating sub across the thief zone. The losses were successfully cured, allowing the operator to continue drilling.

Bulk permeability of coal is a critical parameter in coalbed methane (CBM) or coal seam gas (CSG) well completion designs and field development planning. The estimation of permeability can be made by well testing either during drilling or production; however, well tests are costly, time sensitive and resource-intensive. Therefore, field-wide estimates are often dependent on production data history-matching, which has a high degree of uncertainty. In this paper, we present a new attempt to apply machine learning approach to estimate coal permeability using drilling data. We first extract important parameters from well test analyses, which are obtained using a packer element testing (PET) tool from four wells in the Surat Basin, Australia. Then drilling data from the wells are processed and fed into different artificial neural networks (ANNs), which include multi-layer perceptrons (MLP), convolutional neural network (CNN), and recurrent neural network (RNN). Two types of models are constructed: regression model with permeability values, and classification model with permeability class intervals (i.e., low, medium, and high permeability values). The evaluation metrics include R 2 for regression models and confusion matrix for classification models. Results show that the drilling mud losses are generally higher in coal layers and lower in interburden formations. The predicted medium and high coal permeabilities from MLP and CNN are in good agreement with measured permeability values from PET data. For the classification task, the CNN achieved an overall accuracy of 99%. Thus, an improved coal permeability map with a higher resolution and less calibration against PET data can be developed quickly to aid production data history matching. The developed machine learning model demonstrated a potential to be applied to new wells to predict the coal permeability for the Surat Basin as well as other CSG appraisal projects. This model can allow more rapid optimisation of well spacing, improved downhole pump design, more targeted well stimulation, and overall project economics.

The Dvalin gas field is located in the Norwegian sea on NCS and is operated by Wintershall DEA Norge. It is supported by two independent reservoir structures, Dvalin East and Dvalin West. The field was explored through wells 14S and 15S in 2010 and 2012, respectively. The field is characterized by dry gas, high CO2, high temperature (160 °C) and high pressure (SIWHP 620 bar). The targeted Garn sandstone has good reservoir quality, but with a high permeability contrast. The field development was sanctioned in 2016 and calls for a 4 well solution through a centrally located subsea template, producing gas back to the host platform Heidrun TLP 15 km away. Water depth at location is 380 m and targeted reservoirs are at 4140 m MSL (East) and 4240 m MSL (West). Production plateau rates are estimated to be approximately 106 MMscf/D (3 million std m 3 /d) per well where thin high-permeability zones within the Garn formation are expected to dominate the inflow. The lateral facies development is thought to be relatively homogenous throughout the field, thus S-shape wells falling off to vertical through the reservoir will ensure effective drainage. Sand failure is expected after short time of production and would increase the risk of erosion causing severe damage to well jewelry and production facilities. It has been decided to integrate sand screens as a means of downhole sand control as part of the primary lower completion design. The sand screens will offer sand control, erosion resistance, hot spotting resistance as well as robustness towards a full hole collapse during reservoir pressure depletion. As the subsea completions are carried out from a mobile drilling unit in harsh environments, protection of the sand control filter media during installation is of utmost importance. This paper will describe the selection process of sand control and qualification steps carried out to use ceramic screens as the stand-alone screen solution for successful deployment and integrity for the Dvalin field development

Drilling extended lateral sections to maximize reservoir exposure is key to optimizing field production and data recovery. However, it presents peculiar challenges not limited to hole-cleaning, wellbore stability, narrow drilling windows, and excessive torque and drag. Thus, customizing the fluid system to drill lateral sections requires information to understand the formation characteristics, including geomechanical data to determine the correct mud weight window, a precise selection of optimal fluid rheological properties, good inhibition, and lubricity, which are of foremost importance for extended-reach drilling (ERD) wells. The reservoir section of the well presented in this paper was previously drilled unsuccessfully twice, as the targeted zone was not reached. During the drilling phase, a large amount of non-productive time (NPT) was observed due to stuck pipe incidents, hole collapse, and then, hole cleaning issues were encountered while drilling. Another critical concern is the narrow mud weight window range, which causes the formation to break when Equivalent Circulating Density (ECD) increases beyond the pore pressure or fracture pressure of the formation. A new generation of High-Performance Non-Aqueous Based Mud (HPNBM) was engineered to drill these types of complicated, long horizontal intervals matching the drilling performance required to drill such sections and deliver a perfect gauge hole. This HPNBM provides high shear-thinning properties, an excellent low-end rheological profile, and rapid-set/easy break gels. This paper presents a successful well delivery of drilling the longest horizontal section in the country within a record amount of time. The previous attempts were carefully studied to identify the challenges associated during drilling and considered while designing this HPNBM. The high-performance non-aqueous based mud system proposed with stress caging technique was successful, economic, and drilled successfully with zero non-productive time (NPT) related to drilling fluids. Engineering software was utilized as hole cleaning is critical for drilling the horizontal sections to reach the targeted depth and run casing to the bottom. This paper presents the longest horizontal section (4,200 ft) to be drilled to the targeted depth as planned in Turkey. A comprehensive analysis that includes the planning phase, application, techniques, and performance of the mud system will be presented.

Drilling is considered one of the most challenging and costly operations in the oil and gas industry. Several initiatives were applied to reduce the cost and increase the effectiveness of drilling operations. One of the frequent difficulties that faces these operations is unexpected drilling troubles that take place and stops the operation, resulting in losing a lot of time and money, and could lead to safety issues culminating in a fatality situation. For that, the industry is in continues efforts to prevent drilling troubles. Part of these efforts is utilizing the artificial intelligence (AI) technologies to identify troubles in advance and prevent them before maturing to a serious situation. Multiple approaches were tried; however, errors and significant deviation were observed when comparing the prediction results to the actual drilling data. This could be due to the improper design of the artificial intelligent technology or inappropriate data processing. Therefore, searching for dynamic and adequate artificial intelligent technology and encapsulated data processing model is very essential. This paper presents an effective data-mining methodology to determine the most efficient artificial intelligent technology and the applicable data processing techniques, to identify the early symptoms of drilling troubles in real-time. This methodology is CRISP-DM that stands for Cross Industry Standard Process for Data Mining. This methodology consists of the following phases: Business Understanding, Data Understanding, Data Preparation, Modeling, Evaluation and Deployment. During these phases, multiple data-quality techniques were applied to improve the reliability of the real-time data. The developed model presented a significant improvement in identifying the drilling troubles in advance, compared to the current practice. Parameters such as hook-load and bit-depth, were studied. Actual data from several oil fields were used to develop and validate this smart model. This model provided the drilling engineers and operation crew with bigger window to mitigate the situation and resolve it, prevent the occurrence of several drilling troubles, result in big time and cost savings. In addition to the time and cost savings, CRISP-DM provided the artificial intelligent experts and the drilling domain experts with a framework to exchange knowledge and sharply increase the synergy between the two domains, which lead to a common and clear understanding, and long-term successful drilling and AI teams collaboration. The novelty of this paper is the introduction of data-mining CRIPS methodology for the first time in the prediction of drilling troubles. It enabled the development of a successful artificial intelligence model that outperformed other drilling troubles prediction practices.

Achieving complete and efficient gravel packing is the primary objective when tasked to install an effective sand control completion. This paper describes the challenges faced during the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the "L" field, offshore Republic of Congo. The open hole gravel packs (OHGPs) targeted the most prolific sand to ensure production objectives were achieved with the benefit of a gravel-pack completion. The operator completed two OHGPs with alpha/beta technique for the sand face completion utilizing concentric annular pack screen (CAPS), wire-wrap screens, and a service tool permitting post-gravel pack filter cake clean-up treatments. The accurate selection, modeling, and evaluation of sand control techniques were crucial for completion and production optimization, as well as risk minimization. The service approach had traditionally leveraged upon industry rules of thumb and previous experience, but as the reservoir section length increased and completion configuration became more complex, the error margins tightened and the cost of failure increased such that a more robust design approach was needed. This paper addresses several key factors that must be considered carefully when installing a successful gravel pack completion. The dynamic pressure management becomes critical to maintain the bottom hole pressures within a required range for the successful implementation of the gravel pack. Other factors include designing an optimal screen-wash pipe annulus ratio during alpha-beta wave packing, an optimal alpha wave height, and the use of multiple beta wave packing rates. Results from the preliminary modelling of the gravel pack pumping provided an accurate estimation of the maximum and minimum anticipated pumping rates and pressures. These parameter estimates were generated for the workstring design scenarios and provided guidance for the planned pumping rate adjustment during the gravel packing execution phases. The gravel packed wells achieved pack efficiency greater than 100% based on an estimated 8.5-in. diameter OH. Post completion multi-rate tests concluded potential productivity exceeding the operator's expectations. This paper describes the lessons learned and best practices developed for offshore Congo open-hole gravels packs, which have a very challenging well completion and reservoir scenario. Several proven completion practices are reviewed, with a critical examination of the application of these scenarios for future completion operations in this difficult operating environment. This applied methodology has made significant impact on future field development and increased the production expectations for the asset.

This paper presents a case study on usefulness of having geomechanical understanding to avoid drilling risks and minimize costs in a Drilling campaign, Offshore Peninsular Malaysia. Significant drilling issues related to wellbore stability were encountered in the four exploration wells drilled during previous campaigns. The development wells were planned to drill with high inclinations (up to 70 0 ), through weak coal layers and cross major fault. The drilling problems of the offset wells were critically analyzed to understand the mechanisms of failures. A geomechanical model was built using the offset well information. The well-calibrated stress model was then used for the wellbore stability modeling for the planned trajectories. The outcome of this study was used as key input for casing and mud design. With the help of the reccomendations based on this study, six highly inclined development wells were drilled through low pressure and narrow mud window intervals without operational problems. Reducing non-productive time (NPT) for the entire drilling campaign was one of the key focus for delivering the wells safely within schedule and budget. This paper documents the entire workflow and methodologies used for this entire study.

The Greater Enfield Project (GEP) is a challenging offshore oil development, designed to produce from the Laverda Canyon, Cimatti and Norton over Laverda oil fields. Six water injection wells are required to provide pressure support and sweep oil to three production wells in the Laverda Canyon and Cimatti oil accumulations to improve oil recovery. The GEP injection wells are a critical aspect of water flood design in a complex field, new to Woodside and with limited global benchmarks. A specific drilling and completion fluid system (Reservoir drilling fluid, completion fluid and chemical filter cake breaker) combined with a unique clean up and displacement technique have been adopted to provide high and sustainable matrix injection performance. While filter cake breakers have been previously used in the industry, they are typically combined with a flowback for filter cake removals. Filter cake clean up by means of flowback was discounted for GEP due to cost and the inability of some wells to naturally flow during early life. All GEP injection wells were completed in 2018-2019, one of which is globally the longest horizontal water injection well completed to date based on the Rushmore data base. Fieldwide injection commenced in July 2019 with favorable results. This paper summarises the key design aspects adopted to deliver successful matrix injection performance, presents the improvements implemented during offshore execution and provides an insight into the early life injection performance.

The emergence of Real-Time Well Construction Performance Monitoring Centers has significantly improved the service delivery for Operators across numerous offshore oil fields in Australia. New technologies and workflows were implemented for 3 Australian offshore wells, with the primary objective being to improve drilling efficiency while managing the associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the Operator and highlighting areas of possible improvements. The workflows combined proven technologies, software and wellbore surveillance services, which delivered risk-free wells ahead of Authority for Expenditure (AFE), by targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management. The workflow began with a preliminary field analysis to identify the main challenges and areas that needed improvement. The key learnings were then consolidated on a comprehensive drilling road map by well section that outlined prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also identified performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the Execution Stage were developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration and connection time. The workflows enabled the flawless execution of 3 offshore wells 29.0 days ahead of AFE which saved the Operator USD 15.5M. The closed loop monitoring enabled real time interventions which aided in preventing risks such as stuck pipe, ensured efficient shoe-to-shoe drilling and avoided potential lost-in-hole (LIH) costs. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow was using existing and cost-effective technologies while capitalizing on the renewed synergy between different departments such as Drilling, Mudlogging and Well Operations analysis. The workflow was and can be customized based on different needs, by combining specific modules for monitoring, analysis and wellbore surveillance services, to increase the efficiency of any well construction.

It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications. Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles. The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results. The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.

Historically, stuck-pipe events have been shown to cost the industry several hundred millions of dollars per year, and over 30% non-productive time ( Muqeem et al. 2012 ). In all cases, remedial operations to salvage the subject well are expensive; and success is not guaranteed. This paper describes a case history demonstrating how a differentially stuck string was freed in a relatively short time using an innovative enzyme/weak acid recipe. The string was a 4-1/2 in. lower completions bottom hole assembly (BHA) comprising of swell packers, and inflow control devices. The string was deployed in a carbonate reservoir. After deploying the string in the first 1,000 ft of open hole, the crew stopped to fill up the string to confirm circulation. Upon resumption of operations, the completions string was found to be stuck with no string movement possible in the upward or downward direction. Full circulation was still achieved. The fluid in hole was a water-based fluid. The string was diagnosed to be differentially stuck. It was established that the stuck point was across the high permeable zone. Efforts to work the string free with glycol pills proved unsuccessful. An attempt to place 20%; HCl acid induced up to 30 - 40 barrels per hour (BPH) dynamic losses at the shoe. Luckily, the losses healed relatively quickly, but the string remained stuck. After 29 hours of several unsuccessful attempts, a recipe of an enhanced combination pill of enzymes, and a weak acid accelerator was proposed, pumped across the stuck point, and allowed to soak. After a relatively shorter period of soaking, the string became free. The action of the enzyme/acid pill worked by destroying the polymer base of the filter cake created by the water-based drilling fluid. The homogeneous placement and action of the enzyme/weak acid pill across the stuck area ensured that it was more effective than the conventional HCL acid pill. Hence, the application is being presented as a potentially safe, efficient, and cost-effective option to free a differentially stuck BHA in water-based drilling fluid. Success in freeing a stuck-pipe usually depends on two critical factors - an accurate diagnosis of the mode of stuck-pipe event (i.e. differentially or mechanically); and the ability to implement the remedial operations quickly, and effectively. By implementing the above described technique, significant non- productive time (NPT) was averted. The technique has since been implemented in subsequent differential stuck-pipe events in water-based drilling fluids with a 100%; success rate.

During the drilling process of exploratory wells, the formation data is often limited; most of the time drilling engineers must estimate the pore pressure and fracture gradients. This information is critical for designing the drilling fluid, spacers, and cement slurry as to provide the necessary density and rheological properties. An error in estimating the pore pressure or fracture gradients can induce wellbore instability and lost circulation. If these losses are not controlled, during the cementing job the programmed top of cement (TOC) will not be achieved, zonal isolation will be compromised, and the casing string will not be fully supported. These problems can lead to additional expenses such as remedial jobs, non-productive rig time, use of additional materials, costly logistics, etc. This paper presents a case history with a critical cementing job in which the operator was drilling an offshore exploratory well in Southern Mexico when an area with constant gas flow with a narrow pore-pressure to fracture-gradient window was encountered. The operator had to increase the density of the drilling fluid, which in turn induced total losses. The cementing company recommended pumping a unique spacer technology that enabled circulation to be regained while pumping the cementing job. This technology is an ultra-low invasion cementing spacer that creates an impermeable barrier on the face of the formation through differential pressure. This barrier helps to isolate the formation from the total equivalent circulating density (ECD), thus allowing circulation even in situations where the ECD approaches or slightly exceeds the fracture gradient.

Water-oil emulsion formation is commonly observed at wellhead chokes and topsides control valves, with the impact mitigated by chemical injection. The presence of emulsions downhole in Pyrenees wells was inferred from their significant production rate impact and confirmed by the uplift observed from downhole chemical injection. The Pyrenees fields are located in the Exmouth sub-basin offshore Western Australia. Through analogy between individual Inflow Control Device (ICD) orifice elements and wellhead chokes, ICDs were suspected as the source. This paper describes experimental confirmation of emulsion formation by orifice type inflow control devices in Pyrenees field horizontal well completions and proceeds to characterise the emulsions formed. A purpose built flow rig combined Pyrenees crude oil and produced water under low shear, simulating reservoir flow conditions, before flowing through an orifice element at rates equal to peak and mid-life production. With liquid flow rate held constant, water cut was increased in 10% steps from 0 to 100% water content. A key component of the experimental system is a benchtop Nuclear Magnetic Resonance spectrometer equipped for non-invasive Pulsed Field Gradient measurement of the Droplet Size Distribution of the emulsions formed. Droplet size distribution is a fundamental fluid property that significantly impacts emulsion rheology. The heavy end component of the crude oil was characterised by a novel Enhanced Saturate Aromatic Resin and Asphaltene analysis procedure to facilitate benchmarking of Pyrenees with emulsion formation tendencies of other producing assets. This quantitative demonstration of emulsion formation by orifice type ICDs at near reservoir conditions is novel, as is observation of partial emulsification, and represents initial steps towards generalisation of models for emulsion formation and their transport properties.

Wax deposition during pipeline transportation of crude oil is one of the serious flow assurance problems faced in the petroleum industry ( Deka et al., 2020b ) and wax gelation phenomenon is an inherent characteristic of the wax deposition process and it must be investigated to understand the deposition process. Wax-gelation formation was simulated during flow of waxy oils by numerically simulating its gelling behavior during transportation under different operating conditions by developing a computational fluid dynamics (CFD) model. The modelling technique and the obtained results from this work would help to predict the wax deposition and gel formation tendency in different waxy oils. Wax deposition phenomenon was modelled for a model wax-oil mixture (representing a waxy oil). A numerical model was developed to predict the wax gelation with time and length of pipeline. It involves heat and mass transfer calculations and molecular diffusion mechanism is considered as the primary mechanism for wax deposition, with the calculations being performed for 5 days. The CFD model uses enthalpy porosity technique where wax-oil gel is treated as the solid-liquid region with porosity equal to the liquid fraction. Fluid flow was considered laminar with flow rates being 1-5 GPM and ambient temperature was maintained at 281.3 K. The developed numerical model predicts that the wax gelation increases with time initially and then slowed down subsequently and less increment is observed upon 5 days of fluid flow. These results indicate the wax gelation is fast initially and slows down subsequently, showing strong dependence on time. Wall temperature of wax-oil mixture and the gel deposit decreases from bulk fluid temperature (295.2 K) to the ambient temperature (281.3 K). Increase in the temperature difference between wall and ambient temperature leads to higher wax deposition and gelling formation. Wax gelation was observed to be function of time. The CFD model numerically-simulates the wax-oil gelling formation in terms of liquid fraction (gel formation), where the liquid fraction gets reduced up to 44.7 % upon crude oil flow in the pipeline, being highest at the centre and lowest at pipe-walls, indicating the possible gel formation regions on pipewall. The gel formation was strongly affected by the wall temperatures, duration and length. This work would be one of its kind to report CFD-simulations of wax-oil gel formation in pipelines, where interdependency of fluid flow parameters would be assessed. Therefore, in this work, an attempt was made to simulate the gelling behaviour of the wax crystals in pipeline using an enthalpy porosity technique which has been not been tested much before. Computational fluid dynamics is used in this work to simulate the wax-gelling phenomenon and the wax gelation is observed through observing the changes in the liquid fractions of the wax-oil mixture used in this work. The current work would provide a comprehensive understanding about the wax deposition and gelling phenomenon in waxy oils and would help to design waxy-oil pipelines with appropriate measures, especially in subsea conditions.

The Sangomar Field Development – Phase1, located offshore Senegal, will consist of 23 wells targeting stacked reservoirs, with horizontal lengths up to 1,500m. Due to the long drilling campaign, wells are likely to be drilled after first production, targeted for 2023. At the time of drilling, reservoir pressure in these wells will be affected by nearby producers and injectors, which will reduce the mud window in the boreholes, affecting the drillability. Vulnerable wells are identified by a deterministic borehole stability assessment based on mud weight windows and a probabilistic well-by-well analysis of reservoir pressure at the time of drilling. The estimated mud weight windows are unique to each well and a function of completion type, overburden thickness and well azimuth. Capturing reservoir uncertainties within the uncertainty framework results in 216 models which are reduced to a more manageable 20 models for simulation using a distance-based K-medoid algorithm. Maps of maximum depletion and inflation are generated for each of the medoids. With this work, the importance of probabilistically assessing reservoir pressures is demonstrated in the context of developing a robust drilling sequence, highlighting that results can vary significantly depending on the reservoir models used. Potential magnitudes of depletion and inflation in some scenarios are significantly greater than initially anticipated. The combination of borehole stability assessment and probabilistic well-by-well analysis of reservoir pressure allows clear identification of wells at increased risk of borehole stability problems caused by injection or depletion. Subsequently, the drilling sequence is updated to mitigate borehole stability risks by executing potential problem wells prior to first production and prioritising key water injectors, enabling management of post-production depletion while continuing to meet the other objectives such as maximising early production potential. This paper outlines an innovative workflow which captures the range of subsurface uncertainties to define probabilistic impact of depletion and injection on borehole stability. Within the literature we have not seen any examples of depletion and inflation being assessed probabilistically on multiple models or using a map-based format. Depletion and inflation are also often discussed in the context of producing fields, not during the first phase of drilling, as is the case for the Sangomar Field.

In 2014 ConocoPhillips (CoP) decided to focus on the Jet-type perforate, wash and cement (P/W/C) technique as its primary permanent well abandonment method for setting a full cross-sectional cement/steel barrier. Following this decision, a quality improvement project was launched to prepare for a transition from Cup-type to Jet-type P/W/C to improve barrier plug quality. The initiative was presented during the Stavanger P&A Forum (PAF) conference October 2014 for information and to indicate for specific vendors that there were opportunities for participation. The perforate, wash and cement method is complex and as with any cementing operation there is operational risk involved. This paper is written to share ConocoPhillips experience and learning from the improvement project which is still ongoing. It is specifically written for drilling engineers planning Jet-type P/W/C operation to help identifying key parameters to achieve a top-quality operation as well as managing the operational risk inherent to the operation. Quality requirement in P&A operations? It can be a hard sell to argue for costly fluids, BHAs (bottom hole assembly) and TCP (tubing conveyed perforation) guns to plug off a depleted reservoir where the test of time is hundreds of years from now as the reservoir gets pressurized again. The latter is not the case in the Greater Ekofisk Area (GEA) where active water injection increases the average reservoir pressure quickly and the established production strategy is dependent on good isolation of abandoned wellbores. To get a ‘’good’’ P&A plug you need to understand how to prioritize and control the variables such as cement properties, drilling fluid properties, drill pipe and BHA design, hole cleaning, ECD, displacement, TCP performance, operational sequence and many more. ConocoPhillips have made a structured approach to build a process which captures the basics of getting a high quality well abandonment plug. The displacement process itself has been modelled with computational fluids dynamics (CFD) software to understand key drivers for the placement of a cross-sectional P&A plug. This understanding has been mated with the practical limitations from a standard drilling unit to get a robust operational plan. To ensure the quality is maintained from operation to operation, the process have been accurately described in a Best Practice document. The operation itself is checked against a QA form to verify that execution was performed according to plan. The QA form is then filed as part of the P&A documentation, similar as a casing test during well construction. In the GEA experience a good P/W/C P&A plug is one set as per the Best Practice document where the operation is quality assured with an "all green" QA (quality assurance) sheet. A more tangible description is offered: After the operation the offshore cement sample which is contaminated with 10% mud will set up in the UCA (ultrasonic cement analyser) cell per programmed setting time plus no more than 3 hrs. The cement plug itself will be tagged at planned TOC (top of cement) +/- 20 ft. It will hold the positive pressure test to fracture gradient + 1000 psi. From time to time the plug will be drilled out. If that is the case, we expect to see an average weight on bit larger than 15,000 lbs for a 9 5/8’’ casing plug. The external well barrier element may be logged using a CBL/USIT (cement bond log) string or similar. In that event we expect to see "bond quality", which is a weighted interpretation of CBL, VDL (variable density log), flexural attenuation and pulse echo measurements as "good" to "very good" throughout the perforated section. This paper is one of many discussing the P/W/C technique (1) and is written to help you prioritize focus areas and optimize those. We think a high focus on QA will be your fundament, not only for a "good" P&A plug but also for a flawless execution of the complex offshore operation. Our results can be reviewed in Appendix B . Performance approach technical limit.

Perforate-Wash-Cement (P/W/C) is a well plugging technique extensively used by ConocoPhillips in the Greater Ekofisk Area over the last ten years. In Jet-type P/W/C, Tubing Conveyed Perforating (TCP) guns perforate casing in the target interval before the zone is washed and a cross-sectional cement plug is installed using a specialized Bottom Hole Assembly (BHA). The goal is to maximize the cement plug quality through optimizing the BHA and operational process parameters within constraints imposed by the operating conditions. This paper describes application of Computational Fluid Dynamics (CFD) to achieve this objective. CFD is well suited for modeling wash and cement processes including the associated non-Newtonian fluids. A CFD model of these processes employs unsteady multiphase Reynolds Averaged Navier Stokes (RANS) based Volume of Fluid (VOF) approach with a Shear Stress Transport (SST) K-omega turbulence model. BHA translation and rotation are simulated using moving deforming-layering mesh with interface approach. Physical properties of non-Newtonian fluids selected are based on in-situ conditions and derived via lab tests. CFD-specific considerations such as domain size, turbulence model, mesh type and size, and computational timestep are discussed in this paper. The magnitude and duration of the jet-induced "pressure pulse" in the annular space between the formation wall and the casing are a key to efficient displacement during the wash and cementing processes. Displacement efficiency, in terms of the percentage of mud or cement in a control volume as a function of time, depends on perforation size and density, nozzle size/number, flow rate, fluid properties, as the ROP/BHA pulling speed and tool RPM. Key findings from a parametric study to optimize these parameters are presented. To validate CFD nozzle flow predictions and to rule out potential for false results due to cavitation, laboratory tests were performed under pressurized conditions. A comparison of results from CFD simulations using traditional versus optimized parameters are presented, demonstrating significant efficiency improvement achieved. The study initially focused on North Sea application. Encouraged by substantial improvement in process efficiency through parametric optimization, the technique was extended to UK operations and is planned for the Bayu-Undan field. Cementing simulation results for Bayu-Undan specific well configurations are presented, showing how CFD modeling helped reveal less than ideal cementing efficiency. Ultimately, this work provides significant time savings and quality improvement for P&A projects while maintaining a high safety standard.

To control and equalize the horizontal well drawdown, Autonomous Inflow Control Device (AICD) are planned to be installed along the homogenous reservoirs in five infill wells at B field, Sarawak offshore (Malaysia). The very low viscosity contrast between oil and water (0.6cp and 0.5cp) with 37API degree at B gives unfavorable mobility ratio and water flows with a higher velocity than the oil. This paper presents the interdisciplinary approach to completion design needs which evaluated the efficiency and performance between conventional completions compared with passive inflow control device (ICD), AICD namely Rate Control Production (RCP) and Fluidic Diode to qualify the representative technologies for use at B fields. The very purpose of this flow control device is the extension of well life due to deferment of water and/or gas production prior to water and/or gas breakthrough occurs. Flow performance tests are used to measure the performance of these various flow control devices at representative downhole conditions. The comparative analysis was primarily based on elapsed time comparisons for water/oil ratio (WOR), gas/oil ratio and water cut and sensitivity to historical drawdown, productivity index and production cumulative performance. To reduce formation damage and screen plugging effect in these horizontal section, appropriate fluid conditioning, fluid displacement, filter cake breaker system and compatibility between screen and the fluid in which the bottom hole assembly (BHA) will be deployed are discussed in this paper. The gas-water-control completion using AICD technology is predicted to provide significant benefit during the field development with incremental oil recovery around 10-40%, allowing well production with low water and gas production.