The scope of this paper is to discuss and compare the different milling strategies of the frac plugs associated to hydraulic fracturing operations in both, vertical and horizontal gas wells, with formations depleted in Petroleum Development Oman (PDO); the main objective is to describe milling operations and the well delivery improvement by the optimization of clean out and milling strategy. The paper will show the enhancement of the milling operations and the outstanding results. The paper will start by describing the execution of hydraulic fracturing operations in both vertical and horizontal wells, which is mainly related to plug and perf. It will also cover clean out and milling practices for frac plugs in depleted formations. Further, it will discuss the planning and design of the post frac clean outs and milling jobs based on the learnings previously captured. Frac plugs milling operations have been successfully improved in severe depleted vertical gas wells and some horizontal wells with no severe depletion; initially the milling operation was done after all frac stages were completed in depleted wells, out of the critical path, however the experience showed that it was a lengthy and expensive process due to the severe formation losses while milling leading into a very low efficient operation impacting the frac well delivery. The subsequent step was to address the milling after every stage, during the critical path, which increases the cost of daily frac charges. With the use of an innovate downhole technology the milling strategy was changed and optimized showing outstanding results, milling frac plugs was achieved successfully at the end of the job in horizontal wells while in some previous wells the milling was done in between the stages; also for vertical depleted gas wells, fracturing stages have been combined to mill frac plugs together. The completion of the entire wells (well delivery) was achieved in a relative shorter period of time compared to previous wells; this is reflected on actual cost reduction of more than 20% of total cost/AFE The optimization of the frac plug milling operations is a novel approach to enhance hydraulic fracturing and well delivery in depleted gas wells in PDO, this is in alignment with the continuous improvement (CI) ideas and the lean thinking across the oil and gas industry nowadays. It is easy to replicate in other gas fields expected to be depleted, which will reduce cost, Health, Safety & Environment (HSE) exposure and will help increase the recovery of hydrocarbon reserves.

Drilling wells in some locations in the Greater Burgan field in Kuwait, can demonstrate significant challenges across the intermediate section. Part of these challenges are combining the carbonate formations with the weak unstable Ahmadi shaley formations at the bottom of the section. This makes it challenging to drilling engineers and difficult to balance between natural mud losses across the carbonate formations and weak shale that requires higher mud weight. Adding to these challenges, the limited surface locations in the field, that forces the well design trajectory to be deviated, which makes the mud window even smaller and shifts it higher. Zonal isolation across this interval adds an additional challenge, as it will prevent gas and liquid to escape from high pressure deeper zones to shallow lower pressure zones and probably to surface, which potentially may cause well integrity issues in the future. This paper represents a case of formation collapse on a casing prior to cementing operation, how it was detected, how it was handled and how successfully the well was completed.

Loss circulation is encountered frequently while drilling fractured carbonate reservoirs in specific field. The field practice was attempting to cure losses and if incurable, drill blind to total depth (TD) followed by run and cementing of the liner. The interval from loss zone to liner top was covered by the cement squeezed from liner top. The require time to try to cure the lost circulation zone plus squeezing cement job was approximately 15 days. Several optimization initiatives were implemented to reduce this time to less than seven days. There were at least eight round trips carried out in different ways by different operators to complete the operation of attempting to cure the losses and a liner top squeeze. The engineering team evaluated this for potential optimization, first to identify whether or not losses need to be attempted to be cured to save the time lost on unsuccessful attempts. Second, to analyze the lessons learnt and build on that optimization strategy to reduce the number of trips Lastly to rework the cement slurry design to reduce the number of attempts to squeeze liner top. As such a detailed strategy was formulated regarding when and how to cure losses followed by an optimized procedure for liner top squeeze which saves three round trips. Further, the liner top squeeze operations previously took multiple attempts of squeeze before a successful pressure test was achieved. Based on the lessons learnt, the slurry design was optimized from several aspects including, slurry density, rheology, thickening time and the pumping and displacement procedure was created which helped to reduce the number attempts from six to only one. Another optimization implemented was enabling the loggers perform pressure pass for cement evaluation by the utilization of tractor instead of conventional (Tough Logging Conditions) TLC which not only saved time but also depicted better the condition of cement behind liner. Finally, a robust risk assessment encompassing all possible contingencies for expected issues was incorporated. The optimized liner top squeeze strategy has been implemented at five wells with 100% success, reducing the overall operation time from more than two weeks to less than one week while improving cement quality behind liner to ensure zonal isolation as per requirements. This paper provides details of how the cement slurry, operations sequence and tools selection were enhanced well by well based on continuous improvement. Since cementing liners across loss circulation intervals exists in most of the carbonate reservoirs worldwide, this paper will help to achieve better zonal isolation in losses environment with lower cost and lesser time.

This well was drilled with the objective to support the pressure sustainability of multiple producer wells across Lukhweir-2 formation based on ERD approach. This paper presents the challenges faced in planning and drilling of subject ERD well with a total measured depth of 27,352ft (8.34km) and having horizontal hole of 11,300ft (3.45 km reservoir contact) with directional difficulty index (DDI) of 7.208 using light/slim casing design. Planning of this well started by meetings and collaboration with asset team to a common objective of delivering the longest well across Lukhweir-2 (LK-2) reservoir to support the multiple producers and mitigate all the associated risk by proper planning and drillability analysis such as trajectory design, collision risks, BHA, hydraulics and casing designing. This paper will explain the novel approach of mitigating the challenges faced while drilling this ERD well such as concerns about surface hole drilling (30 deg across interbedded shale formation), challenge in running 7" long liner (>8000ft across multiple reservoir) and overcoming surface pressure and torque limitations while drilling. Results, Observations, This ERD WAG injector well is the first and longest to be drilled with 6" drainage across Lukhwair-2 reservoir from artificial island to have 11,300ft of 6" Geo-Steered Horizontal hole section using Slim Casing design which gives the total well measured depth of well 27,352ft MD / 10,101ft TVD (2.7 ERD H:V ratio) Results from this well have proven that ERD wells with longer reservoir contact have significantly improved well performance, enhanced reservoir management and reduced field development cost. This paper summarizes the practice and technology used to drill successfully the longest ERD / MRC well using slim design practice which includes the utilization of special dope for 4" DP to increase the torque limit, use of special surface equipment called chillers/coolers to over overcome high downhole temperature. This paper will also capture the drivers, selection criteria and lessons-learned over the entire well drilling. The challenges/mitigation explained in this paper will stretch the ERD/MRC boundaries and support engineers to design the complex 3D wells with slim/light casing design and can achieve extended targets with 100% integrity.

Extended reach drilling (ERD) wells involves numerous drilling challenges that in many cases causes cost overrun and delays for such wells. This paper presents a new approach used to drill a 10,000 ft long departure using a slim design to replace the conventionally well design that uses heavy casings. This approach eliminated the 22" hole section and the associated 18 5/8" casing reducing 20 days form the well duration and saving $1 million. Achieving such a long departure requires a shallower kick off and requires building inclination as early as possible crossing reactive shales and need high mud weight to guarantee hole stability. Historically an additional casing string used in order to isolate a loss zone prior to the shale formation to drill it with high mud weight. This approach limited the inclination across shales and penetrated it along with the loss zone in same section by controlling the WBM weight to be just high enough for bore stability and minimizing the loss rate but increasing the challenges in the next sections. Drilling the single horizontal oil producer well started with a 16" hole size, kicked off at 300 ft and built to 22-degree inclination in that section and isolated with 13-3/8" surface casing. A 12-1/4" hole was drilled across the loss zone and reactive shales formation keep the WBM weight as 9.4 ppg (70 PCF) while drilling the loss zone and increased later to 9.9 ppg (74 pcf) prior to drilling the reactive shale where the inclination was limited to 27 degree across it and built later to 32 deg at the end of 12 ¼" hole section and isolated with 9-5/8" production casing.8 ½" hole section was drilled with 12.3 ppg (92 pcf) OBM in order to built 82 deg before penetrating the reactive shale and hold it tangent to cover the maximum departure and built to 90 deg to land in target reservoir with total departure of 10,755 ft and isolated with 8,150 ft long 7" production liner, followed by 4,000 ft 6‘‘ horizontal open hole. This novel light casing design avoided drilling a hole section of 22‘’ and the associated 18-5/8" casing, saving at least 20 days in well duration and nearly $1 million in well cost. The new slim well design explained in this paper, which is used to drill long departure well with 10,000 ft, is the first of its kind in ADNOC Onshore field. It has proved that such long departure wells can be completed with light casing design and achieve 100% integrity.

A multi-frequency electromagnetic pipe inspection tool with multiple transmitter and receiver arrays was designed to accurately estimate the individual wall thicknesses of as many as five nested pipes. The new tool enables monitoring well casing integrity without having to pull out production tubings, therefore minimizing inspection time and cost. This paper demonstrates the performance of the tool using yard mockups with known defects. The principle of tool operation and the methodology for data processing are also detailed in the paper. The tool relies on eddy current principle in its operation. It comprises two sections of transmitting and receiving coil antennas and operates in continuous-wave mode at multiple frequencies. The configuration of strategic transmitter-receiver spacing and multi-frequency operation delivers a suitable range of information to evaluate individual pipes for the majority of well configurations. An advanced inversion-based data processing workflow is executed to estimate pipe parameters, including electrical conductivity and magnetic permeability, wall thickness, and eccentricity. The proficiencies of the technology are confirmed by performing yard tests with two long test mockups. Each mockup has multiple combinations of overlapping and non-overlapping man-made defects distributed along sections consisting of three, four, and five nested pipes, which mimic typical corrosion progression. The measurement data from the mockups are validated against synthetic data generated from a 2D electromagnetic forward solver. Then, a procedure including pipe material property estimation, calibration, and inversion algorithms is performed to retrieve pipe thickness. Results from the yard tests reveal that this tool is fully capable of detecting various kinds of corrosions concurrently across five strings of pipes, even on the outer pipes with high severity. The impact of pipe eccentricity on the accuracy of thickness estimation is also shown by deliberately decentralizing the innermost pipe over a length of the testing setup. The information provided by this tool can improve the efficiency of well intervention operations, especially in areas with high-corrosion rates, and could result in significant cost savings to the operator.

Nowadays wells are drilled deeper, hotter, and subjected to higher downhole pressures making it more complex for completion, deployment of production tools, and to maintain long term well integrity. It is evident that the utilization of downhole data is becoming more important, to optimize production, maximize the recoverable reserves, and to preserve the proper structure of the wells, facilitating their full life cycle until decommissioning. The Energy industry is relying on new technologies to reduce the cost of exploration, production, and maintaining the wellbore's structural integrity for the duration of the well-life as well as the reduction of their decommissioning cost. This paper addresses various new opportunities created by an "integrated" casing/tubing/microsensor technology, and real-time data communication from downhole to the surface. This manuscript will highlight some of the main components of this Novel Autonomous and Wireless Real-time Integrated Monitoring System, which consists of: A smart casing-collar module with an array of various sensors, to monitor casing/cement for the initial state of stress, formation creeping, open annuli and near-wellbore reservoir properties. This information is processed through a short-hop, two-way wireless communication system, for data and command transfer from the casing module to the tubing module, and a wireless power transfer system, to provide power from the tubing-module to the casing-module. An intelligent tubing module deployed near the smart casing-collar module that contains another set of smart sensors for production and annulus monitoring. Interfacing with the casing module is done via the short-hop wireless power transfer and communications system. Included here is a downhole power generator and a real-time wireless communication for data transfer to surface. This provides the end user, the ability of in-situ power generation and real-time wireless data. The abovementioned integrated system is aimed at addressing the entire well-life planning needs, as it can feed the asset management system for production optimization, zonal isolation, P&A placement, casing integrity, formation creeping, reservoir evaluation, and potential decommissioning requirements. Custom-specified systems can quickly adapt and incrporate new features that are of potential benefit to other "industries".

Polymer resin systems have many advantages over conventional cement. Since resins are solids-free particles, they can be used in low injectivity zones such as narrow fractures where conventional cement cannot be squeezed through. Besides, the resins can be used in combination with cement to enhance casing/cement bonding for improved wellbore isolation. To ensure the success of a field application, the lab testing must be performed at downhole conditions. The objectives of this paper are to study the performance of epoxy resins and their curing agents. Also, to examine cement-resin slurry formulation testing and field application. Cement Slurry was designed with suitable rheology and thickening time. This was done by utilizing enough curing agent into the cement-resin slurry. This study also highlights a successful field deployment to cement a 9 5/8-in liner tie-back job.

Cement evaluation data acquired in oil and gas wells for confirmation of zonal isolation, channeling in cement behind casing and well integrity. All available technologies for cement evaluations are primarily measurements of acoustic parameters like amplitude of first arrival, full waveform recording of refracted wave, impedance and attenuation or there a combination. Generally, operationsPetrophysicist, petroleum engineer or service providers are responsible for evaluation of cement bond logs and propose remedial jobs if required. This cement bond log interpretation is quite subjective if performed through pure visual interpretation and its accuracy depends on objective of well, work pressure and experience of interpreter. This paper talks about how ADNOC Onshore has leveraged machine learning (ML) for interpretation of various cement bond logs from several service providers. In green fields, cement evaluation is very important in all new wells to ensure good cement quality and zonal isolation and it is also equally important in in brown fields where 1000s of wells were drilled where well integrity issues are of common occurrence. Major challenges in evaluation are inconsistency and human bias in interpretation and as a result, interpretation may vary from one interpreter to the other. Authors have tested different ML techniques (Random Forest Classification & Neural Net) and smart way of data training. Final recommendation is to use nested models instead of single model. In this technique, input measurements and required solutions will be classified and divided into different classes, a separate ML model will be built for each class and combine all the models to get final cement evaluation and recommendations. Final results include data quality flags, cement bond quality, zonal isolation, channeling, micro annuals, areal cement map (if analyzed field wise), anomaly maps (if analyzed data from offset wells at different times), and recommendation. In this project, a simple easy to use user interface has been developed to browse the cement logs and use the trained ML models to predict the cement evaluations with a click of a button. This ML based cement bond evaluation is proved to be very effective and saved 75% of efforts by operational Petrophysicists. The interpretation accuracy has been significantly improved. This method has potential to be used at rig site. These models are very cost effective with, minimum human bias, and improves consistency as well as independent of wells or type of reservoirs. These models are tested across ADNOC Onshore Wells and can be extended to any well irrespective of geographic locations. This paper discusses machine-learning approach, evaluation of various algorithms and testing results for cement evaluation log from various service providers.

A stiff-string torque & drag & buckling model has been coupled to a 3D meshed casing wear calculation to model the effect of drilling operations on casing wall thickness reduction. Results of the numeric simulation are compared to MFCL for field cases and provide an understanding of possible well integrity issues during the well life cycle. A Hall wear model and 3D rigid stiff string model is used to predict casing wear. Using Wear Factor Coefficients obtained for several hard-banding, casing grade and mud-types, the process was tested against numerous field cases. For each field case, a history of drill string runs were modelled and filtered into operations in which the drill string rotates such as Drilling, Reaming, Back reaming and ROB. Initially, the calliper log was not analysed to ensure the results are non-biased using experimentally found Wear Factors. In a second phase, the Wear Factors were calibrated against the measured calliper log. This paper provides a methodology that was used to successfully quantify the effect of casing wear against numerous field cases. The 3D orientation of the casing wear was found from an un-calibrated MFCL. After calibration of the new Wear Factor, the casing wear can be predicted before and after well construction. When used as a post analysis tool, the methodology helps determine if casing wear was a root cause of loss of well integrity. This process also helps reduce the uncertainty in Wear factor as a major unknow in the contact force, is now properly modelled. When used in a post analysis process, the results where quantitative (groove depth vs 3D orientation) but also qualitative, providing a post-mortem description of the state of the well to operation's personnel. The methodology presented here can be used to both predict excessive casing wear and determine if excessing casing wear was a cause of failure. It can be used to help determine the state of well for workover operations or plug and abandonment operations. Accurate casing wear prediction at planning stage allows the anticipation of costly but fit for purpose mitigation means & measures.

After fast-tracking exploration success into an early production opportunity, Dubai Petroleum Establishment (DPE) recognized directional-casing-(and-liner)-while-drilling (DCWD) technology as enablers to optimizing the full field development of a thin oil rim within an interbedded steeply dipping reef build-up, just below the Nahr Umr Shale. The field development strategy was to land the well as close to the roof of the reservoir as possible and target the attic oil. This required entering the reservoir at higher inclinations and hence drilling the Nahr Umr Shale (cap rock for the reservoir) at more than 80° inclination. The regionally well-known borehole stability issues related to drilling the Nahr Umr Formation at high inclinations (and especially at azimuths that compound issues associated with in-situ stresses) presented a significant challenge for this field development. The objective of this paper is to share an innovative and successful solution which was implemented to mitigate or eliminate the potential issues associated with drilling operations through problematic and unstable formations at high angles (almost horizontal). An extensive engineering process was conducted involving different teams across the operator and the CWD service provider. The process included bottom hole assembly (BHA) drilling dynamics modelling using 4D time-based calculations and the typical drilling engineering calculations (torque and drag, hydraulics, alternating stress, etc.) to enhance the drilling performance during the drilling campaign. As an example, in one of the wells, the team drilled an interval in excess of 1200-ft, reaching the new world-record depth of 12,481-ft_MD, whilst meeting the operator's expectations in terms of rate of penetration (ROP), steerability of the directional BHA (achieving dogleg severity values higher than 4°/100ft), and flawless execution. The paper shows the methodology followed by the drilling team to evaluate the feasibility of the application, the challenges and lessons learnt, and the innovative solutions (telemetry, mud system, logging while drilling [LWD], motor design, underreamers, etc.) which were put in place to optimize the process over the course of the first six jobs in this new field. The DCWD technology enabled the well construction requirement of drilling an unstable shale on a high inclination trajectory (from 60° to 88° inclination), minimizing the stuck-pipe risk and typical unplanned time (NPT) associated with hard reaming, tight spots, and stuck pipe, and eliminating the additional 8 ½-in. hole requirement. The application allowed the operator to enhance the wellbore construction process and eliminated the requirement for an additional short 8.5-in. hole section, which then had to be cased off with a 7-in. liner to isolate the problematic formations. This represents a revolutionary change compared with the way that this challenge has been historically tackled by the operators in the Middle East (including limiting the inclination to a maximum 35°-40° or using oil-based mud [OBM] fluids with extremely high density that increases the chances of losses in the above formations, among others). The potential time savings due to the elimination of an additional interval to cover the problematic shale are estimated in excess of four days. In addition to the time savings, the operator has significantly reduced the associated cost for the BHA lost in hole (LIH) while drilling through the problematic shale without limiting the maximum inclination before landing in the target reservoir. This also creates a positive impact on the directional requirements for the horizontal-producing section (which can now be drilled in either 8 ½-in. and or 6-in. to address reservoir mapping and production conformance requirements).

Reliable cement evaluation is crucial for well integrity and optimal production. Current cement evaluation technologies have limitations and a fundamental analysis is performed to assess neutron logging for this purpose. Basic modelling has been performed to study neutron transmission for several realistic cases including good cement, channeled cement, foamed cement and through-tubing configurations. For a comprehensive review, other aspects such as health, safety and environment (HSE), cost and alternative approaches have also been assessed. Results achieved show that neutrons have the potential to travel to the cement-formation interface and return to the detector without being completely attenuated. For single casing configurations, results indicate that cement channels produce distinguishable results from intact cement. For through-tubing logging it cannot be concluded that detected results are distinguishable. Even though neutron logging itself is likely to be more costly than cement bond logs, potential benefits in terms of other cost savings and decrease in HSE risks must also be considered.

Drilling and cementing operations commonly experience lost circulation (LC), which can result in non-productive time (NPT) and excessive costs. Losses were encountered while performing an offshore workover well operation in the UAE that challenged isolation objectives involving spotting a cement plug through coiled tubing. Selection of lost circulation treatments that may be deployed through coiled tubing is limited, increasing the difficulty in addressing losses. Previous attempts to cure losses and spot the cement plug were unsuccessful. This paper describes the application of a new tailored spacer system (TSS), engineered to reduce formation permeability and prevent lost circulation. Placement occurred through coiled tubing to successfully control losses in the thief zone, enable tagging of cement plugs, and achieve isolation for the zone of interest. The new TSS has been used on multiple cementing operations to mitigate losses, improve circulation, achieve top of cement (TOC) objectives, and eliminate remedial work; however, this case is the first global application of the TSS through coiled tubing in a plugging operation to stop lost circulation. Correctly evaluating and interpreting the well conditions, risk identification, analysis, and communication amongst operations personnel, and execution of good cementing operational practices led to utilization of the new TSS for this specific scenario of placement through the coiled tubing ahead of the cement slurry. Losses were prevented leading to a successful plug operation and enabling cementing goals to be achieved.

The proposal of this paper is to share the knowledge learned in this new procedure and techniques implemented in HP/HT Unconventional wells, created by the Unconventional (UC) Drilling Department at Abu Dhabi which involve around ten different services, where each has a high importance and contribution for the collective success of the well at the moment to frac and hence the feasibility of the project. In order to assure the integrity and accessibility of the Frac String during Plug and Perf hydraulic fracturing operations of one of the toughest rock in Unconventional business worldwide, one procedure has been developed for running operations best practices. Pressure testing the Frac String (FS) during running in hole in stages while in vertical section to sure safe and successful Wireline setting and retrieving nipples plug with more than 30% solids in the system (high mud weight) to guarantee no leak in the string prior reaching total depth (TD). Hanging and testing cross over (XO), assuring compatibility with the wellhead connections. Cementing up to18.7 ppg. Flexible and expandable slurries, cement inside previous casing and apply pressure on surface to avoid gas percolation during the cement setting period. Cleaning out with Coiled tubing (CT) to ensure no obstruction and using different completion fluids for future accessibility. And finally, Pressure testing the Frac string up to 14ksi all are new practices and proven mitigation measures for all assessed risks for hydraulic fracturing operations. This paper is about sharing this new procedure in Abu Dhabi for having a cemented FS in UC wells High Pressure / High Temperature (HP/HT) with 100% integrity and internal accessibility to run plugs, perforations, logs and be able to apply high surface pressure to frac the tight reservoir in the planned zone, creating the desired permeability for future production.

Well integrity management is a prime global focus area for all oil and gas operators. Any field-wide corrosion challenge requires a substantial investment to manage the integrity of assets and, consequently, to maximize life expectancy and efficiency. Over decades, the industry has concentrated its efforts toward containing fluids from any unintentional release at the surface occurring as a result of corrosion. This paper highlights the most recent electromagnetic (EM) logging technology developments to address well integrity challenges. Three primary corrosion mechanisms occur in oil and gas wells: chemical, mechanical, and electrochemical. Electrochemical corrosion is the mechanism responsible for most of the failures in which the outermost casing is exposed to corrosive fluids and is consequently penetrated first. As the corrosion process continues, subsequent well barriers are progressively corroded until the inner casing or tubing is in direct contact with a corrosive environment and at direct risk of a major well integrity failure. As a result of this outside-to-inside corrosion mechanism, the early diagnosis of the outermost casing status is especially important as a proactive measure to identify any potential weak zones in the completion string. This early diagnosis is a major step to optimize well integrity intervention and to optimize workover operations costs. Cathodic protection and coated casing are used to extend the life of the well by controlling corrosion; however, these are only mitigation measures that slow down but do not eliminate corrosion. EM logging technology provides an effective method for monitoring and identifying the effectiveness of these corrosion mitigation measures. Time domain EM pulse eddy current (PEC) technology has facilitated corrosion evaluation by logging through tubing, thereby avoiding the cost of pulling completions solely for surveillance purposes. The latest EM PEC technology, the enhanced pipe detection tool (ePDT), provides individual barrier thickness measurements for four concentric pipe strings. The innovative features of ePDT include: (1) A fractal transmitter (Tx) coiled array that improves the performance of the tool with enhanced signal-to-noise ratio (SNR) covering a wide signal dynamic range, and adaptability for various logging speeds and spatial resolutions for varying pipes; (2) a synthetic aperture of the receiver (Rx) coil array for noise compensation from extraneous tool motion; and (3) a wide-spatial aperture Rx coil array which, when combined with (1) and (2), enables the compression of the inner pipe remnant magnetization interferences without sacrificing spatial resolution. This paper demonstrates ePDT benefits by benchmarking to other technologies and control environments. The results are discussed in detail to provide an overview of EM technology, as well as the advantages and limitations. Ultimately, the answer product from this technology is integrated with other current and historical information related to the well or field being evaluated as part of the well integrity management system (WIMS). Finally, it is important to expand the technology operating envelope beyond the standard applications to address larger completions challenges, such as gas wells and landing base inspection, by extending the tool capabilities while optimizing data acquisition and processing methodologies.

This paper discusses the designing and field application of a polymer resin-based cement system that enhances the final cement properties in terms of compressive strength and cement bond to the casing along-with minimizing the occurrence of casing-to-casing annulus (CCA) pressure during the life cycle of the well. Several experimental studies were applied to this polymer resin-based cement system including rheology, thickening time test, free fluid test, compressive strength test, etc. The results showed that the polymer resin-based cement has improved compressive strength, ductility, and enhanced shear bond strength. Which, as a result, helps to provide a dependable barrier that would help to prevent future sustained casing pressure (SCP). Besides, the cement slurry was designed with a controlled and engineered rheology. This was done by controlling the amount of the resin and cross-linker into the cement slurry in order to achieve the target density as well as to avoid a sudden increase in the final slurry viscosity that could result in mixing difficulties at the field. Moreover, the field deployment of this system on a 13 3/8-in casing second stage tail slurry has been discussed.

In our plant, sulphur is recovered from gas in Sulphur Recovery Units and stored in Liquid Sulphur tanks, before granulation and pelletizing for shipment. Underground concrete storage pits form an important element of the Sulphur Recovery, Treatment / export cycle, providing an intermediate containment to ensure that molten sulphur temperature is maintained within the operating range. These concrete pits tend to deteriorate rapidly due to high temperatures and contact with concentrated sulphur. This paper discusses the pit design and construction practices, and efficient repair/maintenance techniques of ageing containments to ensure improved service life while optimizing maintenance costs. The structure consists of reinforced concrete walls, base and top slab, which supports the Sulphur transfer pumps and associated piping / instrumentation. At bottom, steam coil system is provided where Low Pressure steam is used as heating medium to maintain molten Sulphur at high temperatures. Primarily two concepts are followed for protecting Sulphur pits: (a) Internal surface lining with acid resistant / refractory bricks and insulation, and external waterproofing, or (b) Externally applied waterproofing and thermal insulation, with no internal coating or lining. Since exposure to high Sulphur concentration and high temperature renders the concrete susceptible to sulphate attack and deterioration, it is essential to carry out periodic inspection and maintenance works in these pits. The top slab is susceptible to higher corrosion due to contact with vapours. Evaluation of existing pits with above designs revealed contrasting conditions. Refractory / brick lined pits indicated severe deterioration of lining, with traces of corrosion in concrete surfaces. Underside of slabs also showed deterioration of tiles, however, slab concrete was relatively in better condition. Unlined pits revealed the concrete surfaces of walls and base slab to be in reasonably good condition. However, underside of top slab was found to have severe deterioration, beyond repair mandating replacement. Physical and chemical tests indicated reasonably good condition of reinforcement steel, retention of concrete strength, and no loss of concrete cover. However, sulphate content near the surface was found to exceed code permissible limits. Repair procedures for lined and unlined pits vary, with primary focus in lined pits being selection of appropriate lining for Sulphur resistance and thermal insulation, while for unlined pits, the main concern is selection of suitable concrete mix design and ensuring proper compaction and curing. Deterioration of concrete in process critical structures like liquid sulphur pits is an important issue, which could potentially impact the Sulphur recovery and export process. Both lined and unlined pits are found to be suitable for the purpose, however, each has its own pros and cons. Maintenance and repair procedures need to be in place specific to the type of design and construction of these pits, to improve service life.

In a green field located in offshore Abu Dhabi, a new well was drilled in an oil-bearing zone and was completed with slotted liner inside a 6-in horizontal drain hole. Abnormally high gas rates were reported during the surface production testing of this well. This paper highlights the unique use of a new pulsed neutron tool combined with an advanced production logging tool for assessment of the well performance and identification of the source of gas breakthrough. This combination of advanced technology tools with measurements from array flowmeters, optical gas holdup sensors, and a new generation pulsed-neutron tool was deployed in the well to provide reliable flow type, borehole, and formation measurements in a gas environment. A multidisciplinary approach involving production engineering, petrophysics, and well integrity was essential in diagnosing this unexpected issue of high gas production. An integration of the various results from production logging, the pulsed neutron measurements, and open-hole and cement log data has helped in confirming the source of the produced gas. The acquired production log (PL) data revealed gas entry from the top of the lower completion and no presence of free gas below that depth. The zonal contributions from the horizontal lateral quantified from the acquired data also helped in assessing the productivity of the reservoir. The pulsed neutron log (PNL) measurements were acquired in the second run, which then helped confirm the borehole fluid properties and to identify and quantify the formation fluids. Combining the PNL and PL data helped identify the gas entry point accurately. Based on the integrated data interpretation, it was confirmed that the gas could not originate from the reservoir being produced through the lower completion and that there must be gas channeling downward through channels in the cement behind the casing from a gas reservoir above the oil reservoir. The unique use of the advanced PNL data and its integration with other log data facilitated the successful identification of the gas source and quantified zonal contributions in a challenging logging environment.

Well Integrity is a major concern and a crucial step during the life cycle of the well. That is especially the case after the Macondo incident that changed the perspective of well integrity and proved how misinterpreting the data can lead to severe consequences to the safety of people, financial and environmental impacts. With the new innovations and technologies that we have nowadays, the oil and gas industry has expanded and entered more complex and challenging environments. The technological development of directional drilling allowed better reach and better oil and gas production from the reserves by using multiple angles while drilling. In Saudi Arabia, thousands of wells drilled each year where numerous cement integrity challenges faced especially in high angle wells. Wireline (WL) developed their tools over many years to provide an advanced assessment for cement bond evaluation with a reliable measurement. However, many local cases where observed where cement evaluation through WL was not a possible option due to some challenges such as well control issues and downhole condition. As a result, we needed to implement an alternative solution that can provide a quantitative cement evaluation through different means to address client challenges in cases where the WL service is not a valid option. Due to the high demand for real-time logging and rig time saving, Logging While Drilling (LWD) expanded its service offerings to address client challenges related to well integrity. In 2004, LWD started to provide top of cement (TOC) service utilizing its sonic tool that indicates qualitatively the presence or absence of cement in the annulus. However recently, LWD developed the first algorithms that delivers a quantitative cement evaluation through an LWD sonic tool utilizing a hybrid methodology. This new approach is a combination of two different types of interpretation which are amplitude-based and attenuation-based methodologies. This paper will present a successful trial test of the quantitative cement evaluation through LWD that was done in Hout Field in Saudi Arabia and verified with conventional WL cement bond log. The results of this test proved that LWD cement evaluation can be a viable alternative solution to running WL logs. Especially when the conveyance of WL is not feasible or even as a cost-effective solution to save tripping time.

To determine which salt-based cement system [potassium chloride (KCl) or sodium chloride (NaCl)] was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. A total of four slurry designs (a lead and tail slurry used on each casing string) was programmed. Each slurry was designed and tested as two distinct systems using KCl and NaCl salt respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. at the 2002 IADC/SPE Drilling Conference (SPE-74500-MS), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. Based on these results, conclusions were then made on which salt slurry system (KCl or NaCl) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a KCl salt-based slurry delivered improved liquid and set properties as compared with a NaCl salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only NaCl salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that KCl salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m [328.1 ft] thick.