bluuebunny/crossref_metadata_2025 huggingface dataset:
The Method of Directional Radial Drilling of Channels for Stimulation of Oil Rims
Authors: Galas Ilya , Bashirov Ayrat , Makarenko Vitaly , Miftakhov Salavat , Lyagov Ilya , Dolman Lee , Gulyaev Danila , Nikonorova Anastasia
Published: October 2022

This paper presentsan effective EOR solution for the development of oil-rim deposits. A case history is presented where production from a mature field with low permeability terrigenous reservoirs and nearby water and gas-cap was recovered without the drilling of new infill wells. Fracking in such conditions was not appropriate due to the close proximityof the gas cap. Directionalradial drilling was used to accurately drill four channels in the required azimuthal directions before slotted liners were deployed in each channel to control solids production.

The directional radial drilling technology is unique and creates channels with a diameter of 69 mm (2-3/4") and a length of up to 25 m (82 ft.) through the identified target zone in the reservoir. The special bottomhole assembly (BHA) is deployed on jointed pipes using a standard workover hoist. The stimulation method drills up to 4 hyper-short-radius channels from the same TVD, and formation evaluation measurements can be taken in each channel. Slotted liner or screens can also be deployed if required. This technique is ideal for thin low permeability reservoirs of any type.

A candidate well was identified and four channels with a diameter of 69mm (2-3/4") were accurately placed at the same TVD along a pre-set trajectory in a radial pattern up to 14 m (46 ft.) per channel using a BHA with a mud motor. The planned-versus-actual trajectories were confirmed by a directional survey. A sand screen was deployed in each channel to control produced solids. The resultant performance of the target reservoirs was evaluated by the results of logging (inflow profile). An 898% increase versus the pre-operation production rate was achieved. A production rate with a liquid flow of 673 bbl. per day and an oil flow rate of 252 bbl. per day was obtained. Further reductions of water cut from 56% to 1% during clean-up, and the oil production rate was increased to 598 bbl. per day from the original 60 bbl. per day. The longevity and value of this EOR method is demonstrated by >16 months decline rate to return to initial production rates. The experience demonstrates that the technology is a very valuable stimulation method where gas cap and/or underlying water create challenges to conventional stimulation or infill sidetracking.

This was the first occasion this unique Directional Radial Drilling EOR technology was applied on an oil deposit in a terrigenous reservoir. Additionally, this was the first-time the radial channels were linedwith sand screens. The operation performed has proven that the technology of directional radial drilling is an extremely valuable EOR stimulation technique for oil wellswhere standard hydraulic fracturing is restricted. This technique is valid for and applicable to all reservoir types.
A World First Innovative Hybrid EOR Pilot in a Giant Carbonate Reservoir in Abu Dhabi : Pilot Design and Field Deployment
Authors: Bhushan Yatindra , Igogo Arit , Al Baloch Shahid , Al Blooshi Mohamed Abdulla , Khan Sara Hasrat , Chappell David , Brodie James , Al Tenaiji Aamna , Al Ali Mona Yousif , Xu Siqing , Masalmeh Shehadeh
Published: October 2022

Simultaneous injection of miscible gas and polymer (SIMGAP) has been proposed as a technique for improving sweep efficiency of miscible CO2 in a giant heterogeneous carbonate reservoir (B) with harsh conditions of high temperature and salinity in Abu Dhabi. A pilot is planned to evaluate the concept. Reservoir simulation models were built to design the pilot and to evaluate field-scale deployment of SIMGAP, assuming the pilot is successful. This paper describes the pilot design and the workflow used to assess large-scale deployment.

Reservoir-B comprises of two main units, Upper and Lower, which are in hydrodynamic equilibrium but have large (10-100) permeability contrast, due to which, water injected into the Lower unit rapidly crossflows into the Upper unit bypassing significant volumes of oil in the Lower unit. Hence, the Lower unit forms a key target for enhanced oil recovery (EOR).

In the SIMGAP process, miscible gas (CO2) is injected into the Lower unit and polymer solution is simultaneously injected into the Upper unit. Provided the polymer solution generates sufficient resistance to flow in the Upper unit, crossflow of CO2 is suppressed, and the Lower unit is efficiently swept by miscible CO2.

A SIMGAP pilot has been designed, consisting oftwo central 3000-ft horizontal injectors for polymer injection in Upper, and CO2 injection into Lower unit respectively and two 3000-ft horizontal producers in the Lower unit 250m from the central injectors on either side. Reservoir sweep will be determined by repeat logging of vertical observation wells and the polymer solution in the Upper unit will be sampled to confirm in situ viscosity.

A reservoir model was built and calibrated to field behavior to design the Pilot.The relevant design parameters include offtake rate, polymer and CO2 injection rates, polymer pre-flush and polymer solution concentration and viscosity. A key prerequisite for proper modelling of SIMGAP is to have a static model that captures the geological heterogeneity (e.g., vertical permeability contrast, all prevailing rock types) and a dynamic model that incorporates the SCAL derived capillary pressure (both drainage and imbibition) and relative permeability curves. The model forecasts show that significant sweep of the lower zone is achieved with SIMGAP compared to both water or gas injection and that the process is stable and robust to lateral and vertical reservoir heterogeneities.

The SIMGAP process has never been piloted and it involves a hybrid of two EOR techniques CO2 injection and polymer flooding in harsh conditions of both high temperature and salinity. In addition, field deployment of SIMGAP was directly simulated in the sector models. The resulting field profiles were used to evaluate SIMGAP deployment in Reservoir-B.
Drilling in Area of Unstable Shallower Formations Prone to Rig Pad Subsidence: Turning the Impossible to Possible
Authors: Zahoor Ullah Syed , Ruzhnikov Alexey , Al Fakih Abdulqawi
Published: October 2022

Some of the oil and gas fields in the in Middle East are prone to a shallow sand subsidence while drilling conductor and surface sections, which may result in the in cellar and surrounding area to subside. In the worst case scenario, it may lead to a well abandonment. This issue is known locally as a cellar subsidence or sinkhole and carry high severity risk. Considering the out of proportion risk, drilling engineering team of project formulated an out of the box solution with enough contingencies to cope with this risk and drilled subsequent wells successfully.

The task of sinkhole prevention and mitigation plan was divided in three phases. In first phase, its risk level was identified by generating a risk identification map of the field after analyzing almost all the wells (more than 500 wells) drilled. After identifying with help of this map that sinkhole risk exists mainly in specific areas, temporary plan was not to drill in this high-risk area of +/- 2 km2. However, it left this area of the reservoir undrained which was not acceptable to reservoir development.

As neither leaving the area of the field undrained nor abandoning the wells due to ground subsidence was sustainable, the task was taken to the next phase to formulate a plan to make the drilling possible in this area or similar areas in this field or other fields. As such based on investigative analysis of all the previous incidents, the engineering team proposed a structural approach for an innovative and vigorous plan along with risk assessment and complete scope of contingency measures. This included pilot hole drilling, changing drilling fluid system, drilling parameters, identification of early signs of the risk, changing casing seats, utilization of casing while drilling and a pre-defined strategy to optionally cure losses based on depth of losses. Following the identification of the structure of the plan, a detailed procedure with specifics on fluid properties, expected rock behavior during drilling, detailed contingencies and flow charts were developed.

With this plan, subsequent wells were drilled with 100% success, in high risk zone of sinkhole where the plan was further updated with lessons learnt on well by well basis.

This unique technique which included more than one measures targeting each specific aspect of cellar subsidence mechanism, is adopted for the first time. Considering its success rate, it can be adopted in any other project, where similar situation is faced.

This paper provides of details including mechanism of sinkhole, severity of risk, conventionally attempted unsuccessfully prevention attempts, newly developed strategy followed by its successful applications and lessons learnt.
Implementation of Advanced Bit and BHA Design Software for Drilling Performance Improvement in Offshore Abu Dhabi
Authors: Yudhia Denya Pratama , Choudhry Bilal Iftikhar , Singh Roopinder , Salas Juan Del Alvarez , Rabis Philippe , Couzigou Erwan , Al-Marzouqi Adel , Al Ameri Fahed Salem , Ayadi Mohamed Selim
Published: October 2022

This paper seeks to address the challenges of BHA dysfunctions in complex wells’ environment which impacted the drilling performance in Abu Dhabi Offshore. Drilling operations experienced various cases of BHA failures, which triggered the need for advanced tools to enhance the bit and BHA design analysis during the well preparation phase. Market research was conducted to identify the commercially available software for bit and BHA design analysis. It is to enable a systematic in-house analysis of the bit and BHA proposed by the service providers to ensure the directional drilling and performance goals can be achieved. A specific drilling software was identified as a fit-for-purpose solution. It offers 3D mechanical modelling of any directional system, sensitivity analysis on multiple BHA settings, hole characteristics, and operational parameters driven by a fast-numerical methodology. The acquired software package includes several key modules: BHA pre/post-analysis, PDC bit model, local doglegs, and vibration analysis. The plan was then put in place to enable implementation across fields. In-house training was conducted to introduce the software to end users. Data gathering for PDC bit and RSS modelling was conducted in collaboration with the service providers. The BHA pre-analysis workflow was then defined to enable comprehensive bit and BHA modelling analysis, covering directional drilling analysis and vibration modal analysis. An agreed BHA configuration and stabilization was identified, and boundaries of optimized operational parameters were determined. Drilling operation was then executed with the agreed bit and BHA following the recommended operating parameters. In after, the BHA post-analysis was conducted to calibrate the PDC bit and RSS modelling by utilizing real-time data and directional drilling information. It also captured the lessons learned for bit and BHA design future improvements. The workflow was implemented for 22 drilling BHA in 2021 with most of the focus in 6″ hole section, long lateral drain application. The BHA performance evaluation of the 6″ hole section demonstrated the improvement result, with 10 out of 12 BHA achieving the objective to complete the section in 1 run. The BHA specific polar plot and RPM driller roadmap provided in this analysis functions as a practical guide for BHA analysis during well preparation and execution.
Transforming Production Phase WIMS to a Game Changer Smart Well Integrity Monitoring System with Real Time Automated Engineering Analytics
Authors: Jasem Mohammed , Fabian Oka , Dawson Graeme , Silari Madhukar , Al Junaibi Bader , Challagundla Srinvisa , Noble Steven , Al Sawadi Obadah , Rodriguez Jose , Mylnikov Pavel , Ge Haoyou
Published: October 2022

First implementation of a new well integrity management solution with integrated and automated workflows, the Well Integrity Management solution (WIMS) that helps company to minimize risks and production loss by the real-time monitoring of the operating limits of sour gas wells. Leveraging digital twin technology, the new software enables engineers to rapidly identify high-risk wells, take corrective actions faster, and mitigate issues to maximize well availability.

Previously, the process of monitoring well integrity was based on the multiple software applications which is time-consuming. To address the challenge, we developed a WIMS coupled with the well engineering analysis approach. The system achieves the following: Representative and accurate well barrier equipment inventory for the entire asset.Safely operate critical HPHT wells to their maximum potential,Eliminate critical and costly barrier failures while minimizing production interruption through automated workflows and alert triggers,Free SMEs to perform critical well integrity management tasks, including technical reviews of sensitivity analysis that determine more accurate MAASP/MAWOP values,Track corporate KPIs and report regulatory requirements effectively.

WIMS integrates source system for the well engineering applications. A first-of-its kind, WIMS uses Real Time engineering analytics and artificial intelligence to run as a Digital Twin for well's Operating Limits and diagnoses potential failures. It also measures, reports and displays most realistic well integrity status for the wells, based on company well integrity standards, processes and best practices. This paper details how we were able to successfully address these challenges which encouraged us mutually to work towards further integration with engineering tools and more automation of WIMS processes.

Important Note: All well data, engineering analysis, operating limits and well information etc., displayed or referred to in this publication, are not necessarily actual and only used for illustration purposes.
Technical Feasibility of a Through Tubing Circumferential Zonal Isolation Gamma Scanner for Plug and Abandonment Implementations
Authors: Inanc Feyzi , Jones Allan , Yuan Peng , Anniyev Toyli , Kverneland Johan , Chuilon Pierre
Published: October 2022

This paper presents a feasibility study of a novel nuclear sensor design toward finding volumetric flaws in cement behind two or more tubulars in a wellbore. The sensor concept targets plug and abandonment activities and the presented results include experimental test setups built for the purpose, results of simulations and experiments conducted for determining the range of applicability.

The measurement is based on a gamma-gamma measurement concept that incorporates a rotating interrogating beam illuminating the wellbore for an azimuthal scan while the tool is in motion in the borehole. The radiation source is a conventional Cs-137 radioisotope emitting 662 keV gamma rays that can penetrate through two metallic tubulars to reach the cement. The detector is a gamma detector that is collimated to accept gamma rays from the volume illuminated with the gamma rays and centrally positioned in the tool body. The detector collimator rotates in synchronization with the rotating interrogating beam providing an azimuthal scanning capability.

The feasibility of the concept was initially tested through simulations that provided encouraging results for detection of volumetric flaws in the cement between the outer casing and the formation. This was followed by experiments that were conducted using synthetic test formations embedded with various volumetric cement flaws. The rock sizes were representative of infinite rocks encountered in typical logging runs. The experimental setup provided not only different flaw sizes but also different tubing positions inside the casing annulus. A generic gamma-gamma tool was run vertically in the synthetic rocks without a tubing and with a tubing in place. The vertical runs were repeated around the borehole and images were formed. Another mode of experiment was conducted by rotating the tool around its axis. The motivation behind this was to study the azimuthal response of the gamma-gamma scanner in an eccentered position. The results from the experiments were in line with the simulation results confirming that it is possible to detect volumetric flaws in the cement between the outer casing and the formation.

This paper demonstrates a method for detecting cement flaws that is pivotal in plug and abandonment activities. Different measurement techniques are usually sensitive to different flaw morphologies. While nuclear methods cannot detect micro-channeling, they can be very efficient in detecting volumetric flaws in cement. In contrast, such flaws cannot be efficiently detected by other measurement techniques. The results presented here show how a gamma-gamma measurement can be used to detect and characterize volumetric cement flaws that can be encountered in multi-annular completions.
Development of a New Reservoir Drilling Fluid to Achieve Matrix Injection
Authors: Morrison Alexandra , Biyani Mahesh , Kadam Sunita , Bose Sohini , Zhou Bill
Published: October 2022

Injector wells comprise a small portion of the wells drilled globally; however, they pose unique drilling fluid challenges. Required for pressure support and production maximization, these wells can be costly if the desired level of injectivity cannot be achieved without first flowing them back. Traditional drill-in fluids (DIFs) contain starch and xanthan, the latter is known to impair injectivity due to its poor acid solubility. This paper describes the development of an aqueous reservoir drilling fluid targeted for injector wells.

A brine-based reservoir drilling fluid was designed and developed utilizing a novel dual-functional xanthan-free additive to provide the necessary rheological and fluid loss properties without impairing injectivity. A thorough qualification was undertaken to evaluate fluid performance under a variety of conditions. Properties investigated included rheology, static-age stability, fluid loss, lubricant compatibility, and contamination susceptibility. A delayed-action filter cake breaker fluid was also designed and tested for suitability with the new reservoir drilling fluid. Return injectivity measurements were performed on both aloxite discs and core plugs to simulate the ability to achieve matrix injection without flowback.

The novel additive provided excellent rheology, suspension, fluid loss control in the reservoir drilling fluid tested in the laboratory. Return injectivity testing demonstrated that the new DIF significantly outperformed existing fluids that contain xanthan or diutan without adjusting the delayed-action breaker formulation. The rheological performance of the new fluid was found to be stable and can be adjusted either though the novel additive concentration itself or through particle size optimization. Evaluation of the spent filter cake breaker effluent demonstrated that the novel additive was fully degraded, as compared to the traditional DIF in which an iodine test indicated the presence of whole starch persisting after several days contact with low-pH breaker.

Existing DIF solutions function adequately for oil and gas producing wells given the low lift-off pressure resulting in minimal impairment to productivity. When considering injection wells, superior performance was achieved using this newly developed DIF which provides the potential to reduce well construction costs by eliminating the requirement to flow reservoir fluids back to a production facility before injecting.
The Sensor Ball Revolutionizes Wireline Operations
Authors: Al-Hajri Nasser M , Ureiga Sulaiman T , Javed Muhammad Imran , Alqarni Hassan S
Published: October 2022

This paper will share production engineering perspectives on the deployment of the sensor ball technology. The sensor ball is a new integrated production logging platform that was developed to measure primarily wellbore downhole pressure and temperature. The reduction in size of the innovative tool sensors has enabled packing of the tool in an attractive wireless manner. The sensor ball records wellbore data and stores collected data on electronic memory chips. The scope of this paper is to explain the working mechanism of the technology and outline the proper methodology for deployment by recapping the operational events of a successful sensor ball field trials on two water wells.

The sensor ball is deployed and collected from the wellhead tree cap in a carefully designed sequence of operational steps to ensure no damage to the tool or tree valves can take place. The sensor ball has dissolvable weight element that allows for the tool to descend to the target measurement depth. The tool is made from material, with a specific density, that allows for buoyancy floating in water after the release of dissolvable weight. Conventional wireline gradient pressure and temperature surveys preceded the sensor ball runs during the trial phase. The objective of the wireline surveys is to provide a basis that qualifies the sensor ball data and quantifies its accuracy with respect to gauge measurements. The developed field trial test success criteria were: Successful mechanical deployment/retrieval of the sensor ball within programmed timeComplete data recovery from the sensor ball upon retrievalAccuracy of recovered data compared to wireline surveys below 5% average absolute error

The comparison results of the sensor ball and wireline data at both water wells showed consistency and accuracy. The average absolute error was less than 3 % for pressure and temperature data. Further, the field trial has met all developed success criteria. The deployment of the sensor ball technology by oilfield operators will enable realization of several tangible benefits such as reducing acquisition time of downhole data compared to wireline and reducing manpower requirements for pressure and temperature surveys. The sensor ball enhancement to manpower requirement can allow for simultaneous data acquisition operations that were not possible with wireline surveys. Oilfield operators can avoid direct costs related to wireline units and associated equipment and its maintenance. Further, the typical mechanical risks associated with well intervention can be eliminated by deploying the sensor ball technology.
An Innovative Wellbore Cleanup Solution for Non-Cemented Lower Completions Saves 27 Million$ in ADNOC Onshore
Authors: Varma Esha Narendra , Mwansa Peter Levison , Husien Mohammad , Bin Bahrom Abdul Raman , Saragi Raymond , BinSumaida Ali Sulaiman Ahmed , Al Samahi Musabbeh Khamis , El Moumni El Walid Ben Mohamed , Al Shamsi Juma Sulaiman , Alshaigy Ahmad Othman , Gaurav Anchit , Abdelhalim Khaled
Published: October 2022

The long-term development of any mature field requires a fresh perspective of long MRC (Maximum reservoir contact) wells and increased well accessibility. To improve well accessibility the deployment of lower completion has been a mandate. Onshore UAE Field demands drilling Slim hole (6″ /6-1/8″ ) laterals and Slim Hole ERD (Extended reach drilling) wells with 4.5″ Uncemented Lower Completion. This paper highlights the innovative wellbore cleanout procedure prior installation of Lower Completions.

Conventionally, using Water Based Mud (WBM) with high friction factors in 6″ Horizontal Hole (HH), two trips were required to reduce the friction factor prior running the Lower Completion. The optimized solution allowed wellbore clean-up and displacement of brine in one trip with drilling assembly (BHA). This innovative technique eliminated one dedicated trip for wellbore cleanout and thus saved millions in CAPEX and Business Plan days.

The T&D data for 5 wells with dedicated cleanout trip were compared to clean-out with 6″ drilling BHA with viscous-lubricated brine. The 6″ BHA was optimized to fit with innovative dormant drilling scrapper and lubricated viscous brine was displaced in the Open Hole. A thorough hole cleaning procedure was formulated and was applied to all the wells.

After analyzing over 5 wells, it was observed that in both runs, the one with 6″ BHA compared to dedicated cleanout-trip, the torque and drag values were similar and the effective reduction in friction factor was similar. This supported the elimination of planned dedicated cleanout trip and saved average 2 days/well and 27MM$ for year 2022.

This optimized BHA design with enhanced hole cleaning procedure was a keystone in deploying slim 4-1/2″ lower completion in WBM system. This practice led to successful deployment of First Slim Hole ERD in UAE with 15000ft of 4-1/2″ lower completion with WBM system. This was a one-of-a-kind achievement in UAE.
Successful First Rigless Fully Retrievable ESP System Installation with Coiled Tubing in West Kuwait: Case study
Authors: Al-Matar Mohammad Ahmed , Al-Haddad Mohammed , Najaf Abdulaziz , Al-Obaidly Mubarak , Slama Hedi , Badrawy Kareem , Mahmoud Wael , Baidas Abdullah
Published: October 2022

As hydrocarbon reservoirs deplete and lose their natural energy to flow, artificial lift techniques become unavoidable to keep wells development plan and sustain hydrocarbon production.

In several cases, Electric Submersible Pumps (ESPs) have become a reliable and important tool in today's global oilfield and inevitably the preferred artificial lift method to keep these wells alive and achieve a high hydrocarbon recovery however, since these pumps incur heavy workover rig interventions, the increased operating cost and the unwelcome disruption to the production operations often lead to an unfavorable profitability contrast for oil and gas operators

With the oil and gas economics nowadays managing the operating cost and decreasing the deferred production is the key elements of sustaining a positive business across.

In Kuwait, nearly 67% of the producing wells are equipped with artificial lift systems as several filed are producing from depleted or sub hydrostatic reservoirs that requires an electric submersible pump to help sustaining the life cycle of reservoir development

In an attempt to slash down the overall operating cost related to maintaining and lowering those Electric Submersible Pumps (ESPs), an alternative deployment option was assessed riglessly with Smart Coiled Tubing thus eliminating cost the heavy rig intervention and operational disruption

A team of engineers were assigned to design and meet the challenges of such an application. The team conducted a detailed and comprehensive analysis of all the risk aiming to deliver an optimal intervention design and procedure to ensure minimum cost.

The intervention was designed to use real time downhole telemetry on coiled tubing through fiber optics to monitor and manage the loads exerted on the Electric Submersible Pumps (ESPs), downhole.

After retrieving the ESP, Coiled Tubing clean out run using high rotating jetting nozzle was carried out on the docking sub of the ESP for the deployment and eventually, the ESP was lastly run and placed at the required setting depth.

This paper describes the successful installation of the first Rigless Fully Retrievable ESP System Installation with Coiled Tubing in West Kuwait.
A New Rigless Approach for Fishing a Stuck and Parted Coiled Tubing in a Live Well
Authors: Allegretti Gianluca , Lerose Marco , Mangione Alessandro , Di Vincenzo Stefano , Luppinan Salvatore , Cervantes Julio , Tarchi Mohamed Lamine , Cerri Paolo , Abid Mohamed Lakhdar , Boyce Robert , Mahmoudi Hadjer , Mebarki Safa , Ahmim Nacer Ridha
Published: October 2022

Usually, the preferred way to restore production in wells with accessibility heavily compromised is by rig workover activity. However, a preliminary approach in rigless mode followed by rig activity can be even more effective in the presence of several critical issues. Here we illustrate the methodology and technical solutions adopted to perform a challenging rigless fishing job to make the subsequent rig workover operation quicker, cheaper, and safer.

A workflow was developed for a course of actions to perform a complex fishing intervention while fully respecting the well control requirements. Considering the well status—1½-in. coiled tubing (CT) stuck in 4½-in. tubing at 7582 ft due to scale buildup, parted in two segments side by side, top of fish at 1345 ft and with no injectivity in the well—it was decided to adopt a fit-for-purpose rigless strategy by combining conventional fishing tools (flow release overshot, continuous cutting overshot) with a CT anchor, which guided the electrical line (EL) cutting tools inside the pipe while keeping it in tension. To accomplish the target, a robust design, with multiple contingency plans was properly defined and successfully implemented. In addition to the main constraint of having a CT pipe parted and stuck in the tubing, the scale deposit prohibited killing the well by bullheading. Consequently, the overall fishing operations were planned and managed as if the well was alive.

The alternate use of CT fishing tools, CT anchor, and EL cutting operations allowed recovering approximately 6958 ft over a total length of 7398 ft, leaving just 440 ft of CT pipe stuck in hole inside the scale deposit (with the new top of fish at 7142 ft). As a result, a complex well situation, which could have led to a long and expensive rig operation, was successfully approached in rigless mode, leaving the well ready for a simpler workover activity.

The use of Continuous Cutting Overshot (CCO), through a standard "cut & drop" approach, was limited by the CT lubricator height. An innovative fishing approach was then deployed: a proper CT anchor BHA, to latch and hang the CT pipe in the tubing wall, was run. The beveled shape of the CT anchor allowed EL tools to enter inside the CT pipe and cut the same above the free point, so recovering longer sections of pipe.
Single-Trip Completion Technology Development for ERD Wells
Authors: Murray Fraser , Wee Keith , Kouadio Yao Fernand , Parihar Shardul , Wills John Andrew
Published: October 2022

A well operator wanted to maximize operational efficiency for extended-reach drilling (ERD) wells of more than 45,000 ft measured depth (MD) by converting from a two-trip to a single-trip completion solution. A safety valve, field-adjustable polished bore assembly (PBA), and production packer were developed for the single-trip completion design used in both the producer and injector well environments. Strong collaboration between the well operator and completion technology supplier resulted in a tailored technology development and validation program that reduced operational risk as much as reasonably practical. The technology developer achieved several significant technical milestones during the process, which are discussed in more detail. A pre-run computational modelling strategy was developed to manage deployment risks and ensure the technology operated as designed. The analysis performed using this strategy, along with details on how this data is used to configure the technology is also discussed. Track record details are provided to demonstrate successful deployment of the new technology in a live well environment. To date, the operator has successfully deployed three systems in wells between 30,000 and 45,700 ft MD. The well operator and technology supplier continue to collaborate on ongoing and future wells, where the developed system adds significant value.
Well Completion Design Integrity Evaluation Including Thermal and Stress Analysis for Multi-Zone & Multilateral Well Completions
Authors: Shahreyar Noman , Butler Benjamin , Al-Sheyrey Hussain
Published: October 2022

This paper provides an overview of an analytical method to assess tubing loads, design integrity, and buckling behavior under complex mechanical, pressure, and thermal-loading conditions. The methodology uses a proven tubular design and stress analysis software, applied to a multi-zone intelligent completion and a dual string TAML level 5 multilateral well. Tubing load scenarios are evaluated in separate phases of the completion installation and operating phases. Simultaneous production and injection scenarios are also examined for a dual string multilateral well.

Full well models are created and evaluated, analyzing stress-loading for both well types. Thermal simulation is first performed, followed by tubular stress modeling to guide tubular selection and completion design. Analysis covers completion operations during installation such as packer setting and testing, well operation scenarios such as well stimulation, simultaneous production / injection for the dual string multilateral, and production scenarios for the multi-zone intelligent completion with multi-position Interval Control Valves (ICVs) in various positions.

Results presented show temperature/pressure changes for each simulated scenario and the corresponding load state cases in the modeled wells. Tubular axial loading, burst and collapse limitations, pipe movement and buckling potential are modeled. The resultant forces on completion packers are modeled for the well with the multi-zone intelligent completion. These results are evaluated to select and optimize the well completion design and also identify well operating limits with respect to a set of combined ICV positions during commingled well operations. Results on estimated annular pressure buildup during well operations are also presented with some guidelines on minimizing annular pressure buildup in annuli through mechanical control or well completion landing practices.

This paper provides workflow outlines and results for tubing stress analysis in complex multi-zone intelligent completion and dual completion multilateral wells. Variations in operating temperatures and pressures in such scenarios can place completions in conditions that can exceed design margins that are already limited due to production-casing diameter constraints. The methods and results presented are useful for balancing design-versus-risk for the completion. They can also provide savings by optimizing well design to meet design integrity standards without being overdesigned.
Completion Barrier Glass Plug with Integrated Bypass Sleeve
Authors: Mousa Amier
Published: October 2022

In order to optimize Completion installations by eliminating Intermediate Completion, reducing rig time, and preventing fluid loss, a project was initiated to develop a barrier glass plug with bypass capability. The plug allows self-filling of the tubing while running in hole and circulating of fluid to displace the wellbore. Once the bypass is closed using a pressure key applied from surface, a V0 certified barrier is established.

A glass plug with an integrated bypass sleeve was developed to allow pumping through the plug. To develop the plug, multiple technologies from existing plugs with proven track record were incorporated. To close the bypass sleeve an Electronic Counter system, known as E-Trigger, was utilized. A pressure key is programmed in the E-Trigger Software. Once the pressure key is applied, the bypass sleeve will close. To open the plug, a Mechanical Balanced Counter System was utilized which requires pressure cycles to activate. Once the Balanced Counter is fully cycled, the glass will break and the plug will open.

Utilizing barrier glass plug with bypass capabilities in the lower Completion will eliminate the requirement to use an intermediate completion to isolate the well and displace the well to brine. Once the sleeve is closed it will prevent fluid loss to the formation after placement of the filter cake breaker. The plug can then be used to set production packers hydraulically, pressure test production tubing, and allow for the safe installation of Christmas Trees.

To verify the performance envelope and functionality of the plug, an erosion test was performed where 10 barrels per minute flowrate was achieved for a total volume of 10,000 barrels using water based mud. With the substantial volume pumped, no indication of erosion was seen after the test. The bypass sleeve was then closed and the plug was pressure tested and qualified to ISO 14998 V0.

The current technologies available in the market does not allow for high flowrate pumping and remote closure of barrier glass plugs after the pumping operation. Therefore, incorporating the barrier glass plug with bypass capabilities in the lower completion will result in significant savings by reducing the completion components in the string and reducing rig time.
A Cost-Effective Through-Tubing Gravel Pack Rigless Installation via Intelligent Coiled Tubing
Authors: Badrawy Kareem , Molero Nestor , Kewan Mona , Seoudi Seif , ElKaragy Alaa , Shalaby Roshdy , Desouky Ahmed , Slama Hedi
Published: October 2022

Sand production is deemed one of the major problems in the oil and gas industry. Additional surface equipment is needed to handle the sand returns, bringing on additional costs and disposal difficulties. In addition, among the most common setbacks of sand production is the increased risk of damage to the well jewelry and accessories. For wells that start sand production at a later stage, conventional gravel packing with a workover rig is one of the preferred methods to alleviate the problem. However, availability of workover rigs and project economics have driven operators and service companies in Egypt to explore alternative and cost-effective options.

The novel approach consisted of a rigless intervention aimed to recomplete the well with a through-tubing gravel pack (TTGP) deployed via coiled tubing (CT) equipped with real-time downhole telemetry. The array of bottomhole measurements, annulus temperature, CT annulus pressure, CT internal pressure, casing collar locator (CCL), and axial forces, was leveraged to ensure precise depth correlation and optimal use of the bottomhole assembly and make informed decisions based on the actual downhole dynamics. A high-pressure rotary jetting tool was used in the first CT run to clean out the wellbore and condition the tubulars across the planned anchoring depth for TTGP components.

The candidate well is a vertical gas producer completed with 4 1/2-in. tubing and 4 1/2-in. liner. After the wellbore was conditioned using a high-pressure rotary jetting tool, a sump packer was hydraulically set below the perforations in the second CT run. In the following run, a 200-ft vent screen assembly was connected and then hydraulically set inside the sump packer. The CT string was retrieved to surface upon confirmation of proper setting of the vent screen assembly, and the gravel pack slurry was bullheaded from surface. Excess sand was removed in the fourth CT run, followed by retrieval of the vent plug from the top of the screen assembly. An upper packer was connected to the screen assembly in the next CT run, and then hydraulically set in the 4 1/2-in. liner. Finally, the well was kicked off using nitrogen and then evaluated using a complete surface testing package. The target production rate of 11 MMscf/D was achieved, which represented a 55% improvement with zero sand production on surface. Now with over 2 years of production, the well is producing an average of 10 MMscf/D and maintaining zero sand production.

This enhanced TTGP conveyance approach represents an effective and economic solution to remediate wells compromised by sand production where conventional workover rig methods challenge economics. This technique greatly relies on CT real-time downhole measurements, and operators from the Middle East and across the globe can benefit from the experience gained in Egypt from this project.
Case Study of the First Large Bore Remote Open Fluid Loss Control Device Compatible with all Multilateral Well Levels
Authors: El-Mallawany Ibrahim , Normand Marc , Bernal Ricardo , Shukor Arrauf
Published: October 2022

The first large bore remote open fluid loss control device (FLCD) presented in this paper was developed specifically for a tri-lateral TAML level 4 well and then successfully trial tested. Multilateral wells with limited or no pressure integrity at the junction add additional challenges in regards to the design of a fluid loss control device. In those applications, positive pressure cannot be applied against the junction to remotely open the FLCD. Moreover, depending on the final multilateral completion deployed, the access to the FLCD installed in the laterals may be prevented like in the case of the monobore intelligent completion reviewed in this paper featuring inflow control valves (ICVs) across each lateral entrance. Therefore, retrievable FLCDs cannot be used in those instances and the required interventions would add rig time and cost. Alternatively, treatment with Hydroxyethylcellulose (HEC) pills and/or loss circulation material (LCM) can cause skin damage to the reservoir that can affect production negatively. All these requirements were considered to design the FLCD technology presented in this paper to make it compatible for any TAML level in a multilateral well.
First Application of Intelligent Gas Lift System in ADNOC Offshore Field to Improve Profitability Through Enhanced Gas Lift
Authors: Wang Zhihua , Wills John Andrew , Faustinelli Juan , Abdulhai Walid , Faux Stephen
Published: October 2022

Gas lift is one of the most crucial components for achieving and maintaining the production targets in a giant offshore oil field development. All producer wells are completed with gas lift mandrels (GLMs) using both dummy and tubing pressure shearable valves to accelerate and enhance efficiency of the initial unloading and gas lift start up. The gas lift designs are optimized considering reservoir conditions and surface constraints over the well life cycle. However, once the GLMs are installed, the gas lift optimization would require intervention work, hence production interruptions. To maximize the gas lift performance and minimize the intervention work, a digital intelligent gas lift (DIAL) system was trialed.

Once the system was selected, a comprehensive design review was conducted covering product qualification, material suitability, factory acceptance testing, and technical limits in both initial installation and well life cycle operation. Detailed pre-installation preparation such as system integration testing and installation procedures were prepared. Four DIAL units were installed successfully in a record extended reach drilling (ERD) well together with 4 conventional GLMs along with dummy valves, as contingency. The system was successfully tested during nitrogen unloading operations which not only demonstrated the functionality of the equipment, but also the increased efficiency of the use of the system.

It is estimated that the use of DIAL in this pilot well will result in substantial net present value generation based on the elimination of well intervention related cost to service gas lift valves, avoidance of production deferral, and production gain resulting from optimized real time gas lift operations.

Each DIAL unit has built-in pressure and temperature sensors and adjustable size orifices. This allows the operator to manage the evolving well and reservoir conditions by applying data driven decision making and surface control during well unloading and production to enable the optimum gas lift injection rate and depth to maximize production. This is all able to be accomplished without the need of wireline intervention for valve change out. This process is repeated until gas reached the deepest valve. Additional benefits of using DIAL system in gas lift operations, as compared to conventional systems, will be described in the paper.

The first DIAL system was installed in one of the top 10 globally longest ERD wells containing the largest DIAL system ever mounted. The paper will describe the brief history of artificial lift strategy for the field and current practices, drivers for trialing DIAL, the equipment qualification process, installation overview, and finally ultimate benefits seen in the initial unloading and gas lift operations.
Depth Surface Update Using Velocity Model Integration Workflow
Authors: Al Anbouri Buthaina Abdullah , Hodgson Linda , Al Anboori Abdullah , Cook Peter , Al Rashdi Khalil
Published: October 2022

This paper describes the workflow to derive a robust depth reference case map and associated depth uncertainty range suitable for use in the planning of new wells and for ‘gas in place’ calculations. DGI's Covizsoftware was used to deliver this objective. A number ofseismic and well velocity inputs and seven methodologies were tested withPre-stack depth migrated (PSDM) interval velocities chosen as the most reliable for geologic top prognoses (based on drop-out test results). All other methods were used to frame the uncertainties around this reference case. This methodology was tested in the recent ABCXX8 well with a resultant depth prediction error at the reservoir level of 0.5%. However, it should be noted that distance from nearest control point is a crucial factor in the prediction of depth and corresponding depth uncertainty. Further updates of the calibration model will be made with an upcoming regional well trade and the latest wells on the block. Covizallows rapid updating of the model with any new information.
Data Visualization Workflow an Alternative Procedure to Quality Check Static Grids
Authors: Contreras Perez David Rafael , Almehrzi Amal
Published: October 2022

Static grids are commonly an ensemble of millions of reservoir property values. Analyzing this vast dataset is a challenging task and is usually performed via simple statistical parameters (e.g arithmetic mean and standard deviation). The objective of this paper is to present a quick and efficient way of analyzing static model realization results in a more visual, interactive and efficient manner allowing a multidisciplinary team to absorb information and key ideas quickly.

The proposed methodology starts with a set of properties from a given static grid realization. The data are prepared with all necessary labeling and categorization to be analyzed (e.g. reservoir and segment indicators, well regions etc.). All kinds of data variations available in the static model are gathered and mobilized into dynamic data dashboards for further analysis. The interactive data visualization templates provide flexibility to filter information either by categories or data ranges. The filtering schemes are immediately propagated to all available plots in the dashboard highlighting common patterns from all the data relationships in the static model.

The principle output from this methodology is an interactive data visualization panel that displays all necessary infographics related to reservoir data-trends. Starting from simple rock quality pie-charts, which can be mapped showing field-wide trends, porosity-permeability plots, to more detailed infographics of property ranges per well/reservoir indicator as well as summary tables of average properties per reservoirs/layers/segments etc. The ability to have all plots linked in a single display provides a simple but powerful platform to evaluate and interrogate data from the static grid using different views. Data can be aggregated in different ways and summarized accordingly. With this continuous process of data filtering, it is possible to quickly identify outliers and collect evidence of data inconsistency within the static grid. The additional value of the presented approach is the ability to compare multiple property realizations in a single template and summarize similarities and differences between different static realizations.

The implementation of reservoir property dashboards proved to be an effective practice to increase the understanding of distributed properties inside static grids. A more comprehensive and detailed data quality check can be performed in multiple properties using a single view of the structured dataset. Additionally once data is loaded into the data visualization platform it can be easily shared with team members without the need of any specialized modeling software.