bluuebunny/crossref_metadata_2025 huggingface dataset:
Rule-Based Systematic EOR Screening Methodology for ADNOC Oil Reservoirs
Authors: Mogensen Kristian , Al-Keebali Aaesha
Published: November 2019

Many of the oil reservoirs in ADNOC’s portfolio have been producing for decades and continue to deliver their target rates, thanks to development schemes centred on pressure support from peripheral water injection and/or crestal gas injection, where applicable, or from line-drive patterns.

As these reservoirs mature, a number of enhanced oil recovery (EOR) techniques are being evaluated to increase the ultimate recovery factor. Choosing one or several appropriate EOR methods starts with a robust screening methodology, which in this case has to apply across an entire reservoir portfolio, rather than just to a single asset.

The key objective of the screening efforts presented in this paper is to estimate the EOR potential from each reservoir in a systematic manner to allocate the right resources, to the right fields, at the right time, with the right technology. Therefore, the screening methodology must take into consideration the following aspects: The focus of the screening is on identifying opportunities, which are or will become technically feasible by the time deployment is requiredThe screening procedure must remain sufficiently high-level to be able to deliver an outcome within a short time-frameA single EOR method is not necessarily applicable across an entire reservoir; hence several EOR methods can potentially be implemented in the same reservoir but in different areasThe thought process (workflow) has to be properly documented so that the screening exercise can be updated whenever new technologies or new relevant field data become available

The new EOR screening tool considers more EOR methods compared to previous screening efforts: It takes a much broader view on potential source gas options for miscible gas injection, namely enrichment of sweet hydrocarbon gas, sour gas streams, CO2 with or without impurities, as well as nitrogen for some high-temperature reservoirs containing volatile oil. This step involved estimating miscibility conditions for hundreds of combinations of injection gas compositions and reservoir fluids using equation-of-state based MMP calculations in addition to common MMP correlations.The reservoirs are all carbonate formations and are characterized by high temperature and high salinity. These conditions have traditionally been a challenge for chemical EOR methods involving polymers and surfactants. However, recent R&D progress has opened up for opportunities not previously considered. Both polymer and foam agents are currently being piloted, which have the potential to change the EOR landscape in Abu Dhabi and perhaps elsewhere as well.As reservoirs mature and breakthrough of injection fluids begin to occur, the need for improved reservoir conformance becomes evident. The success of any EOR technique relies on the right well placement with the right monitoring in place and the right level of injection profile control.
Integrated Approach for Analysis and Forecasting of Chemical EOR Recoveries in Sultanate of Oman
Authors: Al Mahrouqi Dawood , Farajzadeh Rouhi , Alkindi Abdullah , Rifaat Mjeni
Published: November 2019

Polymer injection in the south of Sultanate of Oman has been implemented in Marmul field for the last decade. Recently, alkaline surfactant polymer (ASP) technology has also been piloted in the field, which was technically successful owing to its significant incremental oil production. The current end-game strategy for the field is to follow polymer with ASP flood in order to produce the remaining oil after polymer flood and maximize the ultimate oil recovery factor. This has revealed the need for evaluation of the full-field performance of ASP flood using available tools. Full-field dynamic models are not always best tools for modeling the performance of chemical enhanced oil recovery, primarily due to under-representation of the reservoir heterogeneity, lack of the complementary data, complexity of the process itself, and large computation time. In this paper, we implement a conduit-model approach using field production data from the ASP pilot to assess the ultimate incremental oil recovery. This approach is compared to an analytical model that is based on the modified Koval's method with reservoir heterogeneity as an input parameter. The obtained results are used for preliminary assessment of the difference between polymer and ASP injection in the full field.
Cost Effective Alternate for Inconel on Sour Gas
Authors: Wolters Roy
Published: November 2019

The challenge with HP/HT sour gas fields is compliance with NACE MR0175 / ISO 15156. Moderate partial pressures of H2S already required Nickel based alloys like Inconel. Since these are high pressure fields this means that low concentrations of H2S results directly in materials with high cost and difficulties to supply the proper quality.

Table A.23 of NACE MR0175 / ISO 15156-3 indicates that for Wellhead and Christmas tree Components and valve and choke components an alternate cost effective material can be used.

Table A.23 shows that 13%Cr4%Ni Martensitic Stainless Steel can be used without restrictions to the H2S level for valve bodies in API 6A wellhead equipment. The cast version of this material is widely available at relatively low cost and without quality challenges thus making projects less challenging.

The material has proven itself in use for valves in high concentration H2S fields. In order to prove the material being fit for purpose a test program was conducted, including sour gas testing and FEA work. This work was included in NACE ballot 2013-03 and the proposed change from that ballot was adopted in the current NACE MR0175 / ISO 15156-3 standard.
Effective Production Network Debottlenecking Analysis by Finding Optimum Choke Size
Authors: Almohammad Humoud
Published: November 2019

Oil wells performance can be determined from completed zone productivity, completion type and size, and surface facilities. A significant surface tool, wellhead choke, can profoundly impact on the well performance. Determining the optimum choke size can result in improving the production of the well by altering the wellhead pressure, therefore the pressure drop. Increasing the bean size above optimum might result in decreasing wellhead pressure below flowline pressure and prevent the oil from flowing.

To determine the optimum choke size for oil well; live trial and error could be helpful, though it is not practical and need to be combined with a well simulation analysis and history matching. A multiphase flow simulator is applied on a set of selected wells, having bottlenecks and backpressure issues in Kuwaiti oilfields. The simulation has been developed by choosing a precise flow correlation that presents a reliable flow behavior and pressure drop results. A comparison of different flow correlations was performed against the actual test readings to eliminate a potential error from the simulation against the actual readings.

Changing the choke bean size was a quick, effective, and economical solution to overcome the bottlenecks and backpressure issues in individual candidates. Simulating the formation productivity and assessing the well performance and changing the choke size can increase the successfulness chance of the live trial and error procedure. It can also help in categorizing the wells whether to be a candidate to have choke size change, or another solution is required to flow the well such as a surface pump, artificial lift, or changing the receiving facility pressure, if possible. All the selected eighteen wells are vertical or slightly deviated with an oil API gravity between 32 and 35 degrees, and the flow behavior correlations were between the Beggs and Brill (1973) empirical correlation and the Ansari (1994) mechanistic model. The comparison between multiple sensitivity analyses proved that both models are reliable and can be applied to the selected field. Simulating the wells had increased the choke size debottlenecking approach successfulness rate by 70 percent, and increase the oil production up to 6,000 barrels per day.

A debottlenecking analysis is presented in this project, and supported with data matching and field test results. The procedure to optimize the choke size is explained in details using a multiphase flow simulator and an in-house developed excel sheet. Several additional approaches were analyzed to overcome backpressure issues, like using ESP artificial lift method.
Building More Accurate Models for Different Reservoir Types using Interval and Interference Pressure Transient Testing
Authors: Zeybek Murat
Published: November 2019

Building accurate reservoir models can be quite challenging, especially highly stratified thick intervals in hydraulic communication in reservoir. Presented methodology is based on comprehensive Interval and Interference Pressure Transient Testing (IIPTT) for classified reservoir types with a systematic approach. Classification of reservoir types is based on layering, thickness, and hydraulic communication of layers in the reservoir.

The methodology describes building more accurate anisotropic reservoir models, providing well performance assessment based on integrated comprehensive IIPTT solving with efficient non-linear parameter estimation and modeling with numerical simulation for different reservoir types. The number distributed IIPTTs are optimized to ensure to achieve coverage across total thickness depending on the reservoir type.

It is demonstrated that high resolution accurate reservoir models can be built for relatively thick highly layered reservoirs in a feasible manner.
When Effective Integration Drives the Development: A Successful Case History
Authors: Spelta Elisa , Caronni Valerio , Carrasquero Gabriela , Catanzaro Massimo , Rossi Massimo , Tagliamonte Rita Leda , Valdisturlo Antonio
Published: November 2019

A robust and detailed reservoir model is an essential requirement when a fast track approach drives the development of a green field. Such a tool can only be developed through the orchestration of Geological and Geophysical (G&G) and Reservoir Engineering disciplines. This integration effort is, first of all, aimed at identifying the key characteristics of the reservoir most impacting its dynamic behavior at different scale and, eventually, at capturing them with the proper modelling approach.

This paper decribes such approach to the case of a complex deep-water reservoir belonging to slope-toe of slope environment. A 3D integrated static model was built by incorporating core and log data, their petrophysical interpretation, a description of the depositional and architectural elements, a quantitative seismic reservoir characterization and the few dynamic information available at this early development stage.

The implemented geomodeling workflow focused on heterogenetiy that could affect reservoir performance such as structural-stratigraphic discontinuities that could act as hydraulic barriers. Facies in the interwell space were distributed by applying seismic-derived 3D trends. Facies distribution eventually provided the framework within which petrophysical properties modelling was performed. During the implementation of this integrated G&G and Reservoir workflow, continuous crosschecks of consistency and robustness of the model led to elaborate the final product.

The resulting reservoir model captured critical uncertainties (e.g. degree of reservoir heterogeneity including stratigraphic discontinuities) leading to an optimized development scheme, that allowed to minimize risks, despite the few data available.
Real-Time Monitoring and Predictive Failure Identification for Electrical Submersible Pumps
Authors: Bhardwaj Abhijeet Sandeep , Saraf Rahul , Nair Geetha Gopakumar , Vallabhaneni Sridharan
Published: November 2019

The maintenance of electrical submersible pumps (ESPs) is a highly capital-, resource-, and manpower-intensive exercise that is traditionally performed by reactive process monitoring of multivariate sensor data. In the reactive paradigm, it is difficult to proactively distinguish between sensor fluctuations, trip events, and failures in real time. This paper presents a real-time alarming system for predictive ESP failure identification by constructing dynamic operating envelopes on real-time sensor indicators using machine learning (ML). This ML model identifies the complex relationships between pressure head, pump losses, and supplied electrical energy. Operating envelopes are dynamically updated and validated by continuously incoming sensor data to provide indicators of ESP trip events. Recommendations for the amount of data required to provide reliable predictions and an alarming system to classify an ESP trip as a failure are also incorporated in the model. The algorithm can identify longer-term trends and deeper functional relationships from historical data, as compared to the traditional engineering approaches used for ESP diagnoses. The new workflow with the predictive model can provide signals two weeks before the actual failure event, as indicated by the traditional workflow. Issues related to sensor data quality, including missing, misaligned, and erroneous data that may result in false positive notifications can be easily improved by incorporating more domain knowledge by subject matter experts and field engineers. The proactive identification of failure events using this real-time alarming system can improve production efficiencies by avoiding deferment losses. It also contributes indirectly by improving, reducing, and automating the time spent in analyzing failure events, such as dismantle, inspection, and failure analysis (DIFA). The alarming algorithm can be gradually incorporated into traditional systems to provide continuous improvements and to add value without incurring the high costs of initial deployment and change management associated with it. This paper presents predictive ML models deployed to analyze real-time sensor data to proactively predict failures in ESPs results. It also provides recommendations related to the use of these workflows to improve operating practices and production efficiencies and to reduce deferment. Similar approaches can be extended to the monitoring of other equipment in real time.
First Dual-Plug Cementing in a 4.5in Liner in Sub-Saharan Africa
Authors: Elizalde Roberto , Drevillon Pierre-Marie
Published: November 2019

Cementing of a casing string or liner is always considered a crucial phase of the well construction process. The difference with the other phases, is that once cement has been mixed and pumped in the well, there is a limited amount of time for operators to take decisions for troubleshooting or surpassing any obstacles encountered, before cement is no longer pumpable, as at such point, decisions become exponentially costlier, and can even result in the loss of the well, or sidetrack.

Steps to mitigate these risks involve extensive pre-planning to identify all possible risk scenarios, and prepare mitigation, elimination and correction methods. Another step is to count with appropriate equipment, backup equipment, and contingency procedures ready to be implemented if required. Decisions such as how much more volume should be pumped if plug bump is not seen, or if volume count should be reset when dart latch is seen, should be reviewed in advance, as a decision-making process cannot take place when the event is seen, as the timeframe to take these decisions are too narrow.

Cementing a liner in a deepwater scenario increases the risks during the operation. Inaccuracies for volume counting during displacement are increased, and in situations when there is a small liner, and the displacement volume is greatly larger than the slurry volume, increases inaccuracies even further. Free-fall of cement is also increased, as a heavier slurry is being displaced throughout a longer interval, until it U-turns at the shoe and is finally placed on the annular space. This also increases the risk of not seeing the dart latch with the plug, not being able to reset the volume count to a more precise volume.

The cementing phase of the 4.5" liner for the Deepwater Total Moho-Nord Albian Project, presented these risks due to the short 4.5" liner interval. The liner interval can be as short as 450 mts of liner length, equivalent to 10 m3 of cement slurry) in comparison with the TOL depth (average 4,100 m MD, equivalent to over 50 m3 of displacement). The risks were increased as the project relies on plug bump to set a series of annular inflatable packers to help seal the formation from water influxes. This meant that if the theoretical volume was pumped and the plug did not bump at the time, displacement had to stop, and the packers could not be inflated. Rotation, which often helps cement placement, was also not an option in this project, as T&D analysis proved that there was a high risk to exceed the torque limit of the liner connections.

All these risks combined, made the cementing operation of the 4.5" liner of the Albian project, one of the most complex and crucial parts of the well operation.
Condition Monitoring of Critical Systems Using Enhanced Partial Stroke Testing Technology and Smart Solenoid Valves
Authors: Harvey Richard
Published: November 2019

Partial Stroke Testing was developed to assist in the management of the performance of safety critical ON/OFF valves. The original systems were developed over 2 decades ago and initially PST was just used to demonstrate that the valve can move off its seat. This was considered acceptable as a means of demonstrating safety valve performance. Systems used for this purpose were generally mechanical jammers. These jammers would take the form of snail cams attached to the valve stem, end stops on the actuator or other similar methods. These were used as there was concern that the valve may close during testing and therefore the mechanical jammer makes it impossible for the valve to close if used correctly. There was no diagnostic capability beyond the operator watching the valve move.

As instrumentation advanced techniques used for control valves were adapted for PST purposes and valve positioners became a common method for PST. The main advantage of these systems was that certain parameters could be measured to control the PST and gain data relating to performance. However, the drawbacks were that additional equipment was required and pneumatic systems need to be changed to accommodate them. Add to that a now increased risk of spurious trips and the roll out of this technology had limitations.

Now as we move into the era of Industry 4.0, as described by Marr, 2018 and analytics the industry is moving again to see how valve performance can be better quantified and how condition monitoring can be used to aid in the prediction of failures and facilitate predictive maintenance. This has led to the development of PST systems that have analytics based on position type data combined with the reliability and simplicity of mechanical jammers.
Enhanced H2S Workflow to Assist in Managing the Sour Gases & Oil Production – North Jurassic Digital Oil Field, Kuwait.
Authors: Al-Mai Noura , Al-Shuaib Muna , Alvarado Omar , Al-Nesef Mohammad , Al-Saleh Alaa , Al-Qahtani Shaikha , Useche Marcos , Franco Francy , Orjuela Jaime , Wibowo Arif , Prakash Roshan , Gornescu Bogdan
Published: November 2019

An improved workflow for handling an excess of Hydrogen Sulfide (H2S) in treatment facilities is presented. The objective is for the selection of wells to decrease H2S production by reduction of choke sizes with the lowest possible impact on oil production.

During operational restrictions in a gas treatment plant, it is necessary to reduce the H2S quantity received at the facility. To perform this operation, an approach is to limit the production from wells with the biggest rate production of H2S (volume); another solution is to restrict the wells with the highest concentration of H2S (% molar - composition); However, both scenarios have an impact on oil production. KOC - KwIDF Jurassic, has developed a procedure that considers the derivative of the produced H2S curve as a function of produced Oil to find the optimal scenario.

The proposed method was evaluated using the results from a sequence of monthly allocations that include characteristics such as: facility, number of wells, and fluid compositions. The data was analyzed applying three methodologies that have different objective functions, such as H2S volume, H2S concentration, and a new criterion called H2SOR. As a result, there were three different way to rank the wells to reduce H2S production. A monthly plot of Cumulative H2S Production vs Cumulative Oil Production was prepared to calculate the derivative of the curve, finding the optimal solution at different levels of H2S treatment restriction. Finally, the economic analysis for each method was also calculated.

H2SOR methodology guarantees the best alternative to ensure the restriction of sour gas rates with the lowest impact on oil production. It also proves to be the best solution from the economical point of view.
Deep Learning for Sand Production Analysis and Optimum Workflow in the Greater Burgan Field
Authors: Al-Rashidi Hamad , Safar Abdul-Aziz , Al-Shammari Baraa , Rane Nitin , Muhsain Batoul , Al-Mutairi Talal , Al-Mal Bader , Al-Kandari Noor , Mohammad Dalal , Duncan Bruce , Al-Saeed Hanan , Desai Sameer , Kamal Mariam
Published: November 2019

Meeting 2040 KPC Strategic plan objectives and KOC production targets will require adoption of new cost-effective technologies and methods in Kuwait fields, resulting in incremental oil production and extended life of the fields. Long-term oil production through artificial lift application can lead to pressure depletion and water cut incremental in mature fields, which can cause obvious wellbore impairments, particularly in medium to week formations such as Wara and Upper Burgan formations.

One of the critical parameters that will have great influence on maturing this strategy is sand management-field development. Recently some of high producing wells perforated in Wara sandstone Formation in the Greater Burgan field in Kuwait have been plugged due to sand production issues. Understanding the causes of this critical challenge will definitely help KOC in finding the optimum sand management work flow and select the right sand control technologies to maximize the oil production in Wara formation. Several sand characterization tests were conducted on core plugs and produced samples collected downhole, ESP wellbore data was linked with well logs analysis and production data for understanding the sand production phenomena within the intervals and help establish a sand collapse model. Based on the lab work, modeling and ESP real time data, a screening benchmark was developed for sand management and control for Wara formation. The unique customized screening criteria will support South East Kuwait (SEK) field development to identify/avoid the potential sanding intervals and sustain oil production at safe drawdown pressure, which definitely will prevent ESP failures and extend the ESP lifetime. The risk assessment for potential sanding intervals has been established to predict sand production in most new Wara wells. Some Wara wells targeting shallower or weaker sands would normally be sand control candidates, by taking into account the completion design, optimizing surface sand management workflow, managing safe drawdown and BHFP levels, and taking advantage of favorable stress vectors through oriented perforation can encompass the sand free well operating envelopes over life of well production and depletion conditions.
Success Cases for Temperature Survey in Detection Communication between Tubing Annulus and Integrity Check for Through Tubing Bridge Plug also Cross Flow Determination and Evaluation for Continuous Gas Lift System by Simply Way of Temperature & Pressure Gauges in Gulf of Suez Fields - Egypt
Authors: Zakir Eman Ahmed
Published: November 2019

This paper discuss the major applications of temperature survey that it was applied in gulf of Suez wells in Egypt; the first application is the detection of communication points between tubing and annulus in oil producers through keeping high pressure gas in both tubing and annulus then running the temperature gauge in tubing bleeding off annulus pressure while continuous apply high pressure gas on the wellhead which it is cheap and helpful tool to return the wells to production while it was classified as high risk well by fixing communication points then actions took repair the communication points; the second application is integrity check for through tubing bridge plug leaking by real time monitoring for downhole temperature and pressure while the well is under flowing condition achieving differential pressure and saving rig time ; the third application is the determination of fluid movement both inside and behind the production string, hence locating any holes in the casing and any cross flow between intervals in high pressure temperature formation followed by remedial action for production enhancement ; another application in continuous gas lifted wells is the determination of operating valve (injection point) in gas lifted wells with detecting for any leakage valves that it effect on the lifting system efficiency and it needs change to keep the well’s production from dropping .by this tool production increasing was occurred through repairing the wells with more than 4000 BOPD.

so it is very important to share success applications from using temperature survey in oil producers to other companies to benefit from it because it is very cheap and useful in integrity check for completion / casing holes and through tubing bridge plugs leakage also for down hole fluid movement determination in high pressure temperature formation also in the continuous gas lift system evaluation.

Communication points between tubing and annulus in oil producers was determined easily with low cost and Low risk in operation that it was helped in changing the high-risk wells to safe operating wells by repairing the communication it was helped in oil production increasing; the integrity evaluation for through tubing bridge plug saving rig time / cost was determined; the evaluation of continuous gas lift system for determination the point of injection / the leakage valves to enhance lifting system efficiency.
Application of Well Interference Test Using Distributed Pressure Sensors to Optimize Well Spacing in Unconventional Shale Reservoirs
Authors: Uzun Ilkay , Assiri Wisam , Eker Erdinc
Published: November 2019

The optimization of well spacing has become more important in unconventional shale reservoirs to efficiently design infill developments, estimate the Stimulated Reservoir Volume (SRV), and more importantly the estimation of Ultimate Oil Recovery (EUR) from each well. This paper presents a new analytical solution to estimate the start and end of pseudo-transient flow for the data production analysis where boundary-dominated flow exists in the induced fractures hence estimate the SRV for hydraulically fractured horizontal wells for unconventional shale reservoirs.

This paper presents a semi-analytical model to obtain the pressure transient response to characterize the flow and estimate the boundary effect which can be used to analyze the field data in unconventional shale reservoirs. The results from the model are compared and validated against an in-house developed numerical simulation model. The semi-analytical model is based on trilinear model where the SRV is modeled using dual-porosity idealization. The developed model involves the simulation of interference tests for two hydraulically-fractured horizontal well in unconventional shale reservoir using the real-time distributed pressure data. The proposed asymptotic solution evaluates not only the pseudo-transient in induced fractures but also the matrix.

The pressure measurements from real-time distributed pressure sensors and the production measurement using interference test provide a better understanding of the physical phenomena of the interaction between the parent and child wells in shale reservoirs. This paper presents a new model to assess the interference characteristics in horizontal wells to evaluate the optimum well spacing in unconventional shale reservoirs. It is observed that the production from a well is greatly affected by the distance of the wells, the reservoir properties between the wells, and the matrix permeability. It is presented that if the matrix permeability is lower, the start of the pseudo transient flow is sooner; therefore, the drainage volume becomes smaller. This can be observed by comparing the field data from unconventional shale reservoirs in Bakken and Eagle Ford where the matrix permeability in Bakken is higher than that of the Eagle Ford; therefore, the wells observe longer linear flow regime in higher permeability with larger SRV and in-turn larger well-spacing. The proposed asymptotic solution can also be used to analyze the field data in unconventional shale reservoirs to decipher the productivity and economics of horizontal wells.

To effectively produce from unconventional shale reservoirs, an optimum well spacing is required. This paper presents a novel asymptotic solution to characterize the flow regimes and provide a novel formulation in analyzing the pressure and rate variation with time to forecast future performance.
Innovative Digital Well Construction Planning Solution Enhances Coherency and Efficiency of the Drilling Design Process
Authors: Szemat-Vielma Waldemar , Murray Thomas , Kiaie Ali , Bolchover Paul , Yao Jia
Published: November 2019

The oil and gas industry recognizes that there are significant gains to be had by the implementation of new digital technologies. For well construction planning, the goal is to bring together all domains, all data, and all engineering requirements in a seamlessly interconnected solution. As part of this transformation process, an innovative digital solution has been designed and implemented to cover all different aspects of the well planning and engineering workflows, delivering a step change in terms of capabilities and efficiency.

The use of traditional workflows and solutions often requires a lengthy, disconnected, and iterative processes, which can introduce a lack of coherency between the different teams and engineering processes involved, increasing the planning risks. Given the complexity and the number of disciplines involved in the well engineering process, a high-level collaboration is needed in new planning systems. Considering this as the basis for a change, a novel approach to connect all the well planning workflows demonstrates how the process can be optimized by combining automatic engineering and validation, big data analytics, concurrent engineering, and project orchestration.

The main benefit of a native cloud designed and deployed solution is the simplicity for the user because the architecture handles the interconnection of different workflows, data, and people, resulting in a more effective process. In addition, the solution always accounts for the latest data versions and automatically adjusts when any design change is made to the plan. Moreover, the cloud deployment enables complex big data analytics for offset well data analyses, thus increasing the accuracy of the results and democratizing the company knowledge. Automatic engineering validations are immediately confirmed against changes to the wellbore geometries, trajectory design, drilling parameters, bottomhole assemblies, bits, and rig specifications, among others, to deliver a more accurate and coherent result when compared to a disconnected model application workflow. As a result of this innovative solution, a significant reduction of individual software packages required to plan a well can be achieved. The system delivers a step change in in well engineering performance, with case study examples delivering both high quality results and efficiency gains of 50% and more.

This paper presents a full description of a new industry standard digital well construction planning solution that has the potential to transform the well planning process by providing a step change in collaboration, concurrent engineering, automation, and big data analytics. Furthermore, the cloud-deployed solution challenges will be briefly discussed.
Maximising Production Potential by Successful Application of Deep Azimuthal Resistivity and Geo-Steering of an Appraisal Well in an Interbedded Reservoir – A Case Study from UAE
Authors: Mishra Anoop Kr. , Albooshi M.A. A , Al Ali Ahmed Ebrahim , Sinha Rakesh , Al Hashmi Ghassan , Al Blooshi Abdulla , Mills Carey , Mandl Johannes , Fernandes Warren , Potshangbam Sanathoi , Abdoun Safwat , Hassan Syed
Published: November 2019

Accurately placing a horizontal appraisal well within an interbedded reservoir sequence presents a wide range of challenges especially when there is a lack of nearby control wells. These challenges relate to uncertainties in the formation (dip, reservoir continuity & porosity development) and reservoir fluids (contact depth, transition zone height). In order to achieve the appraisal objectives it was critical to successfully intersect certain zones within the reservoir sequence and ascertain their hydrocarbon flow potential along with quantifying key reservoir properties and fluid boundaries. This data was essential for defining and optimizing the subsurface components of field development planning including well count, expected flow rates and in- place / recoverable resource estimations.

In this particular application the target reservoirs are porous gas saturated carbonates developed within an interbedded Jurassic aged limestone. Well placement in the subject well had the primary objective of intersecting five HC bearing zones while maintaining a safe distance from a conductive zone interpreted to be water saturated. As part of the pre-well planning, 3D real-time multiwell reservoir modelling and its updating capabilities with appropriate LWD measurements for Proactive Geosteering and Formation Evaluation was planned. Based on forward response model from offset well data along with drilling engineering and data acquisition requirements, an LWD suite consisting of RSS, Gamma Ray Image, High Resolution Resistivity Image (Fracture and Fault identification), Neutron, Density and 16 sector Density image along with a Deep Azimuthal Resistivity measurement for early detection and avoidance of conductive/water zones was utilized. This tool is capable of early detection of conductive zones that could indicate either transition zone saturations or water saturated porosity beneath a gas-water contact (GWC).

Application of the Azimuthal Resistivity measurements along with the realtime updates of the subsurface model helped place the appraisal well within the hydrocarbon column and also established the top of the low resistivity "Wet Zone". Importantly, these results were later confirmed with production logs acquired as part of well testing operations.
Tandem Dry Gas Seals Design and Maintenance Considerations for Enhanced Reliability and Performance
Authors: Kamal Girish
Published: November 2019

Dry Gas Seals (DGS) for centrifugal compressors exist in the process industry for the last almost thirty years and almost all the compressor units operating in the industry today are equipped with Dry Gas Seals. High operating and maintenance costs, unreliability and hazardous characteristics inherent with the conventional lubricated shaft sealing systems have resulted in widespread utilization of the DGS and their associated sealing systems.

This paper shall cover the design considerations including best operation and maintenance practices to enhance dry gas seals operating life and performance including: ▪Major factors affecting Dry Gas seals service life▪Seal Gas supply and control requirements▪Primary Gas seal venting and health monitoring▪Secondary Gas seal venting and health monitoring▪Separation Gas supply control systems and health monitoring▪Recommended Alarm, Shutdown and Start-Permissive conditions
Processing Challenges and Solutions for Seismic Reservoir Characterization With Wide-Azimuth OBC Seismic Data, Offshore Abu Dhabi, UAE
Authors: Miyamoto Hiroki , Almheiri Afra Naser , Kojima Keitaro , Shibasaki Toshiaki , Bellah Samir , Aljasmi Sami , Mahgoub Mohamed , Cambois Guillaume , Paul Subhrankar , Khakimov Oleg , Barajas Carlos
Published: November 2019

Seismic processing is expected to deliver a reliable product for seismic structure interpretation and reservoir characterization to support subsequent reservoir modeling and drilling operation. 3D OBC wide-azimuth (WAZ) seismic data has a significant advantage in this respect, since it contains large offset and wide azimuth information, which can be utilized for amplitude versus offset (AVO) and amplitude versus azimuth (AVAz) analysis respectively. However, these advanced studies require area-specific data processing efforts in this region for strong linear noise, multiple noise, designature uncertainty etc. Seismic data re-processing was newly conducted in pre-stack time migration (PrSTM) sequence to overcome such technical challenges. Surface-wave noise attenuation was achieved by 2D and 3D model-based dispersive energy attenuation and multi-pass structure oriented filtering in pre-stack and post-stack stages. Source-side deghosting highlighted a low frequency residual bubble and was followed by another pass of de-bubbling based on a smooth spectrum assumption. Shallow water reverberation was minimized by 3D deconvolution and high-resolution radon demultiple. 5D regularization and interpolation with trace densification provided evenly populated traces for each angle and azimuth sectors. Intensive signal preservation protected diffraction energy and resulted in better fault imaging than the vintage processing outcome. Both the vintage and the re-processed seismic data were evaluated in quantitative manners to compare with each other. Angle stacks from the re-processing showed more reasonable response for AVO analysis. Azimuth stacks showed stable S/N ratio leading to higher confidence in azimuthal anisotropy analysis. All these seismic deliverables enable accurate elastic property estimation and detail fault interpreation at target reservoir intervals. The novelty of the proposed workflow is to overcome common technical problems with targeted noise and multiple reduction focusing on angle / azimuth stacks. It unlocks advanced geophysical study for carbonate reservoir in shallow water areas. Processing deliverables will be fully utilized in fault interpretation, AVO and AVAz analysis and will support the forthcoming field development activity.
New Corrosion Growth Model Based on Pipeline Intelligent Pigging Data - Correlating Corrosion Defects Numbers with their Depth
Authors: Trojette Mohamed Zouheir , Zebibi Anouar , Hammadi Abdallah , Hosani Khalid
Published: November 2019

As part of their integrity management system, Oil and Gas operators carry out internal inspection of their pipelines by intelligent pigging. State of the art MFL and UT inspections are used to detect and accurately size the defects, which are present in the pipeline. The predominant type of defects reported is due to internal corrosion.

It is well established that corrosion is a naturally occurring phenomena. When the conditions are right for corrosion to develop, it starts by a single defect or very few defects which are shallow. Then as the pipeline is operated and corrosion further develops the defects increase in size and numbers.

This paper review several intelligent pigging reports data, and analyze the reported defects in terms of numbers and depth for several pipelines, in order to establish a correlation (mathematical model) between the number of internal corrosion defects and their depth. Defects counts will be made and equations will be developed for several pipelines. These equations will basically establish the number of defects as a function of their depth or vice versa.

More over when multiple intelligent pigging runs on same line are available, these derived equations will be compared with the objective to establish a novel model to determine corrosion growth rate in a non-conventional manner. In fact the models (# of defects and their depth equation) established for different inspections will be compared and a corrosion rate model establishing the increase in number of features and their number over time will be thereafter derived.
How Rethinking the Drilling System, from the Drillbit to the Drillstring and the Drilling Fluid Addressed a Threatening Casing Wear and Turned a Difficult 6-in. Section into a Perfect 6-in. Sidetrack
Authors: Labrousse Sébastien , Guner Hakan , Kauffmann Carlos , Caycedo Alberto , Opsahl Jørn , Atallah Rawad , Hatleseth Tore Andreas , Moldekleiv Rune , Nokland Magnar , Andreassen Ørjan , Nyborg Benjamin
Published: November 2019

The purpose of the paper is to present how an integrated solution was designed to turn a challenging 6-in. section into a successful 6-in. production sidetrack in Norway. A threatening casing wear issue caused by the combination of slow progress and localized dogleg was addressed successfully with a complete redesign of the drilling system.

A 6-in. pilot section suffered slow progress due to low rate of penetration and tool failures. Significant amount of metal swarf was recovered while drilling. A casing wear log quantified the wear in the 9 7/8-in. casing, and this led to questioning the feasibility of the planned 6-in. production sidetrack. Operator, rig contractor and integrated services provider worked together to find a solution.

First, a detailed study of the wear was performed. A wear log was run, and the casing wear was quantified. Casing wear simulations were then calibrated based on wear logs and it appeared feasible to drill the 6-in. sidetrack if a minimum rate of penetration and a maximum number of revolutions were respected.

Second, the drilling system was optimized to ensure faster progress. This was done thanks to the learnings from the pilot section. The mud system was changed, and a lower density was used to increase the rate of penetration. The drillbit was optimized based on the limited wear seen in the bits used in the pilot section. As it was more aggressive, the perceived risk of downhole tool failure was mitigated with the use of an anti-stall tool.

Finally, to reduce the incremental wear from the sidetrack operation, casing protectors and lubricants were run. Also, the planned drillpipe was changed to a lighter drillpipe to reduce the sideforces.

The new system resulted in a successful drilling and section TD was reached ahead of the estimated perfect time.

With this paper we provide a detailed example of how a casing wear issue was addressed. The drivers we extract from this case are useful for the planning of future operations, especially in extended-reach wells.
Transforming Waste Heat to Electric Power in Oil and Gas Compression Systems using Supercritical Carbon Dioxide
Authors: Soulas Thomas
Published: November 2019

In the oil and gas sector, energy is wasted far too often. By recovering those losses and increasing efficiency, the operators of production facilities and transmission systems can make dramatic improvements and yield new commercial opportunities. For instance, energy recovery may potentially allow profits to be realized from fields that might otherwise be marginal prospects or represent an additional revenue stream for gas pipeline transmission and distribution network operators.

Now, a breakthrough technology that supports energy recovery from heat rejected from a broad range of industrial processes is available to the oil and gas industry. There is a lot of wasted energy available. Globally, it is estimated that rejected heat corresponds to about 65% of the net energy input across the industrial infrastructure, with numbers varying from 60% to 70% depending on the region, including the Middle East.

Considerable waste heat is ejected from equipment like the gas turbines that are commonly used in mechanical drive applications found in the compression processes of gas production platforms and transmission pipelines. While most gas turbine heat recovery systems use a bottoming steam cycle to improve thermal efficiency, so-called combined cycle turbines, the new development presented in this paper is significantly different.
Intelligent Identification of Least-Connected Components of Reservoir Simulation Models
Authors: Rogowski Marcin , Kayum Suha
Published: November 2019

Reservoir simulation models that represent large-sized reservoirs require significant use of High-Performance Computing resources. Several solutions aim to reduce the load of an individual simulation such as upscaling to consequently reduce the number of grid cells of the model, splitting the model into independent sub-models using crop functionality, or dividing the model into sectors and running these sub-models independently. As it preserves the flux boundary condition, sector modeling could potentially result in the least erroneous solution, especially if the sectors are defined on the regions of least connectivity.

This paper aims to propose an automated, intelligent method to divide the reservoir model into an arbitrary number of least-connected smaller sectors. Streamline simulation output is used as a representation of reservoir connectivity. A graph is built using cells as graph vertices, and the edge weight is calculated based on the time of flight of oil and water between cell pairs.

By presenting the problem in this manner, a graph is built where the non-water cells have equal weight, and the stronger the connection between two cells, represented by the lower time of flight, the larger the edge weight. A graph partitioning tool is used to minimize the total weight of edges cut while keeping the number of vertices in each sub-graph balanced up to a specified tolerance. Partitioning of a graph specified this way is equivalent to splitting the reservoir model into sub-models while avoiding cutting of strongly connected parts, hence minimizing the boundary flux. Applying this method to sector modeling allows splitting a model into a number of smaller sub-models that can be used independently as the interactions between them are minimized, as demonstrated by minimizing flux between them.

The proposed novel method has been tested on several real-field as well as synthetic reservoir models. The method has resulted in sub-models of loosely connected reservoirs. The advantage of our proposed method is especially seen for strongly connected models where it is difficult to identify the least erroneous partitioning for sector generation manually. With the use of our method, it is guaranteed to automatically find the least connection, while minimizing the error that sector division produces, as evident by the low flux between the sector models.
Comparison of open liver resection and RFA for the treatment of solitary 3-5 cm hepatocellular carcinoma: a retrospective study
Authors: Lei Jianyong , Lunan Yan , Dajiang Li , Wentao Wang
Published: November 2019

Aim: The goal of this study was to compare the postoperative results of liver resection and radiofrequency ablation (RFA) for the treatment of small hepatocellular carcinoma (HCC) (3-5 cm). Patients and methods: We retrospectively collected 122 patients with small solitary HCC treated at our center from Jan 2011 to Dec 2015, with diameters in the range of 3-5 cm. According to the treatment program received at our center, they were divided into the liver resection group (72 patients) and the RFA group (50 patients). Result: In comparison with the RFA group, the resection group had a longer operative time, and greater intra-operative blood loss (P<0.01), more hepatic inflow occlusion , and longer postoperative hospital stay (P<0.01). The 1-, 3-, and 5-year expected overall survival rates and tumor-free survival rates were comparable between the two groups. Cox regression analysis showed that resection or RFA was not a significant risk factor for overall or tumor-free survival for HCC. Conclusions: For solitary HCC of 3-5 cm in diameter, RFA can achieve better in-hospital clinical results and similar long-term outcomes, and RFA can be considered for wide application, especially for central cases.