bluuebunny/crossref_metadata_2025 huggingface dataset:
Subsea Pipeline Design Automation Using Digital Field Twin
Authors: Bhowmik Subrata , Noiray Gautier , Naik Harit
Published: November 2019

The main objective of this paper is to present a cost-effective, user-friendly and highly reliable subsea pipeline design automation framework under the cloud-based digital field twin platform Subsea-XD. The FEED and detail design phase of the subsea pipeline is normally quite long and need to run several analyses sequentially to achieve the desired results. In this cloud-based design automation method, a significant number of calculation hours are saved due to systematic and sequential approach with minimum remediation work by reducing human error.

In this proposed design automation framework, all the standard pipeline calculations including code checks are performed through a web-based graphical user interface (GUI) designed in cloud-based digital field twin. In the design phase of the subsea pipeline, some more advanced level pipeline finite element analyses are performed for buckling and walking assessment. The design phase of the subsea pipeline consists of different analytical as well as finite element (FE) calculations which are performed systematically and sequentially in cloud-based digital field twin. Various calculations including wall thickness calculation based on API/DNV/ASME code check, on-bottom stability analysis, pipeline span analysis, pipeline end expansion analysis, out of straightness analysis and pipeline buckling analysis are performed sequentially and systematically in the cloud using the metadata information available from the digital field data. All the standard pipeline calculations are developed using Python API and connected to cloud-based digital twin Subsea-XD. For advanced FE analyses for lateral buckling and pipeline walking, the preliminary susceptibilities are assessed through analytical calculations developed through python- based API. For the pipeline FE analysis for lateral buckling and walking assessment, pre-processor and post-processor are developed in python based on various metadata (pipe data, soil, environment) information available in the subsea digital field.

The pipeline design calculation outputs are stored in a standardised report format in the cloud platform. The GUI is developed and the whole pipeline design process is automated through the python API. This design automation approach significantly reduces the total project cost. Integrating all the pipeline design calculations and automated report generation in a cloud-based digital field twin is very much beneficial for the early stages where some changes are expected.

This pipeline design automation system relates to cloud-based digital field Subsea XD through API so that it is worked as an integrated system giving 3D digital field diagram as well as all pipeline design calculations in one digital platform.
Artificial Intelligence in Autonomous Operation of Oil and Gas Facilities
Authors: Devold Håvard , Fjellheim Roar
Published: November 2019

Objectives/Scope: Remote, inaccessible locations, hazardous environments and cost are some of the drivers for unmanned or remotely-operated facilities. With insight from facilities which are already operating remotely, it is time to take the next step towards running autonomous plants with no people. With reference to external sources and client case studies, this paper will discuss the preconditions and technological developments which now make it possible to do this safely and economically and how Artificial Intelligence is a key component.

Methods, Procedures, Process: The paper describes key criteria and technologies needed for successful autonomous operations. In particular, companies must ensure operations are safe through process safety management. They must also be able to run operations with no physical presence via automatic controls for startup, change and shutdown. Maintenance and inspection must also be done with no-one there, using plant-wide condition monitoring and predictive analytics, as opposed to only tracking critical equipment as the latter is insufficient in processes with so many interdependencies. Robots and drones must also be leveraged where manned intervention is required e.g. for pipeline scraper handling.

Results, Observations, Conclusions: The importance of zero operators is significant. Even just one employee, actually means 20 are needed for a site running all day, every day by the time rest, vacation and sick leave cover requirements are factored in, not to mention support functions like catering and cleaning. This is not only expensive but also means a significant number of people remain exposed to a hazardous working environment. Underpinning the above are Internet of things technologies to sense, measure and control operations, connectivity to share the information in a timely manner, the analytics to process it ‒with a significant reliance on artificial intelligence‒ and appropriate dashboards to bring the information to the remote operator, domain expert or vendor partner. The importance of digital engineering and digital twins in facilitating such activities will also be discussed.

Novel/Additive Information: We show that new safety, operational and maintenance procedures are needed to implement autonomous unmanned operation. Artificial intelligence with machine learning is needed to reach this goal. The paper will provide examples of howunmanned operations are becoming a reality. The safety and cost-saving benefits achieved from pilots and wider field applications of technology will be presented. Many of the technologies and operational changes will in themselves deliver reduced costs by eliminating operator errors, reducing maintenance expenditure and improving availability.
Evaluating Foam Stability using Tailored Water Chemistry for Gas Mobility Control Applications
Authors: AlYousef Zuhair , Ayirala Subhash , Gizzatov Ayrat , Kokal Sunil
Published: November 2019

Generating in-situ foam is regarded as one of the most promising techniques to overcome gas mobility issues and improve sweep efficiency in both miscible and immiscible gas injection enhanced oil recovery (EOR) processes. Gravity override, viscous fingering and channeling through permeable zones are the major limiting factors that can impair the efficiency of gas floods, mainly due to low density and viscosity of the gas relative to reservoir fluids. Generating strong and stable foam while injecting gas is one way to achieve in-depth conformance improvement in the reservoir.

In this study, a tailored water chemistry (formulated low salinity water) has been evaluated in comparison to using typical high salinity injection water (i.e. seawater) and deionized water in surfactant solutions to determine its overall effect on the produced foam. Using bulk foam tests, foam rheology apparatus and microfluidics device, the foam stabilization factors were analyzed and quantified by measuring the foam-life over time of different surfactants in varying salinity water solutions. In addition, the foam rheological properties were measured under high pressure. The microfluidics device was also used to examine the generated foam strength in porous media.

The results from laboratory experiments clearly demonstrated that the use of tailored water chemistry can improve the stability of produced foam when compared to both high salinity water and deionized water. Low salinity tailored water chemistry solutions resulted in a longer lasting foam, by almost 1.8-3.0 times depending on the surfactant type. The foam rheology results showed that the produced foams with the tailored low salinity water are of higher apparent viscosity when compared to those obtained with deionized water. Both longer foam-life and higher apparent viscosity are indicative of better, stronger and more stable foam. The higher resistance to gas flow was observed in porous media with foams generated using the low salinity tailored water chemistry solutions when compared to those foams obtained with deionized water and high salinity water.

This experimental study, for the first time, demonstrated substantial improvements in the foam stability by using a tailored water chemistry aqueous solution. Such huge foam stabilization improvements obtained with tailored water chemistry has the promising potential to increase the apparent viscosity of injected gas and subsequently more effectively mitigate gas mobility issues encountered in EOR applications.
Largest Liner Hanger Ever Installed Worldwide
Authors: Gomez Gonzalez Ernesto S. , Rodriguez Rico Ramon , Obi Ikenna , Bolivar Antonio
Published: November 2019

Some gas wells casing design call for running and cementing intermediate 18 5/8" casing string to cover weak formations (low pressure/losses) including hydrocarbon bearing formations. Some gas wells drilled in the offshore Arabian fields developed sustained Casing-Casing Annular (CCA) pressure problems, emanating from poor cement bond of the intermediate casings, especially the 18-5/8" x 24" casing annulus. This paper will examine the source of the problems, primary solutions, and the remedy for the problems.

Primary cement is the first barrier to prevent sustained CCA pressure problems; from drilling through the production lifecycle of any well. Most of the wells experienced losses while drilling or cementing the intermediate casing; the current practice is to enhance the chances of a good cement job by installing an external inflatable packer with a circulation port (DV). This device splits the cement job into two stages and enables the second stage cement return to surface. In some completed gas wells, DV and cement barrier failure were recorded, which subsequently resulted in CCA pressure development.

A solution was conceived to replace the 18-5/8" casing DV stage tool with a more reliable liner hanger (LH), in the most critical casing annulus CCA3 (18-5/8" x 24"), which has a higher risk of CCA development due to mobile hydrocarbon bearing formations covered behind the 18-5/8" casing. CCA3 pressure was reported in some wells. The shallow intervals were drilled, cased, and cemented, utilizing enhanced cementing practices and a DV tool in a 2-stage cement job.

The LH alternative offers a good solution, but no technology was available worldwide to run the 18 5/8" liner and set inside 24" 201# casing, to avoid CCA pressure in this particular annulus size. The operating company collaborated with the lLH provider to develop the world's biggest LH, with metal-to-metal seal in the hanger and rubber seal barriers in the tie-back. The LH equipment was manufactured over a period of 6 months, deployed, and successfully field tested in five wells with no CCA3 pressure reported to date. The results of this LH installation will be discussed using case histories of recently drilled wells in the field, and compare results with some previous wells. For critical high rate gas wells with associated high construction cost, any technology applied to enhance well integrity, such as installation of the 18-5/8" LH, is considered an absolute necessity by the operator.
Risk Evaluation & Sensitivity Analysis of the Exploration & Production Sharing Agreement
Authors: Balhasan Saad , Biltayib Biltayib
Published: November 2019

This paper has been intended at risk evaluation and to investigate the importance of the Exploration and Production Sharing Agreement (EPSA) model (equity split share, A factors, and production indices B) in terms of different capital budgeting techniques such as Net Present Value (NPV) and Internal Rate of Return (IRR). The present study has applied deterministic research approach along with stochastic research approach using Monte Carlo Simulation procedure. This technique has been adopted to determine the probable range of NPV and IRR values that are based on stochastic variable of financial terms of the EPSA model applied. The simulation output of the economic model of field development by water injection revealed that the NPV and IRR are both significantly fragile terms in case of production share. Different levels of sensitivities have been observed for factors (A) and production indices (B) in terms of NPV and IRR at fixed or variable production share. The analysis exposed that in terms of NPV and IRR, the production index B1 and B3 is relatively more sensitive than other measures. Similarly the outcomes show that in terms of NPV and IRR the production index of B4 and factor A (4) are relatively less affected than other terms. The Crystal Ball's OptQuest's was used to mitigate the financial risk by optimizing the SP's profitability indicators. The project profitability indicators NPV and IRR of the international oil company, designated the second party (SP), were optimized and improved from 16.86% to 20.00% and NPV from $175.03 million to $273.32 million, respectively.
Zohr Offshore Pipeline - Buckle Arrestor SSC Testing & Mitigation
Authors: Hussein Hesham , Elkhafif Hesham , Badran Shady
Published: November 2019

Zohr subsea production system (Accelerated Start Up Phase) is made by 6 wells connected via individual rigid production infield flowlines to two chained Main Subsea Structures. Gas is exported to onshore El Gamil plant through a piggable export sealine connected to the one of the two Main Subsea Structures.

In total 218 km of pipes 30inch to Zohr onshore plant El Gamil pipeline. Pipeline material and dimension combination required for the Zohr project is unique in its kind and the combination of requirements has not been produced before, with demanding mechanical and corrosion tests and a new limit for pipeline exposed to sour service.

A certain number of Buckle arrestors (107 pieces) have been used along pipeline installation. The BAA are around 12 m long and are integrated by three sections; The central sections of thickness (75.8, 66.0 and 54.0mm) are seamless forged pieces produced with ASTM A707 Grade L5 Modified steel in quenched and tempered condition with mechanical properties equivalent to API 5L L415QS / L415QO material. The pup pieces are API 5L LSAW pipes Grade L415MS / L415MO.

During Manufacturing Process Qualification Testing (MPQT) Sulphide Stress Cracking Corrosion Test (SSC) have shown some cracks of test specimens. The specimen fails and SSC cracks were found in the post test analysis, i.e., by sectioning and performing metallography at X100. These specimens were tested in NACE TM0177 type A solution with 5% NaCl and 0.5% acetic acid, saturated with 1 bar H2S at an initial pH of 2.7. Exposure duration was 720 hours and the load to be applied was 90%. No indications or defects were assessed by NDT magnetic particle inspections on all the tested specimens.

Weld overlay of buckle arrestors assemblies (BAA) with alloy N06625 (nominal thickness 3 mm) cover the full length of the central section plus the circumferential welds (that are ground flush) and extending 100 mm on each side of the girth welds into the pup pieces.

It was a challenge to overcome these defect of these pipes considering the stringent requirements in the project specifications and the tight project schedule to achieve the installation campaign without any delay on project schedule.

The Optimized Ramp-Up phase envisages an extension of the Accelerated Start Up subsea system with four (4) additional wells, a new Main Subsea Structure (MSS3), a new Subsea Distribution Unit (SDU) and a piggable export pipeline (30" OD), parallel to the 26" Accelerated Start Up Phase (ASU) export line.
Numerical Modeling and Experimental Validation of a Wellbore Cleanliness Concept During Connection Time
Authors: Ruzhnikov Alexey
Published: November 2019

One of the most common operations while drilling is the connection of drill pipes after every stand drilled. The main concern prior and during this operation is to ensure that annulus around the bottom hole assembly (BHA) and drill string is clean of any cuttings, when often excessive time spent to achieve it. This manuscript discusses modeling, field implementation and operational observations of changing the standard practices, what led to significant time reduction while drilling vertical, deviated and extended reach (ERD) wells.

The most common worldwide practice is to wash / ream a stand up and down prior to connection to remove any potential cuttings around BHA. Having this in mind the objective was set to minimize this time as much as possible towards full elimination. To accurately predict the cuttings lifting forces, annulus cleanliness, hook load fluctuations advanced modeling combining torque, drag and hydraulics was developed. The model considers all the key parameters such as drilling fluid density and rheology, BHA configuration, pumping rates, wellbore geometry, temperature and pressure effects, etc. and can estimate the time required to spend at the end of every stand.

A total of up to one hundred jobs were simulated and followed by the field implementation in the different sections, which were ranged by bit size (from 17-in. to 6-in.), inclination and complexity (from zero to 90 degrees, including ERD wells) as well as other affecting parameters such as losses, wellbore stability etc. The data from the initial wells were crosschecked vs available MWD/LWD data (as equivalent circulating density, annulus pressure while drilling, temperature etc.) to confirm the results of the simulations.

As a result, new connection practices were developed with minimum clean out time prior to a connection. Two examples: in the vertical wells the pre-connection time was reduced almost to zero and only two minutes drill-off now done; in deviated wells including ERD a standard approach of washing up / reaming-down a stand was replaced to 2 - 3 minutes drill-off followed by ream up and down of 10 ft only. Together with other changes it not only allowed the decrease a connection time by up to 60% without the negative incidents like stuck pipe, but also minimized impact on the bottom hole assembly (BHA) components happening due to off bottom stick / slip. This resulted in great time savings, where around 2 days can be saved for 20,000 ft wells vs previously applied practices.

The manuscript describes an engineering-based approach to connection practices which allows to shorten well construction time and decrease the well cost without additional risk.
Deployment of Lower Completions with Interventionless Inflow Control Device to Increase Operational Efficiency, Save Rig Time and Reduce Deployment Risk
Authors: Adan Iain , Boggs Reggie
Published: November 2019

The most common practice to deploy a lower completion with inflow control devices (ICDs) requires a washpipe assembly to facilitate deployment. Due to the nature of traditional ICDs, with open flow ports, the washpipe assembly provides a conduit to circulate fluids during the installation. However, makeup and break out of washpipe takes time, carries risk, and provides no long-term benefit to the completion or long term value to the operator.

The industry has used temporary mechanical isolation in more recent years, but these devices lack redundancy in the event of malfunction.

The objective of the hydro-mechanical ICD is to remove the requirement for washpipe, thereby reducing operational risk and rig time while eliminating HSE concerns related to drill pipe handling when deploying the lower completion. The key differentiator being additional redundancy, should manipulation be required.

An additional feature of the tool is position verification, the ICDs benefit from a passive attenae. The attenae reader can be deployed in the future to independently verify sleeve position should well optimization be required over the well lifecycle as water cut increases.

The paper reviews various techniques that have been adopted to date and concludes with presenting a hydro-mechanical solution that was successfully installed and the value derived.
Case History of a Successful Hydraulic Restimulation Pilot: The Story from Pilot Candidate Selection to Post-job Evaluation and Rollout
Authors: Janiczek Peter , Dragomir Alexandru , Stojkovski Jovan , Makar Ivan , Kolasa Bartlomiej , Paraschiv Madalin
Published: November 2019

This work presents the entire case history process from the recognition and identification of a potential candidate for multistage hydraulic re-stimulation. This includes operational preparations, execution, and how post-treatment results influenced the rollout of a pilot.

While the recognition of the potential candidate was a coincidence by intersecting a stimulated area from one well to a neighboring well, resulting in sustainable higher production, the study phase to identify the full field potential and candidate well identification was executed in a structured way. A primary challenge was the proper preparation of the well, while keeping the overall costs manageable.

Dedicated supply vessel has been used to accommodate stimulation equipment which was used to execute hydraulic stimulation treatments in Black Sea. Hybrid designs have been designed to carry 20/40 RCP proppant, which was pumped in four cycles. Since reservoir has been accessed by originally opened sleeves with addition of new hydrajet cuts along horizontal section the need of special degradable diverter was required to ensure good lateral coverage and proppant distribution. Together with the treatment, hydrocarbon and water sensitive tracers were pumped, allowing an allocation of flow per cycle. After shutting in the well to allow the resin coated proppant to cure, the well was cleaned out with energized fluid and returned to production

Within four hydraulic re-stimulation cycles, a total of 300 tons of proppant with approximately 2,000 m3 of fluid were pumped and successfully diverted. End of cycle ISIPs rose by more than 20 bars and back-calculation of volume of the diverter stages allowed identifying the diversion effect. During the initial flow phase, very high water cut was observed, exhibiting good cleanup of the treatment. After 2 weeks, the rate stabilized at double the pre-treatment rate and slightly above the conservative prediction.

Multistage hydraulic re-stimulation is not well utilized in Europe thus far and has not been applied offshore. In this mature field, the entire process from study to execution and post-job analysis was strongly cost driven, but resulted in the potential for six more hydraulically stimulated wells in this field.
Equivalent Circulating Density Prediction Using a Hybrid ARIMA and BP Neural Network Model
Authors: Han Chao , Guan Zhichuan , Li Jingjiao , Hu Huaigang , Xu Yuqiang
Published: November 2019

A hybrid methodology is presented to predict equivalent circulating density (ECD), which combines autoregressive integrated moving average (ARIMA) and back propagation neural network (BPNN) models. Research results are compared to previously published ECD prediction method that is based on theoretical calculation of hydraulic parameters.

The hybrid methodology is based on data analysis theory. It uses ARIMA model to capture the linear trends of ECD, and then the BP neural network is used to predict the nonlinear and stochastic change law of ECD. Finally BP neural network prediction results are used to correct the prediction error of ARIMA to get the ECD prediction results. With a deepwater well in the South China Sea, a simulation experiment is carried out to verify the comprehensiveness and accuracy of the method presented in this paper.

The prediction results are similar to those of the traditional hydraulics model, which considers the effect of temperature and pressure on drilling fluid density and rheological parameters. Comparisons are also provided for three classical time series prediction models, including the support vector machine, multiple linear regression and grey prediction. The root mean square error (RMSE) and the mean absolute deviation (MAD) were selected as evaluation indicators. The comparison results show that the hybrid model can reflect the variation law of ECD more accurately. Therefore, relative to the traditional methods of prediction, the hybrid methodology has the advantages of advanced modeling thought and simple operation, and it can be selected for prediction of ECD.

Because of the effects of high temperature, high pressure and uncertain factors, the accurate prediction of ECD is very difficult. This paper provides a novel idea for accurately predicting ECD by analyzing the implicit relationship of ECD series data through data mining.
Trading Risk for Reliability, Flexibility and Efficiency in NGL Plants
Authors: Patel Tushar , Tabaza Sami
Published: November 2019

Gas processing plants need to cope with varying and often uncertain conditions. Operators of gas processing plants in North Dakota (USA) typically face challenges with the mode of operation (ethane rejection or ethane recovery) and feed gas uncertainty (rich gas or lean gas). In terms of equipment reliability, flexibility and efficiency, these circumstances also place significant requirements on the compressor technology used. This case study will discuss the deployment of a mechanical refrigeration cycle using commercial-grade propane (95 to 98.5% propane, with the rest being heavy hydrocarbons, or HD5, or higher-grade propane). In the context of different compressor technologies available for such applications (this includes oil flooded screw, integrally geared centrifugal or inline centrifugal, the authors examine the performance characteristics of integrally geared compressor technology applied in gas processing plants.

Inherently, oil-flooded screw compressor systems require regular maintenance to ensure the availability of oil-free process gas. In turn, when seals or coalescing filters are not maintained or do not perform as expected, oil may carry over with the process gas and flows to downstream. These events require extensive cleaning and can lead to plant downtime. By comparison, integrally geared compressors and inline centrifugal compressors are 100% oil-free (no oil in compression chamber / process), providing increased reliability while requiring less maintenance. Also, integrally geared technology can be supplied with tilting pad thrust bearings which allow these propane refrigeration compressors to start at a higher suction pressure (i.e., settle out conditions on hot summer days), thus providing superior rotor stability while saving the propane because there is no need to flare the gas to reduce the system settle out pressure (Patel and Struck 2017).

With regards to the parameter of flexibility, the authors will discuss how the variable diffuser guide vanes (vDGVs) are helping to provide the process flexibility, thereby extending compressor turndown up to 50% without recycle. vDGVs can maintain a required and subsequently designed discharge pressure that gives operators flexibility with varying mole weight and head requirements. vDGVs also help with start-up during high settle-out conditions like those in refrigeration processes.

It was found that integrally geared compressors are about 10% more efficient than oil-flooded screw compressors. As each impeller has its own casing and seals, it will allow for easy accommodation of side streams. Also, integral gearing can match the impeller geometry to the required speed which results in higher compression efficiency, while dry gas seals reduce process gas leakage to improve plant reliability. Lastly, it was found that an integrally geared refrigerant compressor delivers more than USD 200 000 per year in OPEX savings, in addition to lower CAPEX of up to approximately 20% (based on the study done for a 200 MMSCFD plant).
Understanding Erosion Patterns as Potential Sites for Corrosion Proliferation
Authors: Noui-Mehidi Mohamed N. , Badeghaish Wael O.
Published: November 2019

In the case of coated materials, any mechanical erosion at a specified location in a flow system will lead to chemical corrosion if the fluids are in contact with the eroded zone, which presents a favorable condition for corrosion growth. In contrast, corrosion of materials can worsen by mechanical erosion when corrosion has started destroying the texture of the subject material. In the present paper, we will review erosion-corrosion aspects of metallic systems based on particle impingement mechanisms’ Finnie model and its implication of different metallic materials. The paper summarizes the effects of fine particle impingement with regard to different flow situations that can lead to mechanical erosion that will affect the chemical reliability of the metal leading to potential harmful corrosion. The paper will provide a few recommendations to avoid such situations and achieve a sound mechanical and chemical reliability of the material system in use.
Successful Use of Tubing Punch Technology in Production Restoration of a Highly Deviated Gas Well With Stuck Plug
Authors: Gadelhak Abdelrahman , Deshmukh Rohit , Sudarev Maxim , Baslaib Mohamed , Al-Badi Mohammed , Ahmed Zeeshan , Assagaf Mohamed , Al-Attar Mohamed , Al Jaberi Fawzi , Hegazy Gehad
Published: November 2019

The scope of the paper is to demonstrate the effectiveness of tubing punch technology for a gas well through rig-less operation to bypass flow restriction due to a stuck plug. The scope shall encompass the technology selection, challenges faces and successful deployment relative to conventional options.

In a pursuit to reduce rig time, smart solutions have been explored by the operators for effective production enhancement and reliance on multiple well interventions to save cost. The candidate onshore well in discussion is a high potential well with an average gas production of ~30 MMScf/d and condensate averaging ~4,000 STB/d. The well has been producing consistently since 1997 until 2013 where by the well was killed for maintenance activities. In 2015, an attempt to recommission the well was failed due to a stuck slick line plug. The well was attempted to flow though the equalizing ports in the plug body, however that resulted in a significant reduction of flow rate to ~ 8MMscf/d resulting in a production loss of 22 MMSCFD. Various options were contemplated in an attempt to re-instate the well to its original condition i.e. milling, workover, cutter etc., however the options were discounted considering high cost and rig requirements. Tubing punch technology/Solution was chosen in view of the cost effective rig less activity. The paper shall discuss the details of planning, inflow modelling and operational challenges for the well re-instatement to its original condition without compromising well integrity requirements. The technology implementation demonstrated a direct production gain of +/- 22 MMSCFD and +/-400 BOPD using the low cost intervention Tubing punch technology with net cost 27 K $USD
Evaluation of an Ethoxylated Amine Surfactant for CO2-Foam Stability at High Salinity Conditions
Authors: Le Linh , Ramanathan Raja , Nasr-El-Din Hisham
Published: November 2019

CO2 flooding is well-known to be an effective EOR method and has been successfully implemented around the world. In heterogeneous formations, CO2 foam has been utilized to achieve conformance and mobility control. However, the foam performance degrades significantly at high saline environments. Ethoxylated amines have been reported to be successful in high pressure-high temperature (HPHT) conditions. This paper investigates the results obtained from a study of the foamability and foam stability at varying salinities, initial pH, and surfactant concentration.

The surfactant is evaluated to provide optimum concentration, salinity, and a pH level for better foam performance during EOR applications. Bottle shake tests achieved the objectives of this paper. Different salinities of brine, ranging from 0 to 25 wt%, mixed with the surfactant, with concentrations of 0.1 to 1 wt%, helped in the investigation of the foam performance. The bottle shake tests were conducted to prescreen the surfactant concentration, salinity, and pH level, at ambient conditions. Sodium chloride was used to prepare the solutions.

The bottle shake tests indicated that, in terms of foam half-life, the optimal surfactant concentration was 0.25 wt% for salinities of 0 to 15 wt% NaCl. Moreover, at this salinity range, the lowering of the surfactant solution's pH had a detrimental effect on the foam stability. The faster collapse of the foam at lower pH could be attributed to the repulsive interactions between the amine headgroups. The optimum initial pH was between 6 and 6.5 for salinity between 0 to 15 wt% NaCl. However, for higher salinity environment, 15 to 25 wt% NaCl, foam stability at low pH shows drastic improvement over its counterpart at lower salinities. At these high salinities, the optimal surfactant concentration was 0.50 wt%.

The application of the ethoxylated amine surfactant at different salinity levels has not been studied in detail. The application of this surfactant needs to be evaluated for optimum concentration, pH, and salinity. The effect of the surfactant's initial pH on the foamability and foam half-life has not been investigated. This paper addresses these gaps in literature and provides an optimized composition that can be applied for EOR operations.
A New, Low Cost CNG Ship, the Optimum
Authors: Fitzpatrick John , Stenning David
Published: November 2019

The quest to develop a low-cost, volume efficient CNG ship has been pursued for two decades. The optimum way to store compressed gas is to stack long lengths of hexagonal close-packed pipe horizontally in the holds of a ship. Past attempts to use this approach failed because as the ship flexes at sea, the pipes rub against each other which is clearly unacceptable. A novel technical solution has been developed and a ship design, based on this new "Optimum" technology, was recently Approved for Construction by the American Bureau of Shipping. This paper describes the technology, the ship, the design process and concludes with an economic evaluation.

By forcing long horizontal hexagonal stacked pipe tightly together within the hold of the ship the friction mobilized between the pipes creates sufficient shear resistance to prevent the pipes from moving and fretting in any circumstance. Based on this novel principle, a CNG ship with a capacity of 200 million standard cubic feet of natural gas was designed. The CNG-O-200 design was approved by the American Bureau of Shipping in January 2019 after three years of design, physical testing, computer modeling, and verification of safety and reliability. Some of the challenges addressed were: Determination of the forces and the mechanism needed to mobilize the friction,Design of the ship envelop, focusing on the midship section,The physical testing program to prove the system works,Developing a gas loading and discharge method was safe, simple and cost effective.

The main result of this work is a low-cost and volume efficient CNG ship that is Approved for Construction by ABS. On a volume equivalent basis, the size of a CNG Optimum ship is less than one-half the size of past CNG ship designs such as the Coselle CNG ship. This has significantly improved the economics of marine CNG shipping.

Marine CNG shipping has been an emerging technology and industry for many years with limited commercial success. Applications of marine CNG include markets that neither LNG nor pipelines have been able to serve, such as stranded offshore gas and smaller regional markets. This new low-cost and efficient CNG ship offers industry a new way to monetize stranded gas reserves and serve smaller regional gas markets.
Simplifying the Complex: Saturation Modelling in a Challenging Carbonate Reservoir with a Tilted Contact & Significant Imbibition in the Sultanate of Oman
Authors: Hadidi Shahab , Boya Ferrero Maria , Al Sadi Badar
Published: November 2019

The fluid fill concept of a complex carbonate reservoir of the Shuaiba Formation has been re-evaluated after 45 years of production. Structural changes post primary drainage resulted in a tilted contact towards the north east and water imbibition into the oil zone in a considerable volume of the reservoir. Rock facies change substantially vertically and laterally as observed from the 25+ cored wells and have camouflaged the fluid fill impact. Reservoir heterogeneity increases from the relatively homogeneous mud-dominated rock type in the central south-east to more heterogeneous grainstones and grain-dominated packstones further away. This paper demonstrates the value of using simplified and structured approaches to analyse saturation profiles to deduce possible fluid fill concept(s) and water saturation distribution.

The saturation profile with core permeability and core facies interpretation were used to identify imbibition, map the water table (imbibition) surface and recognize the trend of structural tilting post-charge. The central south-east area has negligible tilting and imbibition with a saturation model that could be simplified to primary drainage.

Above the water table, the mud-dominated rock saturation model was the reference point. Due to scarcity of wells unaffected by imbibition or tilt, a benchmark primary-drainage saturation model of analogue carbonate reservoirs was used to create a first-pass saturation model of the mud-dominated rock and identify entry height. The paleo-reference (original FWL) was reconstructed from the OWC picked from 72 vertical wells and smoothed by the general trend of tilt from the shallower seismic horizons. The workflow relied on using the mud-dominated rock saturation model to flag other rock types in uncored wells and possibly reducing the uncertainty in facies distribution. With the complexity at hand, difficulty in populating the facies between wells and time constraints, the water saturation below the water table was interpolated from all vertical wells.

The paleo-reference reconstruction indicates substantial tilting of the structure post-charge. One-third of the hydrocarbon volumes are in the imbibed region. The reservoir has been charged close to the irreducible water saturation and the majority of logged wells display paleo imbibed transition zones so it was not possible to utilize saturation-depth signature to identify a large number of distinctive rock types.

Due to the aforementioned, the saturation model for all of the reservoir rocks could be simplified by a single saturation function above the paleo-reference and a current water table depth.
Successful MPC Application for Ultra-Deepwater Well in South America: Case Study
Authors: Souza Leonardo , Sasso Alejandro de , Ribeiro Danilo , Guzman Jose
Published: November 2019

Exploration deepwater wells demand proper planning to mitigate any potential risks during well construction where uncertainty can play an important role. For this reason, designing dependable barriers under such a scenario requires innovative techniques, such as Managed Pressure Cementing (MPC). Using Managed Pressure Drilling (MPD), the operator can control the wellbore pressure while drilling each section. This unconventional solution for a short operational window has been successfully applied in some fields around the world, with additional advantages when cementing jobs are designed and executed.

The tight operational window expected for a 9-5/8-in. liner and the presence of gas were the main drivers to analyze the most likely scenarios for the cement job. The analysis describes that by managing the hydrostatic pressure of the fluids by applying pressure in the backside makes it possible to maintain control of the wellbore—without influxes or losses—before, during, and after the cement job. Nevertheless, to achieve the most reliable hydraulic modeling, critical parameters were identified for use as part of the input for a state-of-art cement simulator.

The scope of the cementing job for this case study was designed using a state-of-the-art simulation software to determine expected hydraulics outcomes. The main target was to maintain the bottomhole Equivalent Circulating Density (ECD) between 12.2 and 12.4 ppg during the entire cementing job operation. This 0.2-ppg margin was achieved by applying designed Surface Back Pressure (SBP) by using an MPC operational technique and finishing in a statically overbalanced condition. Dynamic pore-pressure and leak-off tests performed before the cement job confirmed the operating window. The information obtained was analyzed using appropriate software. This previous data was important to define appropriate fluids volumes and design to calculate the minimum SBP necessary for the safe execution of the job, always aiming to reduce chances of kicks and mitigate losses.

The cementing operation was performed according to the planned procedure, with no deviations, and the cementing job was performed in accord with the pumping schedule and SBP. Displacement was completed with zero mud losses, and lift pressure was observed as expected. MPC is a recommended method for zonal isolation in such cases as a small operational window, even more so when challenging deepwater scenarios are encountered. A case study of this cementing job is presented in this paper to discuss the planning process, details of the execution, and lessons learned.
Enhanced Well Remedial Decisions from Exact Location of Fluid Movement Behind Casing Identification
Authors: Croon Marcel , Huber Perry , Wright Jacob
Published: November 2019

Historically, acoustic wellbore monitoring is one of the main methods of detecting fluid movement behind the casing. Analysis of the complex acoustic environment in the wellbore can be challenging. A standard hydrophone noise tool is unable to measure flow directions (vertical and horizontal) and cannot detect low flow, low pressure sporadic events or multiple sources. This uncertainty may result in subjective acoustic interpretation leading to poor advice on remedial actions for wells with well integrity issues. A geophone array, including four 3-component geophones deployed via Wireline, provides a solution for this problem by creating a three-dimensional map of the acoustic environment. This acoustic profile, with accurately measured background noise levels throughout the length of the well, is then analyzed to confirm source locations and presence of flow (gas / oil / water) behind casing. The Unique geophone array configuration has allowed us to confirm source locations and flow paths of unwanted fluid flow for hundreds of conventional and unconventional production wells. Scenarios include wells with surface-casing or annular vent-flow issues, multiple source vent-flow situations, wells with cross flow between zones and integrity confirmation for gas storage caverns / zones. Since the detected flow is rendered into horizontal and vertical components, we can determine flow direction and accurately pin-point depth levels of fluid entry from the formation into the wellbore annulus. Geophone array noise logging has occurred in approximately 500 wells globally and the success rate for first attempt repairs is about 80% which is significantly higher than the typical 30% success rate.
Qualification of UNS N08028 and UNS N08825 Material as a Cost-Effective Solution for Extreme Sour Environment
Authors: Lamy Justine , Mizukami Akio , Millet Cécile , Néel Guillaume , Bouchart Nicolas
Published: November 2019

In recent years, Oil and Gas operators have faced new challenges with higher H2S partial pressure wells, especially in the Middle East. NACE MR 0175 part III provides guidance on the material selection for Corrosion Resistant Alloys; however, the well conditions considered by the Operator (total pressure 5526 psi, 1044 psi H2S, 279°F) are on the border of the UNS N08028 / UNS N08825 application domain, and therefore the recommendation would be to use a higher alloy, UNS N06985 material.

This paper describes a methodology to perform fine material selection for such critical conditions considering the representativeness of the testing condition and specific laboratory testing to qualify a suitable material for the intended application.

The objective was to evaluate the suitability of UNS N08028 and UNS N08825 material 110 ksi in the conditions described above. Based on actual reservoir conditions and fluid analysis, the test solution was defined to represent actual corrosiveness of the environment. Solution components, gas phases and in situ pH were defined using OLI® Stream Analyzer Thermodynamic software to reach the specified conditions at the test temperatures. Then, Stress Corrosion Cracking was assessed based on SSRT (Slow Strain Rate Test) as per NACE TM 0198-2016 [9], a rather conservative test as the material is stressed in its plastic domain; and C-ring as per NACE TM 0177-2016 [12], performed on rolled material to be representative of the final material surface finish.

All SSRT specimens showed a high ductility ratio and the absence of secondary cracking on the gauge section on both grades. All SCC C-ring specimens exposed to the environment successfully completed 720 hours exposure on both grades. Both UNS N08028 and UNS N08825 materials successfully passed the SSRT and C-ring tests, allowing the Operator to optimize the material selection by choosing a grade specifically qualified for their application and reducing the overall tubular cost by 30%.
Integration of Engineering Approaches and Workflows for an Economically Attractive Redevelopment of Highly Depleted Oil Rim Reservoirs - Giant Abu Dhabi Onshore Field
Authors: Meziani Said , Ghorayeb Kassem , Al Zaabi Najla , Hafez Hafez , Al Katheeri Abdulla , Maldonado Jorge , Khattak Iftikhar , Haryanto Elin , Chabernaud Thierry , Yersaiyn Saltanat , Kumar Sayani , Shahid Shawwal , Agam Abdelrahman , Shah Abdur Rahman , Chakraborty Subrata
Published: November 2019

This paper describes a pragmatic approach for reviving a highly depleted major Oil Rim Reservoir after more than 30 years of massive gas cap exploitation. The main objective is to assess options and identify the optimal plan to re-develop the Oil Rim while honoring and not jeopardizing the gas and condensate production of the network and the existing facility constraints.

An integrated workflow was designed and implemented to understand the reservoir geology, field production history and to address requirements of both oil rim and gas cap developments. Analysis started by a dynamic synthesis to track oil/water contact (OWC) and gas/oil contact evolution with time using available surveillance data: MDT pressure gradient analysis with petrophysical evaluation (RST & OH logs).

A study consisting of a comprehensive review and update of the static and dynamic models was carried out to ensure the model adequacy for robust re-development planning. The dynamic model quality was assessed by comparing dynamic model results with surveillance data especially with regard to predicting the contacts movements and pressure variation vs. time in the different regions of the Oil Rim.

Production forecasting and optimal re-development plan identification followed a systematic approach aiming at assessing the incremental impact on oil recovery through the utilization of artificial lifting, different types of wells and completion as well as a variety of water injection scenarios. Sensitivity analysis included horizontal well lengths, well density, well placement, water injection and production capacity as well as economic constraints.

Oil production from this low-pressure oil rim reservoir has been a challenge due to the spread oil resources and complicated production mechanisms. The movement of OWC and GOC has been very sensitive and caused unfavorable early water/gas breakthrough. Despite the low recovery factor, some attempts to revive dead oil wells through artificial lift means (ESP, booster pumps) were made and considered as an initial step to reactivate the inactive wells.

The low oil production volume and hence low recovery makes the oil rim re-development economically less attractive. However, integration of state-of-the-art engineering approaches, proposed innovative technical initiatives and new technologies create an opportunity for significantly more economically attractive re-development.

The workflows used and discussed in this paper were tested for four other oil rim reservoirs and can be implemented in similar challenging oil rim development projects.