bluuebunny/crossref_metadata_2025_split huggingface dataset:
HSE Closed Loop Drilling for Well Integrity
Authors: Abraham Jobin , Saleh Mujahed , Hadj-Moussa Ayoub 
Published: November 2019

Abstract
Offset wells in this region for the past 20 years were used as water disposal wells, having 40,000 bpd water production. Past decade observed remarkable decline in production leading to the development of the current well as a replacement while abandoning the previous well. The well was ranked as medium critical considered from its long water disposal period as no integrity test were performed due to the well location. The lithology of anhydrite alternation with limestone, dolomite and thin shale layers caused a risk of losses and differential sticking. In addition, this was a H2S bearing (100 - 119ppm) salt-water flow formation.
With a rotating control head in place with the flow line valve closed providing a closed loop system, the return is dumped to the sea through the extended diverter lines, ensuring that the H2S emissions are diverted away from the rig floor and from the manned complexes.
Total losses and sour water flow made closed loop flow drilling an engineering solution for its ability to ensure no H2S migration to the rig floor and continuity of the drilling operation with returns diverted away from the rig at all times. The introduction of side entry flow line on the rotating control device (RCD) allowed utilization of an additional fill up line planned to bullhead back to the formation preventing excessive gas migration.
Extensive planning of rig interface with rotating control head with side inlet connection from the standpipe manifold to manage time and space constraints in addition to losses management providing well continuity.
The well drilled successfully with a rotating control device- RCD at surface and returns diverted safely. The closed system with rotating control device - RCD and a well head pressure monitoring gauge provided an additional security of analyzing well conditions, though risk of having gas influx was initially identified as a medium hazard being a top hole section with a higher chances of losses while drilling.
As circulation and conditioning was done traces of gas and H2S were observed with an increase in pressure observed at the RCD. Bullheading from the side inlet of the RCD from standpipe was utilized to balance the well eliminating the risk of high exposure of H2S gas at surface. Having the only pressure monitoring system in place with the RCD the overhead pressure could be identified to raise the mud weight and to balance the well. This operation was successful and resulted in zero gas at surface with casing and cementing operations on the well conducted safely without any quality, health or safety issues.
Understanding the risk of less information about the formation led to the approach of utilizing a low pressure rotating head system to drill safely into a H2S risk zone. This paper identifies how a previously used system, could have an innovated approach to drill safely in a total loss and H2S prone formations.
Rotating Equipment Switchover Dashboard
Authors: Alzahrani Khalid , Alzahrany Abdulaziz 
Published: November 2019

Abstract

CONTENT
This Instruction outlines the procedures for testing spare pumps. The text includes: DefinitionResponsibilitySwitching IntervalsSwitching TimeSwitching ProcedureSwitchover Dashboard

DEFINITION
This procedure outlines switching between "Main Pump" (running pump) and "spare pump" (the one to be tested). All other type of equipment's (rotating and/or stationary) will be switchover based in the following:PM (Preventive Maintenance) program.Inspection ProgramTest and Inspection T&I program

STRATEGY OBJECTIVES

RESPONSIBILITY

Operation Superintendent:

Area Operation Foreman:

Reliability Engineer:

SWITCHING INTERVAL
Switching between spare pumps and main ones shall be done once every 4 to 6 weeks to ensure the equipment availability and reliability. It shall coincide with the monthly vibration survey. For the compressor lube oil system, the functional test is preferred to be scheduled before a planned compressor shutdown.
Discussions were held with the rotating equipment manufacturers, specialists and users to clarify all corrosion, electrical and mechanical concerns regarding the switching periods between alternate pieces of rotating equipment. The compilation of all of these discussions and concerns resulted in the following two basic guidelines which within themselves comprise the heart of the Rotating Equipment Operating Strategy.

A. MEDIUM VOLTAGE EQUIPMENT (Higher than 600 V up to 13.8 KV):
Equipment of this voltage type should be switched from the stand-by mode to the operational mode once per month.
Note: Excluding any stand-by equipment that is not required by Operations should be run a minimum of one continuous hour every month.

B. LOW VOLTAGE EQUIPMENT (Equal or Less than 600 V):
Equipment of this voltage type should be switched from the stand-by mode to the operational mode once every two weeks. This includes the switching between the main and auxiliary lube/seal oil pumps.
Note: Excluding any stand-by equipment that is not required by Operations should be run a minimum of thirty continuous minutes every two weeks.

SWITCHING Time
Switching between critical pumps shall be conducted during the normal working days in day time where the support organizations are available.

SWITCHING PROCEDURES
This RIM covers four different pump startup scenarios. Each one of these scenarios includes important checks and procedures that need to be followed to ensure a reliable pump start-up. Below you will find a detailed start-up procedure for each scenario. The procedure will be detailed but general, additional steps may be required for some particular process.

FOLLOW UP PROGRAM

Key Performance indicators (KPI's)
Switchover = (Total Equipment comply with switchover/Equipment Schedule Switchover) X 100%, Target 90%
Note:
Switchover the pump:

START-UP AND STOPPAGE FOR DEFERENT TYPE OF ROTATING EQUIMPMENT
First Retrievable Application of Lower Completion Stimulation Technology
Authors: Almaawali Sultan , Kumar Kamlesh , Awang Zaini , Duvenhage Viljoen 
Published: November 2019

Abstract
New operational application using a field-tested stimulation technology that was previously only available as a permanent installation as part of the lower completion was recently successfully applied as a retrievable option. This alternative installation method reduces rig time, overall project cost and returns the wellbore to Open Hole should it be required for post stimulation logging or future interventions. The lower completion stimulation technology consists of standard liner pipe that is made up offline to short Subs and the sub-assemblies are then preloaded with four tubes up to 40 feet in length, each tube with a jetting nozzle on the end. The liner string with casing packer was run into the open-hole well section with Subs positioned across the formation where stimulation was required. 15% HCl acid was then pumped at the designed rate that resulted in the penetration of the tubes into formation. Post stimulation the complete liner assembly was then retrieved by releasing packer with straight pull and shearing tubes that has entered the formation (the penetrated needles remain inside the formation). Many operational challenges were overcome by the PDO's drilling team in order to complete this first of its kind installation utilizing multiple running string combinations and a small work over rig (Max 125 kdan) in order to keep the overall project cost down.
Evaluation of Probability Point Estimate Methods for Uncertainty Analysis of Hydrocarbon in Place as an Alternative Techniques to Monte Carlo Simulation
Authors: Algdamsi Hossein , Amtereg Ahmed , Agnia Ammar , Alusta Jamal , Alkouh Ahmed 
Published: November 2019

Abstract
Typically, the Monte Carlo simulation (MCS) approach was generally applied to assess and quantify uncertainty in probabilistic reserve estimates and improve risk decision making, regrdless of that it can be quite computationally intensive, MCS method has the advantages of generating possible outcomes That contain more information relative to deterministic and scenario approach by taking into consideration the uncertainty associated with the range of various input variable. However, MCS entails that the probability distribution functions of all uncertain input parameter be entirely known, this might be an obstacle or limitation on successful implementation of MCS as subjectivity on the selection and definition of the input variable distributions and their characterization or due to incomplete information and lack of data will critically impact and limit both its proper application and interpretation of the results and consequently doubt statistically the robustness of the solution. This shortcoming of MCS and difficulty can be circumvented by other complementary method like the PEM, first-order second moment (FOSM) or Warren’s probability analysis methods which does not require a previous knowledge of the range and distribution shape to be defined or condition where information concerning uncertain parameter is not sufficient or reliable, moreover it has the advantage of less computational requirement to attain solution with comparable accuracy. This paper provides a comparative assessment of Point Estimate Method (PEM) for analyzing uncertainty of hydrocarbon in place as more practical alternative approaches to Monte Carlo simulation (MCS). Five PEM Rosenblueth, Harr, Che-Hao et al., Geethanjali et al. and Hong 2n scheme algorithm were used to model output uncertainty of hydrocarbon in Place for more than 20 field and predict P10, P50 and P90 using different PEM Technique. MSC result was generated for the same fields with an optimum number of samples for key variable using stability analysis and statistical measure of model run convergence which are benchmark to which the PEMs’ results are compared.
Deep Learning and Hybrid Approaches Applied to Production Forecasting
Authors: Shoeibi Omrani Pejman , Vecchia Adrian Luciano , Dobrovolschi Iulian , Van Baalen Thijs , Poort Jonah , Octaviano Ryvo , Binn-Tahir Huzaifah , Muñoz Esteban 
Published: November 2019

Abstract
Reliable forecasting of production rates from mature hydrocarbon fields is crucial both in optimizing their operation (via short-term forecasts) and in making reliable reserves estimations (via long-term forecasts). Several approaches may be employed for production forecasting from the industry standard decline curve analysis, to new technologies such as machine learning. The goal of this study is to assess the potential of utilizing deep learning and hybrid modelling approaches for production rate forecasting.
Several methods were developed and assessed for both short-term and long-term forecasts, such as: first-principle physics-based approaches, decline curve analysis, deep learning models and hybrid models (which combine first-principle and deep learning models). These methods were tested on data from a variety of gas assets for different forecasting horizons, ranging from 6 weeks to several years. The results suggest that each model can be beneficial for production forecasting, depending on the complexity of the production behavior, the forecasting horizon and the availability and accuracy of the data used. The performances of both hybrid and physical models were dependent on the quality of the calibration (history matching) of the models employed. Deep learning models were found to be more accurate in capturing the dynamic effects observed during production – this was especially true for mature fields with frequent shut-ins and interventions. For long-term production forecasting, in some cases, the hybrid model produced a greater accuracy due to its consideration of the long-term reservoir depletion process provided by the incorporated material balance model.
Real-Time Structural Risk Assessment for Offshore Asset Management
Authors: Atia Mohamed , Keys Matt , Omar Tarek 
Published: November 2019

Abstract
Middle East offshore platforms installations started in the early 60's and continue today. Managing asset integrity and demonstrating compliance is increasingly challenging due to frequent brownfield modifications, increased safety factors with the introduction of international standards, changes in metocean data and age deterioration. From work with North Sea, Gulf Region and Asia Pacific operators, an approach was developed to manage ageing assets using real-time structural risk assessments and operational procedures that ensures consistent risk levels of life safety and environmental for all assets and is applicable to all regions.
Utilising the improved accuracy of modern weather forecasts, in combination with structural reliability, a methodology has been developed to determine the forecasted risk level for any critical element. This is updated live, with each new weather forecast, to provide proactive notifications and alerts so operators have more up to date knowledge to make decisions on their assets. A live web-based system can be utilised to display this information.
The approach splits the three risks of life safety, environmental and structural damage into separate requirements and calculates the probability of failure, which will lead to each of the three consequences, for the critical component or the overall structure. The risk is evaluated and compared with the industry standard and the operators own acceptance criteria to determine if operational procedures need to be enacted to reduce the consequence. It has been found that the acceptable risk levels for the ‘in a forecasted storm’ risk are governing over the traditional design ‘annual’ risk levels.
If at any point in time the probability of a wave height approaching the field exceeds the maximum allowable for a structure, the system issues timely alerts and warnings to the relevant stakeholder for their actions. The operator then has the option of de-manning or shutting down operations to maintain the risk levels for life safety and environmental at ALARP (as low as reasonably practicable) levels. The system also provides information for post-storm structural damage likelihood.
A combination of online monitoring, inspection and/or asset loading history, which can be incorporated using Bayesian updating methods, and advanced assessment have been used to reduce the occurrence of enacting operational procedures for structures that are non-code compliant to greater than every 10 years while also reducing the annual risks.
An additional advanced feature can be utilised by connecting installed accelerometers to the structure for continuous live streaming of the structural response which can issue alerts if any damage is suspected.
Miscible N2 EOR in a Giant High Temperature Complex Carbonate Reservoir
Authors: Xu Siqing , Mogensen Kristian , Al Shehhi Budoor , Mabrook Maged , A. BinAmro Ahmed , E. Ali Ahmed 
Published: November 2019

Abstract
In this paper, we investigate the potential for applying miscible nitrogen injection as an enhanced oil recovery (EOR) method for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field, which is located onshore Abu Dhabi, is still in its early development phases but suffers from relatively low throughput rate because of low permeability. Various gas injection schemes are being considered, with different source gases. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas.
The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10 to 20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N2 WAG scheme, and the ability to maintain a higher reservoir pressure (at initial reservoir pressure).
From a surface facilities point of view, techniques for N2 capturing is mature, tried and tested. N2 being inert does not pose corrosion risks to well completion and surface facilities. However, capital costs for N2 rejection units – if utilised in a N2 WAG EOR scheme – will need to be taken into account. Although N2 WAG EOR is seen to be very attractive for the reservoir under study, alternative EOR schemes are also being actively evaluated. The aim is to arrive at an optimum EOR project for the reservoir in line the achieving the 70% oil recovery aspiration.
Combined Solution for Lost Circulation Treatment to Successfully Drill Through Naturally Fractured Vugular Porosity Formation on ERD Wells in the UAE
Authors: Bermudez Romulo , Abdelkerim Doutoum Mahamat Habib , Al Azizi B. , Nour Mahmoud , Medina Ruben , Bereikaa Hesham , Rocha M. C. , Nasrallah M. M. 
Published: November 2019

Abstract
While drilling through the initial section of extended reach drill (ERD) wells in Abu Dhabi where the trajectory requires a high inclination across a recognized loss zone various options were required to be assessed to maximize efficiency while balancing risks. Factors such as loss rate, capability of mixing fluid, necessary density to help prevent flow from a shallow water-bearing zone, and rig time, where all necessary and key factors to consider in the design process.
For this UAE field with common losses in the surface casing, brine capping was determined the best solution to continue drilling without generating nonproductive time or creating a possible wellbore instability issue when unable to keep up with building mud to offset mud losses. For wells with a higher inclination angle, when the loss rate reached the point where it was not possible to prepare the fluid to keep up with losses, it was necessary to identify a different solution to cure or significantly reduce the losses and enable the hole section to be drilled without potential operational risks.
For vugular/fractured porosity formations, using tailored particle size materials was unsuccessful for curing the losses. Therefore, a unique solution was implemented by combining two different systems to battle the losses: a swelling polymer lost-circulation material (LCM) that hydrates and helps reduce flow velocity into the formation, followed by a shear-rate rheology-dependent cement system that is a tunable and tailored slurry with thixotropic properties, which stops losses and develops low compressive strength. With this combined solution, the drilling process was successfully resumed and completed.
The usual loss rate for this particular vugular argillaceous limestone formation is between 600 and 800 bbl/hr while drilling. Once the solution was successfully implemented, losses were reduced to 15 bbl/hr. The technique was performed on a second well, applying the lessons learned from the first attempt, and the unique solution achieved a dramatic reduction of losses to 2 to 6 bbl/hr. The cost and effectiveness of the treatment demonstrated that this solution is best for optimizing the drilling process for this particular condition.
Applying a swelling polymer LCM and the shear-rate rheology-dependent cement system cured losses for an argillaceous limestone formation with fractured/vugular porosity. It is the first global application of this combined solution.
Energy Savings of Amine Sweetening Process Through Rich Solvent Recycle Approach and Low Stripper Operating Pressure
Authors: Al Hatmi Khalid , Al Mashrafi As'ad , Al Balushi Sa'ud , Al Battashi Mundhir 
Published: November 2019

Abstract
The amine sweetening process is one of the most matured technology that deals with acid gas removal. However, energy consumption is considered as a prominent concern for amine absorption process due to the significant energy requirement for amine re-boiler. In previous paper (SPE-192731-MS), we discussed the effectiveness of two promising debottlenecking approaches for amine sweetening process namely; lean vapor compression (LVC) and rich vapor compression (RVC). This paper objective is to study the effectiveness of Rich Solvent Recycle (RSR) and low stripper operating pressure on pre-combustion amine absorption process.
The study used ProMax 4.0 simulator, which has been well proven to have a high accurate prediction for amine sweetening processes calculations. For RSR approach, the rich solvent leaving the bottom of absorber has been divided into two streams in which one is recycled back to the bottom of the absorber and other stream continues to the same normal path as for conventional amine process configuration. The flow ratio between recycled stream to the forward stream has been optimized to provide the minimum overall duty. For the stripper operating pressure approach, the impact of lowering the pressure on re-boiler duty has been studied for two different plants. For all scenarios, the treated gas acid gas concentration and system operating window were kept as constant. The proposed approaches have been simulated in two existing two amine-sweetening plants currently under operation by Petroleum Development Oman (PDO) for H2S capture (i.e. Plant-A) and the other one for CO2 capture (i.e. Plant-B). .
The results indicate that rich solvent recycle (RSR) debottlenecking approach potentially could result in lower re-boiler duty by maximizing the solvent/acid gas contact at the bottom of the contactor with a potential energy saving of 20% for Plant-A. The ratio between recycled streams to the forward stream has been manipulated to achieve optimum energy consumption. For stripper operating pressure, it has been found that the re-boiler duty decreased due to lower operating pressure.
The study has focused on pre-combustion amine absorption process unlike most of the published studies, which focused on post-combustion processes. In addition, in this paper live plants data were used to examine the simultaneous impact of different parameters.