bluuebunny/crossref_metadata_2025_split huggingface dataset:
Risk Assessment Suite - An Innovative Approach of Risk Mitigation Measures Prioritization for Well Integrity Assurance
Authors: Amrideswaran Hareesh , Al-Sada Abdulhameed Ali , Saleh Mohammed Ali Abdulla 
Published: March 2015

Abstract
Well Integrity Assurance is the key concept to reduce the risk of unwanted incidents in any oil & gas field, thereby ensuring safety of people, environment, assets, business and reputation during the entire well life cycle from Conception to Abandonment. Due to a huge number of wells and the ever-increasing matured field issues, the key challenge faced by Qatar Petroleum was to prioritize the remedial measures (rig & rigless) and pro-active health checks based on well risk conditions and barrier status. In this paper, we are elucidating the Risk Assessment Suite created by the Well Integrity Department of Qatar Petroleum to resolve this challenge.
The Risk Assessment Suite is an innovative model to assess the integrity issues in oil/gas wells, to establish their associated risk level and to prioritize the mitigation measures/pro-active health checks in those oil/gas wells based upon the risk level and optimum available resources for ensuring that the wells operate in a safe operating envelope. The four major components of the risk assessment suite are Risk Ranking Guidance Matrix, Well Failure Matrix, Priority Ranking Matrix, and Well Risk Assessment Sheet.
The Risk Assessment Suite is a highly successful methodology practiced in Qatar Petroleum for assuring safety, well integrity, higher return on assets and performance enhancement of its oil & gas fields. The highlight of this suite is its unique innovative model for prioritizing the rig/rigless repairs and pro-active routine/non-routine health checks by considering priority ranking points together with risk ranking as a single function in order to address both risk level and the barrier failure intensity of a well at the same time.
Risk Assessment Suite is a highly transferable model that can be used by other E&P companies worldwide with similar requirements like Qatar Petroleum for prioritizing remedial measures and risk mitigation actions on oil/gas wells in their fields.
A Slow Release CO2 for Enhanced Oil Recovery in Carbonate Reservoirs
Authors: Alam M.M. Mansoor , Mahmoud Mohamed , Sibaweihi Najmudeenn 
Published: March 2015

Abstract
CO2 is used to swell the oil and increase its mobility by reducing the viscosity and reducing the IFT between the rock and oil. The problem of CO2 during the EOR process is the gravity override and the displacement efficiency. Foamed CO2 was introduced to overcome the displacement efficiency problem. The foam can be generated using different types of surfactants. The surfactants will not from a stable foam at HPHT conditions and the reservoir water salinity will impact the foam quality in addition to the surfactant adsorption to the carbonate rocks will reduce the surfactant concentration and will affect the generated foam.
In this study we will investigate the use of slow release CO2 concept. The CO2 can be slowly released in the carbonate reservoir by injecting low reaction rate fluids (in this case citric acid) that will react with the rock after placement and this will generate CO2. Coreflooding test will be performed using carbonate core at 100°C saturated with crude oil. CMG will be used to simulate the process of CO2 generation by injecting the CO2 in an aquifer underlying the carbonate formation and after that allow the CO2 to release to the oil zone. The slow released CO2 from the aquifer will swell the oil and then the oil can be displaced by sea water.
Coreflooding results showed that the slow release CO2 technique gave up to 42 % extra oil recovery from the oil in place after sea water flooding into the carbonate core at 100°C and 1100 psi back pressure. The extra oil recovery was due to the slow resealed CO2 and oil swelling and also due to the rock dissolution and IFT reduction. The simulation results by CMG showed that the slow release CO2 technique gave 70% oil recovery from the residual oil more than the sea water injection which confirmed the efficiency of the slow release technique in large scale.
Nano-Confined Adsorbed and Free Gas in Shale Reservoirs: A Molecular Dynamic Study
Authors: Stukan Mikhail , Abdallah Wael 
Published: March 2015

Abstract
Gas production from shale reservoirs is expected to last for hundred years by some estimates. However, the phase behavior of gas in shale reservoirs is inherently more complex compared to the conventional ones. In shale reservoirs, a large amount of gas is stored in nano-size pores which are an integral part of kerogen structure. The phase behavior of this fluid is significantly different from those in the bulk and is still far from being fully investigated. Better understanding of the influence of nano-confinement on the fluid phase behavior should help in estimating the amount of gas in place and to develop an optimum production plan to maximize the recovery.
Using molecular dynamics simulations, we modeled methane's phase behavior in shale gas reservoirs wherein the nano-pores in the kerogen play a major role in adsorption of the gas molecules. A fully atomistic model was used for methane and the pore walls; the pore walls were represented by graphite sheets. Eight pores of width ranging from 0.7 nm up to 4.0 nm were considered; the pores were connected to a bulk volume (reservoir). The amount of free and adsorbed gas in the pores was calculated in the pressure range from 6000 to 100 psi.
The results demonstrate the influence of pore size on the mechanism of gas release and its dynamics. The gas production rate from pores is a result of the interplay between the rate of transport of a free gas molecule out of the pore, and the rate of desorption of the adsorbed gas from the pore wall. For the smallest pores, adsorption plays the main role in controlling the dynamics as compared with the large ones. Our data can be utilized for predicting the rate of gas production from shale gas based on the pore size distribution and fluid composition.
Selection of Best Reserves Estimation Methodology to Quantify and Reduce the Uncertainty – Accompanied by Çayirdere Gas Field Case Study
Authors: Tugan Murat Fatih , Onur Mustafa 
Published: March 2015

Abstract
Uncertainty in reserves estimation plays a critical role at all-time steps of production/development plans and determines the financial strength of the project and the company. In this study, the importance of probabilistic approach to reserves estimation is emphasized by showing change in the estimated values of reserves with producing time. An analytic uncertainty propagation method (AUPM), a simple, yet quite accurate alternative uncertainty quantification method to the well-known Monte Carlo method, is used to assess the uncertainty in gas reserves estimations. In addition to the theory, as a case study, one of the largest Turkish Petroleum Corporation (TPAO) gas field, Çayırdere Field, reserves is estimated, and uncertainties for this field reserve are presented at all-time steps. As a result, the estimated value of the most likely reserve (P50) by utilization of AUPM in conjunction with probabilistic methodology prior to production period, matches quite well with the value estimated at the abandonment of the reservoir by using performance-based methods. The Çayırdere Gas Field Case Study supports the glorious success of the approach promised in this study.
Renovating Bahrain's Field: Improving Production Testing Efficiency
Authors: Naser H.H. , Zainal Y.A. 
Published: March 2015

Abstract
Production testing of wells in Bahrain field historically was carried out at Well Manifolds using 2-phase test separators, mechanical liquid meter and gas chart recorder. Flow line liquid samples were collected for water cut measurement. Production fluid was diverted to test separators using manually operated valves on production and test headers. When Tatweer Petroleum took over operation of Bahrain field in late 2009, there was a need for more well testing to improve surveillance of wells performance and accommodate new wells added through aggressive drilling program. This was possible through contracting well testing services to assist in handling the increased number of well tests and also validate tests of the company owned Test Separators.
In 2012, 3-phase test separators were introduced as replacements to the old, undersized 2-phase test separators. The new separators are equipped with oil, water and gas meters, and automatic level and pressure controls. When the new testers were first introduced, they did not perform well and only one third of the tests were validated as “good” by Production Engineers. A multi-disciplinary team was set up and tasked with developing a work plan to solve problems with the new test separators in order to improve validation of well tests. The team addressed several issues including chemical injection, instrumentation, automation of well testing process, capture test data into software applications, trouble shoot wells, develop KPIs, and train operators.
As a result of the team's effort, well testing performance has significantly improved. Well test validation has increased from 30% to 90% and the number of daily well tests doubled from 32 to 64. With this improvement, the company was able to reduce the contracted well testing service and reduce cost. Additionally, through quality well testing, there was an improved understanding of individual wells performance, thus allowing better production optimization and reservoir management.
Combining Horizontal Production Logging and Distributed Temperature Interpretations to Diagnose Annular Flow in Slotted-Liner Completions
Authors: Haoua T. Ben , Abubakr S. , Pazzi J. , Djessas L. , Ali A. M. , Ayyad H.B. , Boumali A. , Boulkaila Z. , Brahim M.H. 
Published: March 2015

Abstract
Production logging in horizontal wells has been challenging due to phase stratification and complex flow regimes. New technologies were introduced to properly characterize such flow dynamics; however, adding a new complex completion strategy, such as a slotted liner, raises the challenge to a new level. When a slotted liner is not equipped with a hanger, two flow paths become possible—one inside the slotted liner and the other outside it—with possible fluid exchange between the two paths. Production logging tools can only see the inner flow. The lack of information about the outer flow raises uncertainties about the real producing zone(s) and may affect the success of future well intervention operations.
We describe a new methodology that combines multiphase production logging measurements with distributed temperature survey data. Both sets of data were acquired simultaneously during conveyance of the production logging tool on coiled tubing. The production logging data offers insights into phase distribution and enables production profiling inside the slotted liner; distributed temperature data solves for total formation production. Combining the two interpretations enables quantification of flow in each of the two paths and helps identify the fluid exchange between them, which would otherwise be misinterpreted as fluid entry from the formation. The result of this integrated interpretation methodology is accurate determination of zonal contributions.
Integration of Reservoir Performance and Geoscience Studies in the History Match of a Complex Carbonate Reservoir – a Case Study from the Magwa Marrat Reservoir - Kuwait
Authors: Jadi Menayer Al , Kumar Pranay , Lislaud Frederic , Robert Joël , Alessandroni Mauro , Lefebvre Christian , Groen Vincent de , Vigier Louise , Datta Kalyanbrata , Hafez Karam , Taneja Hans , Bhattacharya Muktibrata , Bond Deryck 
Published: March 2015

Abstract
An integrated reservoir study of the Magwa Marrat reservoir has been completed recently. This study was carried out to support the continued development of the reservoir, in particular the planning of a secondary water flood.
The initial part of the study concentrated on reservoir characterization and reservoir performance over a long period, in the order of 30 years, of primary recovery, followed by analysis of a recent pilot water flood. A better understanding of the controls of flow and the role of fracture corridors and diffuse fractures was achieved through and integration of geophysical, petrophysical and dynamic data including tracer tools and in particular through a dynamic model of the water flood pilot. The uncertainties related to structural extension, especially on the flanks of the field and related to aquifer support, were also recognized.
Later on static and dynamic models were built, first around the pilot water flood area and then for the entire reservoir. These models have been used for development planning.
This paper gives an overview of the integrated study but concentrates on the features, detailed below, that were key to better understanding the fluid flow physics and to achieve a satisfactory “history match”.
A single porosity model that accounted for matrix permeability, local enhancement to permeability within restricted fracture corridors and the effect of diffuse fractures in “tight” zones was adopted. Matrix permeability values were based on the results of a rock typing study. Static and dynamic pressure, oil production and water movement matching was achieved by making limited and realistic changes to fracture zone permeability, fracture zone extent and some fine tuning of matrix permeability. Well productivities, pressure transient tests, interference tests and production log data were used to guide and validate the history match.
Water-cut match was further improved by making reasonable changes to the structural model in regions where significant structural uncertainty was recognized.
BBS Implementation in the Middle Eastern Oil & Gas Environment -Moving Ahead
Authors: Al-Failakawi Ali , Al-Qallaf Yousef , Adivi Bala Siva 
Published: March 2015

Abstract
This paper describes one successful approach of Behavior Based Safety (BBS) implementation in Oil & Gas Company in Kuwait. The unique approach involved tailor made approach and implementation has been done through the very basic building blocks. Much emphasis was placed on understanding the Middle Eastern Social Culture, organizational culture including the HSE culture and then designing the BBS program to suit the cultural norms.
Several organizations in the Middle East Region have implemented in-house versions of Behavior Based Safety (BBS) programs such as STOP, ASA, SOC, and so on. However, these programs have been driven by Key Performance Indicators (KPI) and therefore suffered from number-crunching instead of focusing on quality execution and effectively influencing behaviors. Quite a few BBS consultants have attempted to implement their respective copyright BBS programs in this Region. There has been varying successes.
Gas Lift Optimization using Artificial Neural Network
Authors: Ranjan A. , Verma S. , Singh Y. 
Published: March 2015

Abstract
Due to the increasing number of brown fields and lessening of huge oil discoveries maximizing recoveries by artificial lift techniques can be a compensating factor to balance the demand to supply ratio. Gas lift holds a promising aspect in this regard especially for offshore platform where every square inch costs thousands of dollars and space is limited. Gas lift occupies very little space at the wellhead and many directional wells can be drilled close together and easily produced. Although gas lift optimization has been attempted using soft tools like fuzzy logic, pattern recognition and intelligent network, none of them holds promises as big as artificial neural network. The gas lift optimization considered in this paper is to maximize the daily hydrocarbon production by selecting optimally the lift gas rates. The procedure utilizes well test information and calculations of vertical two phase flow behaviour to predict field producing rate responses to changes in gas input rate. Nodal analyses, gas lift databases and gas lift monitoring system are among the tools applied to meet the objective by training and testing various ANN models by varying number of neurons in each layer, learning rate, training type, epoch and minimum error. It is confirmed that in comparison with the models previously published in literature our ANN model has a better accuracy and performance in optimizing the gas lift rate.
PICD Performance Evaluation Study for Carbonate Field Using Post Installation PLT and Production Data
Authors: Lee Byung , Galimzyanov Artyom , Faizal Syed Abu , Vicario Roberto 
Published: March 2015

Abstract
Passive Inflow Control Devices (PICD) are a common completion method for horizontal wells. A PICD completion can not only equalize the fluid influx along the length of the horizontal well but also can delay breakthrough of unwanted fluids and solve the challenges associated with uneven reservoir heterogeneities. Saudi Aramco is now the world leader in the use of PICD technology.
Since the first installation of PICD in 2002, Saudi Aramco utilized various types of PICD for their sandstone and carbonate oil fields. Among these fields, one particular carbonate field was selected to study the performance of PICD completion and assess its effectiveness over barefoot completion. Production logs from 22 post-installation horizontal wells with PICD from the subject were analyzed. A near-wellbore simulator was used to match the actual fluid influx in PICD completion obtained from production logs. The matched model was used to simulate the flux profile for the openhole case and well performance was compared with PICD case. As part of the evaluation, production history of the PICD installed wells was also studied. Time-to-water breakthrough and increase in water-cut trends for PICD-installed wells were investigated to find how PICD design can improve fluid flux along the horizontal well and delay unwanted fluid. This exsercise helped identify optimization design guidelines with regards to number of compartments, PICDs per compartment and the process of dealing with uncertain changing well conditions in naturally fractured carbonate field. Dynamic modeling was also performed to evaluate the suggested PICD design recommendations with respect cumulative oil production and water breakthrough deferment.
This paper describes the detailed evaluation methodology, analysis results for the selected field and subsequent recommendations for design practice to maximize the value of PICD.
Successful Implementation of CO2 Energized Acid Fracturing Treatment in Deep, Tight and Sour Carbonate Gas Reservoir in Saudi Arabia that Reduced Fresh Water Consumption and Enhanced Well Performance
Authors: Malik Ataur R. , Dashash Alaa A. , Driweesh Saad M. , Noaman Yousef M. , Soriano Eduardo , Lopez Alfredo 
Published: March 2015

Abstract
Up to three thousand barrels of stimulation fluids are pumped during a single vertical fracture treatment in carbonate reservoir of Saudi Arabia with the objective of creating sufficient conductive reservoir contact for commercial production. The post-stimulation production performance in deep, tight, and sour carbonate gas reservoirs often does not meet expectations due to complex reservoir characterization and poor transmissibility. The post-stimulation cleanup period often takes much longer due to resistance in unloading the pumped fluids.
Carbon dioxide (CO2) with 30% foam quality (FQ) has been introduced for the first time during acid fracturing treatment in the tight, sour and high pressure, high temperature (HPHT) carbonate gas reservoir of Saudi Arabia to reduce consumption of fresh water, minimize reservoir damage, reduce the flowback period and eliminate the need for nitrogen lifting with coiled tubing (CT). The water and acid volume were reduced by one third through energizing the fluids system with CO2 during acid fracturing treatment in the candidate well. The Pad fluid was a zirconate crosslinked gel that was optimized for low pH to maintain stability in the presence of CO2. To minimize fluid leak-off and improve diversion effects, a chemical diverting system was included in the CO2 energized acid fracture treatment. A non-emulsifier foaming agent was used in the Pad and acid blends to create the desired emulsion with CO2. The post-fracture flowback period was reduced significantly and a 2.5 fold increase in the gas rate was realized.
The addition of liquid CO2 to HCl in quantities sufficient to produce emulsion allows live acid to retard and penetrate much deeper than HCl itself. The CO2 strips hydrocarbon from the rock and allows acid to effectively react to the rock surface. CO2 remains in the liquid or supercritical phase during injection mode and flows back in the gas phase over a wide range of temperature and pressure allowing pumped fluids to recover in fast and safe manner.
This paper is focused on laboratory tests of fluid systems, and the design, execution and evaluation of CO2 energized acid fracturing treatment, and a safe flowback strategy used for sour wells with high a concentration of CO2.
Coiled Tubing Conveyed Video Camera and Multi-Arm Caliper Liner Damage Diagnostics Post Plug and Perf Frac
Authors: Ashby S , Al-Shamrani S , Hansen J , Almutairi T , Al-Mulhim A 
Published: March 2015

Abstract
This paper describes the experiences of utilizing coiled tubing and its conveyed diagnostic tools, following a multi-stage plug and perf acid fracturing treatment performed in a highly deviated well. A downhole video camera and multi-arm caliper run on coiled tubing were used for the first time in Saudi Aramco gas wells.
The well is a gas producing well in a thick carbonate structure and was drilled at a high angle to intersect several different porosity layers within the formation. The well was also drilled at 30 degrees to the minimum stress direction to allow the creation of transverse fractures from each frac stage. The final completion consisted of five frac stages spaced out along the interval separated by four bridge plugs. Following the completion of the fracturing operations the initial attempt to mill the plugs was unsuccessful as the milling tools were unable to reach the depth of the first plug. At this stage the well was potentially lost due to suspected damage or deformation to the liner caused during the fracturing.
A series of diagnostic runs was performed with coiled tubing and a milling strategy formed from the results. The diagnostics included first time use in the area gas wells of a downhole video camera and multi-arm caliper conveyed on coiled tubing.
The diagnostics were successfully completed and analyzed. From these results the required milling tool diameter was determined and a milling bottom-hole assembly was designed. Coiled tubing was re-mobilized and the plugs were successfully removed from the liner allowing full bore access and the well to be flowed back.