bluuebunny/crossref_metadata_2025 huggingface dataset:
First Successful Openhole Lateral Multistage Acid Frac in a Complex Unconventional Carbonate Reservoir North Kuwait
Authors: Al-Enezi Badriya , Al-Mufarej Mishal , Ashqar Ayham , Navia Alejandro
Published: November 2017

Openhole (OH) multistage fracturing (MSF) is increasingly used to stimulate and maximize production within low-permeability reservoirs in unconventional plays globally, extending its use from tight sands, shales, and carbonate reservoirs. Technological breakthroughs in hydraulic fracturing have helped enable OH MSF within lateral sections.

The target reservoir is a tight heterogeneous carbonate with unsustainable productivity. The hydrocarbon produced is oil of relatively low API and gas/oil ratio (GOR). Given the challenging nature of the unconventional Mauddud reservoir of the Bahrah field, a sophisticated design of both the well completion and fracturing treatment is necessary to achieve the North Kuwait strategic production targets by maximizing reservoir contact and enhancingwell performance.

A long horizontal well was drilled within the Mauddud reservoir. Completion technology was based on distributing swellable packers along the lateral section to develop MSF acidizing.

The multistage packer and port designs were based on the reservoir mechanical and formation properties, to achievethe best fracture extension. Fracture acidizingwas performed on each stage, the well was flowed clean, and an electrical submersible pump (ESP) was run to produce the well. A production logging tool (PLT) survey was run immediately after fracture acidizing and six months after production. The recorded data indicated different contribution profiles of the stages, which indicated the fractures and production within such reservoirstake time to stabilize.

This paper describes and addresses the effectiveness of MSF. Additionally, MSF performance in horizontal vs. vertical wells is assessed. Well performance analysis, exploitation approaches, and successful implementation are discussed, highlighting the advanced completion technology applied. The PLT results at different stages of the well life (post-acidizing and after ESP installation) are discussed. A comparison between the multifracture within the lateral section and vertical fractured well showed the benefit of the technology used to boost and sustain production. Effective horizontal drilling and MSF have helped enablethe development of unconventional resources, which were considered economically unfeasible previously.
Mechanisms and EOR Potential of Nitrogen Assisted Artificial Foamy Oil Flooding
Authors: Jiang Youwei , Wang Bojun , Li Qiu , Zhao Jian , Zhang Yunjun , Zheng Haoran
Published: November 2017

Nitrogen assisted artificial foamy oil flooding (AFO) is an oil recovery process in which nitrogen and foamy oil agent are injected into a water flooded reservoir to drive the remaining oil when it is emulsified with the injected gas and water. The rheological behavior of the emulsified oil is similar with foamy oil flow, so this process is called artificial foamy oil flooding in this paper.

A visible micro-model of etched glass is developed to observe the emulsification process of nitrogen, foamy oil agent, water and oil. The foamy oil agent is a composition of surfactants like foaming agents, foam stabilizers, viscosity reducers and so on. One-dimensional flooding experiments are conducted to measure the resistance factor of artificial foamy oil flow process. The impacts of foamy oil agent concentration and air/liquid ratio upon the resistance factor are assessed in the experiments too. The potential of AFO of overcoming the interlayer interference effect is evaluated with parallel core flooding experiments. Based on experimental results, the reservoir engineering aspects of this technique is discussed and the capability of enhancing oil recovery is demonstrated with a pilot application outcomes.

The mechanisms of AFO unveiled with the etched glass model include: (1) dramatic viscosity reduction with oil/water emulsification; (2) increased elastic energy of oil saturated with micro gas bubbles; (3) Foam blockage in water saturated zones; (4) improvement of drainage factor with pseudo miscible flooding. Compared with the simple treatment with viscosity reducer, AFO is more stable which does not separated within four hours. It reduces the oil viscosity by 80%. The resistance factor can be as high as 58 when the concentration of foamy oil agent is 0.5%. Parallel core flooding experiments reveal that the injection of nitrogen and foamy oil agent after water flooding can reduce water cut by 12%, and enhance oil recovery by 15.8%. In the pilot in Tuha Oil Field, PetroChina, the injected nitrogen compensated the formation pressure rapidly and emulsified with oil to stimulate daily oil production rate and recovery. Demonstrated with reservoir engineering theories and numerical simulation, whose outcomes are compatible with the pilot performance, artificial foamy oil flooding is of great potential to further enhance oil recovery for water flooded reservoirs in Tuha field.

Artificial foamy oil flooding technique, inspired by foamy oil flow in Venezuela, is probably a new EOR solution to reduce water cut and improve oil mobility in water flooded reservoirs, especially in heavy oil reservoirs exploited with water injection in Tuha Field. The mechanisms and recovery potential are unveiled with laboratory experiments and pilot tests.
The First Slickline Rigless Deployed High Rate Slim Design ESP in the Middle East.
Authors: Rafie Majid , Qahtani Mesfer , Mutairi Khaled M. , Winarno Mulad B. , Windiarto Yhossie S. , Assal Anwar
Published: November 2017

The oil industry has been for many years, growing and innovating technology over time. Economic cost is the main driver for changes that occur in our industry and the need to overcome a variety of challenges from reservoir to production to have a profitable well. Saudi Aramco as one of the largest operators worldwide have several fields that run completely on artificial lift, mainly ESPs, to produce. These ESPs are known to be prone to wear and tear, requiring replacement every few years. Conventionally through the use of a workover rig, these ESP and upper completion are replaced every so often. In recent years, the decline of the oil prices worldwide has cited the need to reduce capital & operational expenses to maximize the profitability in our economic analysis.

Saudi Aramco, as a lead oil & gas operator is paving the way in alternative deployments method of ESP completion. This paper details Saudi Aramco’s successful deployment and qualification of a high rate, slim design alternative deployed ESP system. As part of the qualification criteria the system was successfully installed, removed and reinstalled three times over a six month period on slick-line.
Prolonging Gas Production until the End of Concession by Optimizing Existing Resources: A Case Study from Greater Bongkot South Field Development Strategy
Authors: Kritsadativud P. , Sivapiromrat P. , Limprasert T. , Srihirunrusmee S. , Whangkitjamorn J. , Navasumrit P. , Roatkanjanaporn T. , Sapmanee K. , Palviriyachote S. , Thongpian D. , Kaewmuang W. , Promsen P. , Kittisupalauk S. , Kittisureethorn N. , Tan S. , Swarnanto L.D.
Published: November 2017

The Greater Bongkot South Field (GBS) is located in Gulf of Thailand, supplying 320 MMSCFD of Thailand domestic natural gas consumption. The production started in 2012 and its gas supply was committed until March 2023. With this obligation, as well as highly faulted reservoirs, variable gas CO2 contents and small original gas in place volumes, new wells and platforms are required to be continuously sanctioned throughout the field life.

The recent oil price recession in late 2014 and production timing close to the concession end resulted in the changes in GBS development strategy in order to deliver the stable production until the concession ends.

This paper presents the new GBS development strategy when cost saving through oil price recession and production period close to end of concession are the major consideration. Initially, the clear objective and policy from asset’s management was communicated to all working team. Part of design thinking process were used to generate ideas to fill up production gap until end of concession. Some of ideas were implemented such as unlocked integrity wells by perforation with management of change procedure (MOC), or intensive review all of existing unperforated reservoirs and set up new perforation strategy. Then, unleash the locked in potentials, accelerating resources beyond concession, and evaluate new resources by step out infill drilling is proposed.

By synergy and corporation among geoscientists, reservoir engineering, production technologist, development planning and well engineering team, GBS new development strategy is expected close the production profile gap until end of concession in March 2023 and able to prolong production plateau without new wellhead platforms installation, saving more than 60 million USD to the whole project.

A new way of working through a case study in GBS field development strategy can be example for other field development that come close to end of concession or want to squeeze existing resources as much as possible before starting a new major investment.
National Maintenance Management of Indonesian Upstream Oil and Gas Production Facilities
Authors: Amir Mohamad Fauzan , Poerwanto Tomy W. , Pribadi Rossupanji , Aswandi Aswandi , Baidjuri A. Farid
Published: November 2017

Managing more than 60 oil and gas companies spending the maintenance budget of about 1 (one) Billion US Dollar is a big challenge to Special Task Force for Upstream Oil and Gas Business Republic of Indonesia (or known as SKK Migas) as an Indonesian government body appointed to supervise and monitor the Production Sharing Contract (PSC) operators all over Indonesia. Given the limited resources, some restrictions must be addressed, among others, the legacy manual system which is unable to manage the massive information in maintenance; the loss production opportunities due to reliability issue of the ageing facilities, maintenance cost reduction, reutilization of surplus assets and gap in knowledge, competency and innovation between the companies.

The strategies for overcoming the restrictions are principally driven by some major factors i.e. the oil and gas production target and the controlled cost recovery. The efforts are therefore implemented into some general approaches, namely by building a national maintenance information system, applying maintenance assessment regularly, controlling the maintenance work program & budgets and collaborative approaches to the companies.

The maintenance information system has been successfully developed in an efficient and customable manner. The system is able to provide national maintenance data, which are powerful to support decision-making processes in maintenance management. By the system-driven, the control and supervision become more effective. The historical data stored completely helps facilitating evaluation of the operator performance and deciding what actions are required to improve the performance goal. In addition to that, the unused or idle equipment are also well-monitored by the system. Whenever needed, they can be transferred to other companies, so that saving the operational expenses, instead of purchasing or building the new facilities. No exception as well is the efforts to close gap in knowledge, competency and innovation via maintenance cluster forums around Indonesia.
Saving Rig Time by the Use of New Generation Ultrasonic Transducers to Evaluate Cement in Outer Casing through Section Milled Window of the Inner Casing
Authors: Noble L. , Govil A. , McCann C. , Obando Palacio G. A. , Knutsen O. , Nesland B. , Mueller D. T.
Published: November 2017

As the fields in the North Sea mature, many of wells undergo permanent well abandonment or permanent abandonment of a section of the well for consequent well sidetracking. Compliant procedures for well abandonment as per Norwegian Continental Shelf regulatory requirements necessitates the presence of double barriers to isolate permeable formations/sources of inflow.

To achieve a compliant plug-and-abandonment case in situations where casing cement is part of the primary or secondary well barrier (forming part of an external well barrier envelope), casing cement must be verified by logging to ensure a good formation-to-cement-to-casing seal. However, if inner casing is expected to be cemented across the depth where the permanent cement plug (forming an internal well barrier element, WBE) is planned to be set, then the inner casing must be milled so that the outer casing can be logged to verify the barrier seal. Traditional casing milling operations are costly and time consuming, often lasting for several days.

This paper describes an alternative way of verifying an external WBE when the inner casing presents an obstruction for outer casing cement evaluation.
Integrated Fracture Characterization and Modeling in North Kuwait Carbonate Reservoirs
Authors: Richard Pascal , Lamine Sadok , Pattnaik Chinmaya , Al Ajmi Neama , Kidambi Vijay , Narhari Rao , LeVarlet Xavier , Swaby Peter , Dashti Qasem
Published: November 2017

The North Kuwait Carbonate (NKJG) reservoirs are currently under development by KOC (Kuwait Oil Company). The appraisal and development of the NKJG offer challenges such as lateral variations in reservoir quality, tight to very tight reservoirs and natural fracturing to a varying degree spatially. The presence of open, connected fractures is one of the key elements to achieve a successful development. Also, the presence of fracture corridors increase the risk associated with drilling. Numerous fracture modelling studies have been supporting both appraisal and development strategies of the fields.

A structural evolution model has been developed based on field observations and linked to the regional phases of deformations. Detailed fracture characterization using static BHI (bore hole images) and core data as well as dynamic data has been achieved. Small scale detailed DFN (Discrete Fracture Network) in support of planning and drilling activities of future appraisal wells has been carried out. Full field DFN in support to production history matching and forecast has been completed. The core and pressure transient analysis data have been used to calibrate the permeability and porosity of the DFN property ahead of the dynamic simulation work.

This paper illustrates some examples of best practices of the various study components with a focus on core to BHI calibration, fracture porosity calibration using core data and calibration of DFN models using pressure transient analysis data.
Acid Diversion in Carbonates with Nanoparticles-Based in Situ Gelled Acid
Authors: Abdelfatah Elsayed , Bang Sangho , Pournik Maysam , Shiau Bor Jier , Harwell Jeffrey , Haroun Mohammed , Rahman Motiur
Published: November 2017

Acid stimulation is used in carbonate reservoirs to bypass formation damage. Carbonate reservoirs are highly heterogeneous with layers of large permeability variation. For even distribution of acid between layers, we have developed a new acid diversion system using nanoparticles. Nanoparticles aggregate size distribution evolves with time, and once it spans pore space, gel structure is formed. The objective of this present a new acid diversion system with nanoparticles based acid system along with model that can predict the gelation kinetics.

Experimental inversitgation has been conducted to study the gelation kinetics of nanoparticles at different salts, ionic strength, pH, and temperature. Phase behavior study was first conducted. The best system was then tested in parallel coreflood. Then Population Balance equation (PBE) is used to model the growth of aggregates and the interaction between aggregates and porous media. Quadrature method of moments (QMOM) is used to convert the PBE with continuous distribution of nanoparticle size into moment transport equations for efficient computation. Finite volume method is used for discretization of moment transport equation, acid transport equation, continuity equation and Darcy law.

Acid diversion in carbonates using nanoparticle-based in situ gelled acid is proven to be more efficient than convectional diversion systems especially for harsh reservoir conditions. The effect of different salts, ionic strength, pH and temperature was studied experimentally. Coreflooding shows that Nanoparticle-based system can create several complete wormholes in both low and high permeability cores. Nanoparticles plugging small pore throats can divert acid into larger pores and reduce acid leakoff. Model presented in this paper gives insight into the aggregation and gelation kinetics. Model displayed the influence of nanoparticle concentration on gelation time. Once the gel forms, shear thinning behavior is used to model the viscosity of the gel. Shear rate could highly reduce the viscosity of the gel and hence affect the efficiency of acid diversion.

The model developed in this work accurately simulate aggregation, initiation of gelation of fumed silica and acid diversion in carbonates. The new acid diversion system is highly effective in even distribution of acid between layers of different permeability. The model developed in this study can help in optimization of new nanoparticles-based acid diversion system.
Integrated Approach to Address Reservoir Uncertainties in One of the Largest Recent Gas Discoveries Onshore Egypt
Authors: Abdelkhalek Mostafa , Elhares Layla , Van Heeswijk Victor , Amin Sameh , Gill Nick
Published: November 2017

The BTE field is one of the largest recent gas discoveries in the Egyptian Western Desert. The main subsurface uncertainties impacting the Initial Gas in Place (GIIP) are Gas Water Contact (GWC), structure, fault positions and sand development. Given the large subsurface uncertainties, it is planned to further appraise the field with one or two appraisal wells and reshooting seismic.

Other key uncertainties are sand quality, intra-field faults and aquifer strength. These uncertainties will impact the wells deliverability, Estimated Ultimate Recovery per well (EUR/well) and the Ultimate Recovery Factor (URF). The EUR/well and the URF are a function of the number of wells drilled.

An integrated probabilistic modelling (experimental design model) approach was developed to consider all main reservoir uncertainties together and determine the true P90, P50 and P10 EUR subsurface realizations. Three different software packages were used and linked together; Material Balance Equation1-3 (MBE) software, statistical4 package software, and Spreadsheet software. The three packages are talking to each other through Visual Basic for Application5 (VBA) programming language.

This probabilistic model enables the user to run sensitivity studies by changing one parameter at a time and check its effect of EUR. The model also lends itself for uncertainty studies (experimental design) by examining all the possible combinations scenarios between the different uncertain parameters; such as GIIP, tanks transmissibility, wells flow coefficient6 (C), wells flow exponent (n), relative permeability parameters, aquifer properties7, etc.
Optimization of LPG Recovery from Refinery Delayed Coking Gas Recovery Unit
Authors: El Khashab A. A. , El Maghraby A. M. , Refaat M. A. , El Meligy H. A.
Published: November 2017

Refinery Delayed Coking units produce light components from the top of the fractionation section as one of the products. The extent of recovering LPG from this stream via the Gas Recovery Unit mainly depends on the costs involved in recovery.

Gas Recovery Units usually comprise of feed compression to a higher pressure followed by absorption with a solvent (i.e. naphtha) and a stripper column where the light components absorbed in the process stream are stripped. The rich solvent from the stripper bottom is then routed to a debutanizer column where LPG is separated. The recovered LPG and Fuel Gas undergo further amine treatment to meet H2S specifications.

The objective of this paper is to present the methodology applied to evaluate/optimize the different process schemes and main operating parameters of a Refinery Delayed Coking Gas Recovery Unit for optimum energy/cost effective LPG recovery.

The Delayed Coking Gas Recovery Unit has been simulated utilizing HYSYS® steady state simulation software linked to Aspen Process Economic Analyzer to evaluate the effect of different combinations of process schemes and operating parameters on the products recovery as well as equipment sizing and thus the capital cost, while estimating the required utilities and thus the operating cost.

Two main different process operating parameters have been studied: Absorber operating pressureNaphtha (Solvent) recycle ratio

Four different process schemes have been studied: Including both Recontactor and PresaturatorIncluding Recontactor onlyIncluding Presaturator onlyWithout both Recontactor and Presaturator

The Absorber operating pressure and the naphtha recycle ratio have major effect on the LPG recovery. Increasing either of the above parameters enhances the absorption and thus increases the LPG recovery on the other hand increases the utility consumption and thus the operating costs as well as increasing the equipment sizing and thus the capital cost.

The optimum operating parameters resulting in the higher net present value (NPV) and internal rate of return (i.e. higher economics parameters) was found to be an Absorber pressure of 22 bar (i.e. the pressure that can be achieved by 2 compression stages) and Naphtha recycle ratio of 0.42.

The optimum scheme was found to be that including both the Recontactor and Presaturator, although this scheme has extra equipment, however the addition of these equipment result in higher product recovery at lower Naphtha recycle ratio and thus result in savings in equipment sizing and thus capital cost as well as savings in the utility requirements (i.e. power and steam) and thus the operating costs.

Coker Gas Recovery Units are common in most refineries, although the design of this unit is conventional; however, this paper introduces new level of absorber operating pressure which has been proven to be economically attractive in recovering more LPG with reduced operating costs.
A Different Approach to Evaluate Wettability in Shales
Authors: Araujo de Itriago Yani C. , Albrecht Jochen , Möeller Andre , Dallmann Gerald
Published: November 2017

Conventional methods for wettability assessment are based on volumetric measurements such as displacement tests, and have to be modified for shales because of their low porosity, ultra low permeability with natural fractures, and reactive components. These methods are time consuming and the results are often questionable; these facts that have motivated the search for new approaches to estimate this property. A methodology for measuring shales wettability that uses X-Ray Photoelectron Spectroscopy (XPS) is presented in this paper. Results are compared with conventional imbibition tests. XPS is being used as a faster way to infer the wetting condition on sandstones rocks.

XPS allows knowing the chemical composition of the outer layers of a solid surface. Using XPS the organic carbon content at the surface is evaluated, and then it is correlated with the wetting condition from imbibition tests. Water wet and oil wet shales from different countries were investigated. Samples were prepared rigorously for mineralogical and XPS measurement.

The relationship between wettability and surface composition as determined from XPS is reported. Wettability index measured by imbibition tests is used in this study as an indicator of the wettability of shales. The XPS spectra of oil-wet surfaces of shales reveal the existence of organic carbon and also of an organic mineral species such as Si–CH. These species have a well-defined binding energy which differs from the inorganic species of mineral grains. In this study we present quantifiable evidence that chemisorbed organic material on the surfaces defines the oil-wetting character of oil shales. In the case of gas shales gas is adsorbed onto clay surfaces, as well in natural fractures and porous giving them oil wet condition. This view is supported by a strong correlation between the organic matter content on shale surfaces, the mineral composition and the wettability. In this paper we demonstrate a different approach for measuring shale wettability using XPS analysis. Instead of waiting for many days for the results from imbibition test, XPS takes less than one day. As a result, the time needed for the wettability measurement is reduced significantly.
Molecular Simulation of CO2 Sequestration and Enhanced Gas Recovery in Gas Rich Shale: An Insight Based on Realistic Kerogen Model
Authors: Huang Liang , Ning Zhengfu , Li He , Wang Qing , Ye Hongtao , Qin Huibo
Published: November 2017

Injection of CO2 into shale plays has been considered as one potential scenario for CO2 sequestration with enhanced CH4 recovery (CS-EGR). In this work, a realistic molecular model of bulk kerogen was constructed by molecular dynamics simulations (MD). Grand canonical Monte Carlo simulations (GCMC) were performed to investigate the replacement of CH4 by CO2 under different reservoir pressures, CO2 mole ratios and kerogen moisture contents. The radial distribution functions (RDF) were computed to discuss the affinity between CH4/CO2 and atoms in the kerogen. Also, the CO2/CH4 adsorption selectivity was computed to evaluate the preferential adsorption of CO2 and CH4. Results show that the CO2/CH4 selectivity increases at the beginning, and then decreases with further increasing pressure, which indicates that low reservoir pressure is beneficial to the efficiency improvement of CS-EGR. The amount of CO2 sequestration and CH4 desorption increases, while the CO2/CH4 selectivity decreases as the CO2 mole ratio increases, indicating the adsorption stability of sequestrated CO2 weakens with increasing CO2 mole ratio. The CO2/CH4 adsorption selectivity decreases initially, and then increases with the kerogen moisture content. Increasing the reservoir moisture content can improve the performance of CS-EGR. The preferential adsorption sites for CH4 are the sulfur-containing groups, while these for CO2 are the nitrogen- and oxygen-containing groups. One adsorption layer is observed for CH4, while two adsorption layers are identified for CO2. This study gains enhanced insights on the replacement exploitation of shale gas by CO2 at molecular scale, and it can provide applicable guidelines for the optimization of CS-EGR in shale gas reservoir.
A Geochemical Model for Investigation of Wettability Alteration during Brine-Dependent Flooding in Carbonate Reservoirs
Authors: Awolayo Adedapo , Sarma Hemanta , Nghiem Long , Emre Gorucu
Published: November 2017

The impact of brine salinity and compositions on improving brine-dependent recovery processes has been an active research area over the past two decades. Various studies have demonstrated an improvement in oil recovery, attributed predominantly to the ability of the brine to alter rock’s wettability towards water-wetness. The proposed hypothesis is that the wettability of carbonate rocks is altered due to desorption of oil carboxylic groups from rock surfaces by the adsorbed sulfate, while the divalent cations are co-adsorbed.

We developed a reactive transport model to test this hypothesis and considered wettability alteration through geochemical interactions among brine, oil and rock surface. In this model, we used various reaction pathways to account for the competition between oil acid-groups and active ionson the rock surface. The equations developed from various reactions are coupled with multiphase flow equations to control flow functions that ultimately determine the oil recovery. The model we developed was used to investigate the effects of ionic variations during carbonate coreflooding experiments. Thereafter, we extended DLVO (Derjaguin, Landau, Verwey and Overbeek) theory of surface forces to explain the molecular interactions between rock−brine−oil system by generating interfacial disjoining pressure and interaction energy.

The model was tested by matching and predicting results from recently published flooding experimental studies related to ionically-modified brines conducted under single-phase and two-phase flow conditions. In these experiments, sulfate concentration in seawater was halved and quadrupled, and compared to injections of formation water and seawater. We found remarkable agreement with the produced ion histories reported from the single-phase tests, although there were delays in the produced sulfate concentration because of retention within the core. For two-phase experiments, the model yielded excellent replication of the produced ion histories and oil recoveries obtained during injection of various brines. Results show that increasing sulfate while maintaining the concentration level of other ions improved oil recovery up to 10% OOIP. However, when sulfate was reduced, neither additional oil was recovered nor sulfate ion production was delayed. Application of DVLO theory shows that disjoining pressure, which dictates the water film thickness, is extremely sensitive to sulfate content of the brine. Brines with more sulfate content exhibit higher disjoining pressure and energy barrier compared to brines with fewer sulfates. This suggests that increasing sulfate in the injected brine is essential to alter rock wettability.
Drivers and Constraints of International Projects Development in the Arctic
Authors: Akimova Irina
Published: November 2017

Nowadays more than ever there can be no doubt that world economy and especially global energy markets are driven by technology innovations. As Arctic currently serves as a potential game changer for energy markets, emerged technologies it will bring to the market and its infrastructure development can totally reshape the global landscape of the international energy market.

This paper highlights benefits that development of international projects in the Arctic can bring to the market by making it more innovative and competitive along with potential usage of some of its technologies in other offshore and marine projects.
Evaluation of Eco Friendly Bio-Oil Dispersants on the Inhibition of Asphaltene Precipitation in a Kuwaiti Crude Oil
Authors: Alrashidi Hessah , Nasr-El-Din Hisham A.
Published: November 2017

Asphaltene precipitation, flocculation and deposition are vital problems that may cause serious damage to reservoirs, wells, and production facilities. Asphaltene precipitation may occur during primary depletion or acidizing jobs as well as after the injection of rich gas or carbon dioxide. The Organic deposition removal is considered a costly workover job with the current oil prices. The solvents that are usually used are toluene and xylene, which are considered carcinogenic and toxic chemicals. The use of dispersion to inhibit the organic deposition is essential and can be expensive, as it is required for the life of the well.

The objective of this paper is to compare the effectiveness of two chemical dispersants and deasphalted oil against vegetable oils (coconut oil and andiroba oil) on the inhibition of asphaltene precipitation.

A Kuwaiti crude oil sample was used in this study with an API of approximately 38° and asphaltene content of 2 wt%. The crude oil was characterized by a variety of analytical techniques including: Total acid number (TAN), Total base number (TBN), water content, Saturates, Aromatic, Resins, and Asphaltene analysis (SARA), density, viscosity and elemental analysis. Dispersants and vegetable oils were analyzed by Fourier Transform Infrared spectroscopy (FTIR) to determine the functional groups. An Asphaltene dispersants test was carried out at different concentrations of 150, 300 and 500 ppm and temperatures of 25 and 70°C to evaluate the dispersant efficiency and limitations.

The results of this study showed that the dispersant should be designed based on understanding the asphaltene structure and interaction mechanism. Temperature greatly affects the blended dispersant performance due to the relation of asphaltene solubility and temperature; therefore designing optimum concentration must be taking into account. Employing the deasphalted oil as solvent to mitigate asphaltene precipitation can be desirable from economical perspective.

Coconut oil performs very well as an asphaltene dispersant when paired with DAO at a concentration of 500 ppm or solely at 25°C. The results can be employed in designing and optimizing dispersants that are environmental friendly and cost effective.
Running Feed Gas Compressor without Atmospheric Gas
Authors: Al Braiki Wael Khaled
Published: November 2017

ADGAS LNG Plant 26 contains two identical multi-wheel single stage Centrifugal Compressors. Their function is to compress atmospheric gas from ADMA to 2.0 barg pressure. The compressor is designed for running parallel both, in load sharing mode by master pressure control to be able to maintain Atmospheric gas pressure at about 29"of H2O. The suction of both Booster compressors draw from common suction drum (26-C-0101) which has two separate demister pads and suctions.

The inlet pressure of south and north dropped to min of 15 & 9"WG respectively Due to the difference in the suction flow, the LNG Operations started facing the difficulties to maintain south (26K101) and north booster compressor (26K2O1) in AUTO load sharing mode.

Due to sticky oily viscous sludge type material coming along with the incoming Atmospheric feed gas stream, demister pads were fouled and the high DP made it difficult to pull, all the available atmospheric gases from ADMA & resulted in flaring of about 9mmscfd. To open the suction drum & clean/replace the demister pads it required 9 days outage of both the booster compressors.

Both LNG trains’ Feed gas compressors had to be run without atmospheric gases, which was never attempted earlier It was required to capture all Atmospheric gases in OAG. The challenge was running both LNG FGC-1/2 without any ATM gases & OAG with Minimum required 35 Psig Gas.

LNG boosters were unloaded and FGC’s were loaded with more 35# gas. OAG booster compressors were fully loaded with all the available atmospheric gases (100mmscfd).

LNG Booster compressor demister pad replacement require 10 days shutdown, Traditionally FGC also stopped and LNG trains run with HP Gas only

By Implementing the innovation of Feed Gas compressor is running without Atmospheric gas, there were no impact on ADMA oil production, LPG loss reduced by 2581 tonnes per day and LP Gas Flaring of 2 MMSCFD saved. Demister pads were replaced and High DP problem resolved
Performance Enhancement of Drilling and Completions Operations in Giant Offshore Field Abu Dhabi by Tracking and Monitoring Invisible Lost Time and Defined KPIs
Authors: Raza Syed Ali , Al-Braik Haythem , Attalah Mohamed , Corona Mauricio , Kojadinovic Nenad
Published: November 2017

Drilling and Completions operations optimization requires as starting point the building of an alive database that sustains the benchmark for a list of defined KPIs. The KPIs will represent main well construction activities conducted in different well types in a specific field. Once the data is captured and processed, the operations efficiency is obtained with the computation of the Invisible Lost Time (ILT). Computations are defined in different ways by different operators with different margins. The purpose of this paper is to probe that operational efficiency that can be tracked better when the percentiles lead the targets and not the Composite Best as a target.

The continuous monitoring of the performance and the daily distribution of KPI's tracking dashboard has changed the mindset of the entire team, engaging the rig personnel in the identification of specific limiters that affect the performance and defining specific actions to take to revert the trend. The year to year comparisons showed a significant performance improvement in all the rigs but not at the same rate. The expected learning curve has deferred from one rig to another.

A forecast tool has been created to generate an automatic AFE that delivers automatically TvD curves for the different percentiles and it is aligned to the latest rig's performance and the well architecture. This tool will help the drilling engineers to estimate, quick and more accurate, the well duration time, especially when the rig allocation is crucial for the yearly objectives of the project.
pH-Responsive Supramolecular Gelling Agents Used in EOR and Their Potential as Fracking Fluids
Authors: Yegin Cengiz , Temizel Cenk , Yegin Yagmur , Sari Mufrettin Murat , Jia Bao , Alklih Mohamad Yousef
Published: November 2017

Hydraulic fracturing is an important method to recover shale oil and gas that has drastically increased U.S. energy production in recent decades. Shales are low permeability formations where natural resources are trapped, and require a well-planned hydraulic fracturing process and a highly developed fracturing (fracking) fluid for efficient oil/gas recovery. In this study, a pH-responsive solution synthesized by supramolecular assembly of maleic acid and an amino-amide in an aqueous media is described as a potential fracking fluid owing to its mobility control, proppant carrying and settling capacities. Previous investigations on this solution system had shown its large potential to replace displacement fluids in EOR due to pH-tunable and reversible viscosity behavior.

The main working mechanism is that; the initial viscosity of injected solution is kept at moderate/high values to easily transport proppants and easily inject the fluid; and then decreased when the solution reaches a position near fissures for settling of proppants. It has been reported by rheology tests of the developed fracking fluid, which consists of the supramolecular solution and proppants (silica sand), viscosity can be changed about 1600 times from pH 3.8 to pH 8.3 in a reversible fashion at only 2 wt.% concentration. On the other hand, sedimentation studies indicated that the sedimentation speed of the silica proppants decreased around five orders of magnitude from pH 4 to pH 8, again in a reversible way. Furthermore, experimental studies revealed that the developed supramolecular solutions have both reversible pH-responsive properties, and tolerance against high salinities and elevated temperatures. Another outstanding property of these supramolecular solutions is their self-healing feature which enables them to disassemble and reassemble upon exposure to extreme shear stresses, while polymer viscosifying agents the fracking fluids degrade and break up under similar conditions.

The supramolecular assembly system discussed in this study has a promising potential to become next-generation fracking fluids with its outstanding properties including but not limited to pH-sensitivity, reversible viscosity, high proppant transfer capacity, tolerance to high temperatures and salinity, self-healing behavior, environmental friendliness and sustainability.
A Multifaceted Strategy to Achieve Significant Reservoir Simulation Work Flow Efficiency Gains
Authors: Kaczorowski Norman , Knyazev Alexander , Ghassan Majed , Brock Nigel , Wilby Geoff , Engle Colin , Bogachev Kirill
Published: November 2017

A multifaceted strategy is presented which achieved significant reservoir simulation work flow efficiency gains at an operating company. The components of the strategy, including hardware and software, are detailed, and the relative efficiency gain is quantified with respect to the previous approach. The relative business value achieved by implementing the strategy is discussed. The new strategy improved efficiency by leveraging modern technology to impact those tasks of routine reservoir simulation work flows not directly related to reservoir engineering. This involved changes in three primary areas of the classic simulation routine of pre-processing, processing, and post-processing. A turn-key high-performance computing (HPC) solution for hosting data storage and executing simulation job processing was designed and implemented. A modern state-of-the-art simulator was configured for simulation job processing. An innovative simulation project management technology solution was deployed to organise and drive the reservoir simulation work flows and associated data management. The in-place HPC solution was constrained by the configuration of the compute nodes, lack of a master node, and the storage solution. These were configured inefficiently to the point that the expected gains from fast processing capacity were not realised due to other choke points in the compute processing and network. To realise the full potential of fast processing in a modern parallel environment, a custom HPC solution was designed. The custom solution allowed for better communication between the compute nodes and the storage, and incorporated an integrated master node. Next, simulation jobs were configured to run on a modern state-of-the-art simulator optimised for advanced HPC hardware. The new simulator significantly reduced model run times. Lastly, an innovative simulation project management technology was deployed on the reservoir engineer workstations. This technology allowed the engineers to reduce the time spent managing data, and to increase the time spent engineering. The preand post-processing engineering tasks were also made more efficient with the technology. The net result of the new strategy was to increase simulation throughput eight times. The higher volume of throughput led to more optimised engineering solutions and eventually allowed for the development of more complex simulation models. The multifaceted strategy to improve reservoir simulation work flow efficiency combines optimisation of the hardware and selecting software technologies conducive to modern HPC environments to allow engineers to focus the majority of their efforts on engineering rather than on systems and data management.
Finite Element Based Optimization and Improvement of the Sucker Rod Pumping System
Authors: Langbauer C. , Antretter T.
Published: November 2017

Low oil prices push the demand for efficient production, especially in mature fields. The reduction of artificial lifting costs by increasing efficiency is essential for extending the meantime between failure, the economic limit of the reservoir and the increase of the recovery factor.

For achieving these goals, the Finite Elements Method (FEM) is used for modelling and analysing the behaviour of the sucker rod string. Based on the results an optimisation of the whole pumping system is performed, which does not only consider subsurface equipment, but in addition also the surface facilities. The main target is to carry out a diagnostic analysis to evaluate the performance of existing units as well as a predictive analysis to optimize their performance and to design new units.

This paper summarizes the concept and the capabilities of the employed sucker rod pumping system analysis, based on the results of the sucker rod string FEM – simulation, including downhole pump as well as surface unit improvements. The model and the simulation results are verified by a comparison with downhole dynamometer measurements, obtained by several self-developed DDS (Downhole Dynamometer Sensor) during field tests. The presented simulation concept yields more accurate results than currently available commercial software products and in addition allows maximum flexibility in terms of sucker rod string composition, operation conditions, fluid conditions and the choice of installed equipment.

A comparison conducted on the performance and efficiency of a standard pumping system design and an optimized pumping system design resulted in an increased energy efficiency of more than 30%.
Formation of Mercaptans and Organosulfur Species in Claus Process
Authors: Rahman Ramees K. , Raj Abhijeet G. , Ibrahim Salisu
Published: November 2017

The formation of mercaptans and organosulfur species in Claus process leads to a reduction in the sulfur recovery efficiency, and an increase in the cost of tail gas treatment. While process optimization can be used to minimize their production in plants, the existing models fail to predict their concentrations to a reasonable accuracy. This study provides a detailed and validated model for Claus process including organosulfur species reactions that can be used in process optimization. A Claus mechanism, developed in a previous study, was used as the base mechanism. To this, the organosulfur reaction mechanism, developed using quantum chemistry, was added. The rate constants of the elementary reactions were determined using transition state theory. New rate parameters were validated with experimental data from the literature as well as from the sulfur recovery units in the UAE. The reaction furnace of the Claus process was modelled as an adiabatic plug flow reactor, and the waste heat boiler was modelled as a heat exchanger. New reactions and their rates for COS and CS2 formation provided a good match between the experimental data and the computed values. The important reactions contributing to COS formation were: i) CO+S3=COS+S2; ii) COS+O=CO2+S; iii) COS+SH=CO+HSS. Similar analyses were done for other organosulfur species to find the reactions responsible for their formation. The process simulations of SRU thermal unit were conducted using Chemkin Pro software to determine the conditions under which their concentrations can be minimized in the furnace. COS concentration was found to be reducing beyond 1500 K while mercaptans were destructed around 1050 K. It is also observed that CO concentration increased due to the thermal cracking of CO2. The presence of CO2 and fuel gas in the feed to the Claus process was found to be contributing highly to the formation of organosulfur species, but the furnace temperature played a vital role in their formation and destruction. The model developed in this study successfully predict the concentrations of organosulfur species including mercaptans, COS and CS2 in Claus process that will help in the optimization of process parameters to minimize their formation, maximize the sulfur recovery efficiency, and reduce the load on downstream catalytic units.