bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Gas Recovery by CO2 Injection and Sequestration: Effects of Temperature, Vertical and Horizontal Orientations on Dispersion Coefficient
Authors: Abba Muhammad Kabir , Abbas Abubakar Jibrin , Al-Otaibi Athari , Nasr Ghasem Ghavami
Published: November 2018

Enhanced gas recovery (EGR) by CO2 injection and sequestration is receiving increased attention within the research community. This is as a result of its potential to be an avenue for the simultaneous additional recovery of natural gas from the reservoir and provide a safe CO2 sequestration site. However, the major problem with this technology lies in the excessive mixing of the injected CO2 and the nascent natural gas (CH4) during the displacement process. This excessive mixing is the reason why the technology has not been widely patronised, given that the recovered CH4 will be heavily contaminated with the injected CO2 thereby making it "lacking" as sales gas after recovery. This hinders the market value of the recovered CH4 and eventually renders it not viable economically. Hence, highlighting the factors responsible for the mixing could provide technical solution to minimise the mixing phenomenon during EGR. This research focuses on the temperature effects and the orientation of the injection pattern of the technique. An experimental core flooding simulation was carried out at a temperature of 50°C and a pressure of 1300 psig and varying injection rates of 0.2 - 0.5 ml/min on Grey Berea sandstone core sample with the sample situated in both vertical and horizontal orientations. It was observed that at higher temperature (50°C) suitable for many gas reservoirs, the disperstion coefficient increased significantly compared to our earlier work (Abba, Abbas, & Nasr, 2017) at 40°C by a factor of 2.3. This trend was due to the increased energy of the gas molecules at the observed conditions, thereby increasing their mobilities. Conversely, the dispersion coefficient also increased significantly by a factor of 3.4 in the horizontal orientation at lower injection rates compared to the vertical core flooding with the concentration profiles showing significant capillary tailing effects at higher flowrates. This signified the effect of gravity in the horizontal orientation was more pronounced at lower injection rates during the injection of CO2 and this will have tremendous effect on the flow behavior of supercritical CO2 during the gas-gas displacement process.
Robust EOR Screening Workflow for a Carbonate Green Field: A Case Study
Authors: Ali Abdulla Ali , Park Sangseok , Mukhtar Muhammad , Ghorayeb Kassem , Alkhatib Mohamad , Ojha Aditiya , Shah Abdur Rahman , Ortiz Jaime Moreno
Published: November 2018

Early assessment of enhanced oil recovery (EOR) potential in fields that are at early development stages is becoming more common in the oil industry, ensuring that investment decisions are consistent with the EOR deployment once the field reaches maturity. Well, facilities and monitoring design maybe influenced to accommodate the EOR implementation, thus reducing Capex and mitigating project exposure. Challenges arise, as expected, due to the limited information, particularly when the field has not yet been under production and dynamic information of connectivity, compartmentalization and reservoir extend is scarce.

This paper describes the screening analysis performed on an onshore marginal green field in the UAE with four drilled wells and no production history with water injection considered on the approved development plan. The comprehensive screening workflow resulted on a narrow list of potential applicable EOR methods and their corresponding benefits allowing the operator to tailor development activities for early EOR de-risking and accelerated field deployment. A multi-dimensional approach was adopted using a combination of numerical, analytical methods and past EOR experience, to shortlist and rank the most attractive EOR development options, robustness of the selection (and ranking) was tested under the key reservoir uncertainties.

WAG was identified as one of the better suited EOR processes (complemented the planned waterflood) along with miscible CO2 injection (with possible WAG applications).
Resolution of Frequent Mechanical Seal Failure on Highly Critical Lean Solvent Pumps
Authors: Sharda Rajeev
Published: November 2018

Brief information of the issue

ADNOC Gas processing plant at Habshan 5, AbuDhabi was commissioned in 2013 and since then Lean solvent circulation pumps tag no 530/531/532/533P101A/B, which are highly critical to operations, remained bad actors due to frequent failures of cartridge mechanical seals.
Real-Time Fluid Characterization Using Advanced Gas Analysis in Hith and Gotnia Formations
Authors: Peres Jose , Mukherjee Pritish , Dashti Jalal , Mushnuri Sudhakar , Al-Qattan Faisal , Al-Bader Mishari , Al-Kandari Jassim , Al-Awadi Mishari , Reitsma Mariel , Watts Jon
Published: November 2018

The Hith and Gotnia Formations in Kuwait were considered to only be acting as seals for the early Jurassic hydrocarbon bearing reservoirs. However, recent hydrocarbon discovery within the Gotnia Formation has proven that they have reservoir potential as well. Due to High Pressure-High Temperature (HPHT) conditions of these formations, casing is set immediately after drilling, thus limiting open hole data acquisition. To overcome this problem we deployed a single mass spectrometry service for advanced gas analysis to understand and characterize the fluid variations within the Hith and Gotnia Formations.

Two mass spectrometers, for gas in and gas out detection, were connected to constant volume degassers in the suction pit and shaker house, respectively. First, the dynamic oil based mud (OBM) discriminator differentiated OBM contamination and subsequently the unique ‘real-time’ algorithms quantified concentrations of formation hydrocarbons.

The formations under evaluation were divided into 3 major geochemical zones based on acquired gas data. These geochemical zones were marked by changes in mud gas response and were closely linked to lithological properties, each lithology type having a distinct gas signature. The Hith Formation consists of thinly interbedded anhydrite and limestone and comprises the first geochemical zone. With low gas response, gas ratios point to a potential oil fluid type although the formation is likely unproductive due to low permeability and high water content. The four halite intervals within the Gotnia Formation were grouped together as the second geochemical zone, having no production potential due to their low porosity and permeability. They behave as a seal to the hydrocarbons in the interbedded anhydrite-limestone intervals. The three anhydrite plus limestone intervals within the Gotnia Formation belong to the third geochemical zone. Comparison of the oil signatures in these intervals revealed a decrease in fluid density from top to bottom. The different fluid density within each interval and the sealing efficiency of the interbedded halite suggest that there is no direct fluid communication between the individual anhydrite cycles. This paper covers in details the response and interpretation of the gas signatures in each zone.
Effects of Formation Properties and Treatment Parameters on Hydraulic Fracture Geometry in Poro-Viscoelasticity Shale Gas Reservoirs Using Cohesive Zone Method in a 3D Model
Authors: Suo Yu , Chen Zhixi , Rahman Sheik , Xu Wenjun
Published: November 2018

Hydraulic fracturing is a significant way to improve the productivity of the unconventional reservoir with low permeability and porosity. Current hydraulic fracturing simulation models are mostly based on poro-elastic theory. However, for rocks such as shale, the viscoelastic feature has been observed in both field investigations and laboratory experiments. This paper presents a 3D numerical model for fracture propagation in visco-elastic shale gas formations using ABAQUS platform. The cohesive elements based on damage mechanics were adopted to simulate the initiation and propagation of hydraulic fractures. The model was used to investigate formation properties and treatment parameters on fracture geometry, especially the fracture behaviour when entering into the barrier formations. It is found that higher treatment pressure is required to initiate and propagate the hydraulic fracture and the fracture is wider but shorter in poro-viscoelastic formation comparing to poro-elastic formation. The higher differential in-situ stress, tensile strength and Young modulus in barrier formations and lower fracturing fluid injection rate and lower fracturing fluid viscosity have positive effect on the controlling of fracture vertical growth and restricting hydraulic fracture within the pay zone. Results of this study will provide the industry a better understanding of hydraulic fracture behaviour in shale gas formations.
Using CHARM Modelling to Decide the use and Discharge of Surfactant at an Offshore EOR Project
Authors: Chai Ching Hsia Ivy , Shafie Nur Anisah , Razali Norzafirah , A Manap Arif Azhan , Salleh Intan Khalida
Published: November 2018

The application chemicals such as surfactants for Enhanced Oil Recovery (EOR) has caught the attention of various stakeholders especially regulators and operators - raising concerns of the impact of these chemicals to the ocean when they are back-produced. The current approach in mitigating the toxicity at production is the dilution of produced fluids to a lower concentration before disposal to sea. However, how confident are we that EOR chemicals do not cause environmental impact to marine life? Due diligence conducted showed that there are no environmental regulations or guidelines in Malaysia for the application of EOR chemicals at an offshore platform. For this reason, our team refers to the strictest of regulation for chemicals' use and discharge for an offshore environment used at the North/Norwegian Sea, adopting all qualification criteria from Harmonized Ocean Chemical Notification Format (HOCNF), of the OSPAR Harmonised Mandatory Control System (HMCS), developed through the OSPAR Decision 2000/2. HOCNF ranks chemical products according to Hazard Quotient (HQ), calculated using the Chemical Hazard and Risk Management (CHARM) model. CHARM is a set of rules to determine the risk and extent of surfactant formulation's movement in the ocean - a vital decision making tool to determine if EOR chemicals are safe for use and overboard discharge. This paper describes the ‘environmental-friendliness’ of a newly developed surfactant formulation which will be applied in a Water-Alternating-Gas (WAG) operation at an offshore field in Malaysia using CHARM. First, a comprehensive review of the components of the formulation was conducted, leading to sound selection and/or synthesis of chemistries that confers good environmental properties i.e. non- or low toxicity, persistency, bioaccumulation, with high biodegradability. Next was to determine the degree of toxicity of the formulation at three trophic levels. Using the lowest acute toxicity value, we apply this value to the CHARM model to calculate the dilution of the formulation 500 m radius from the point of discharge - given the expected adsorption, application concentration, and the volume ratio between squeeze vs. produced water. Whether CHARM is exhaustive to decide if the surfactant formulation can be discharged overboard is still being debated. Many argued that it is the responsibility of the chemical manufacturer or product inventor to select or synthesize chemistries with good ecotoxicity properties in the first place. Product innovation has to be aware on new regulation(s) e.g. the banning on the use of a chemical currently used in manufacturing so that the company develops an alternative ahead of its competitors. In the operator's viewpoint, even if the model indicates that the chemical pose a low hazard, physicochemical parameters of the produced fluids has to be monitored beyond the pilot implementation period.
Improved Characterization of Transition Zones in Carbonate Reservoir by Modern Digital Imaging Technique
Authors: Sun Huafeng , Belhaj Hadi , Bera Achinta
Published: November 2018

Transition zone (TZ) containing a large amount of oil plays a key role in a carbonate reservoir. Its characterization is challenging because it is difficult to define top and thickness of the transition zone and it may contain many kinds of rock types differently affecting the fluid flow behavior. Routine core analysis (RCA) and special core analysis (SCAL) can be used to study for characterizaiton and modeling of TZs, but these data can rarely be used to obtain the details of the pore structure governing the rock properties. In recent years, the digital imaging technique has made great progress, because the rock microstructures can be directly imaged by using modern digital imaging technique such as thin sections (TS), scanning electron microscope (SEM) images and X-Ray computed tomography (XCT) scans. This paper focuses on the application of digital imaging technique for characterization of TZs in carbonate reservoirs located within the Middle East region. The experimental data and digital imaging data are used to study the rock samples of TZ. The results show that: 1) the rock properties of TZ samples can be accurately predicted by using digital imaging technique; 2) the petrography and diagenesis of TZ are well studied; 3) the carbonate rocks are qualitatively and quantitatively classified into three types: matrix, fractured and vuggy; 4) digital imaging technique, generally, proves to be a powerful tool for characterization of TZs in carbonate reservoirs.
Cyclone Type Autonomous Inflow Control Device for Water and Gas Control: Simulation-Driven Design
Authors: Chochua Gocha , Rudic Aleksandar , Kumar Amrendra , Mainy Aurelien , Woiceshyn Glenn
Published: November 2018

Horizontal wells are considered superior to vertical and deviated wells because they increase reservoir contact; however, they can cone unwanted fluids (gas, water) causing reduced oil recovery and early well abandonment. Inflow Control Devices (ICDs) are typically installed along the completion string to delay coning and restrict water/gas influx. Once the coning occurs, conventional ICDs, such as channels and orifices, were found to be inadequate in choking back the unwanted fluids. Thus, new types of "autonomous" ICDs, or AICDs, were developed that choke back unwanted fluids more than conventional ICDs. Conversely, such AICDs have limitations related to bulkiness, moving parts, wellsite adjustability, flow performance predictability, and erosion.

To overcome these limitations, a new AICD, operating on a principle of a cyclone, was developed by a synergy of the latest numerical technologies, such as Computational Fluid Dynamics (CFD) utilizing a high-fidelity Large Eddy Simulation (LES) turbulence model, and Design of Experiments (DOE) techniques. This CFD-driven design optimization involved utilization of high-performance computing (HPC) coupled with experimental validation. A DOE matrix of CFD analyses runs was performed to identify a geometry that would generate significantly higher pressure drop for water and gas than for oil.

Early multiphase testing on a prototype device validated the concept, and CFD was used to improve the understanding of the operating principle and hence the design. CFD was further used to extrapolate the flow performance to a wider range of operating conditions. An expanded flow performance map and the use of non-dimensional parameters led to the development of a mechanistic AICD performance model which further enhanced our understanding of AICDs and allowed reservoir software programs to evaluate the production performance of wells with AICDs versus wells with conventional ICDs or no inflow control. The overall result is the new cyclonic AICD presented herein which is: 1) relatively compact, 2) without moving parts, 3) erosion resistant, 4) superior in multiphase performance, 5) easily adjustable at the wellsite with many settings, 6) accurately modeled with CFD, and 7) easy to incorporate into state-of-the-art reservoir simulation models.
Asset Management of Wells and Facilities Through Integration of Monitoring and Geomechanical Modeling for a Field with Active Subsidence in Sultanate of Oman
Authors: Mahajan Sandeep , Stammeijer Jan , Mukhaini Hamed , Azri Saif , Rahmoune Rachid , Aamri Mohammed , Tarmizi Ikhsan
Published: November 2018

One of the PDO's largest producing fields in Oman consists of three stacked reservoir formations, two of which are currently producing while deeper reservoirs are being considered for development. The shallowest reservoir (~ 900 m depth) is a highly compacting carbonate gas reservoir under depletion, whereas the intermediate reservoir Shuaiba is an oil-bearing reservoir under water flood. The deeper reservoirs are oil and gas bearing located in the Sudair and Khuff formations.

Interpretation of 3D seismic data shows a major NE/SW and NW/SE fault system in all 3 reservoirs. Depletion in the shallow gas reservoir, which exhibits pore collapsing response on depletion, has induced surface subsidence which is active and expected to reach about 2.4 m at the end of field life. Subsurface deformations and induced stress changes have resulted in subset of the faults (NE/SW) to reactivate, causing seismic tremors, occasionally felt at surface.

Ongoing surface subsidence has resulted in some damage to surface facilities and subsurface well integrity issues. Furthermore, fault reactivation and/or loss of well integrity may induce leakage pathways for reservoir fluids to cross flow between reservoirs or to shallow aquifers. PDO has implemented an extensive monitoring program supported by parallel 3D geomechanical modeling studies, to manage ongoing field development whist mitigating the risks.

Extensive monitoring efforts using a variety of techniques are in place since 1999. Frequent InSAR satellite data measures surface subsidence with such high accuracy and resolution that local zones of higher deformation can be reliably identified and flagged. Continuous GPS data acquisition in a few places throughout the field allows for detailed temporal assessment of subsidence and forms the basis for predictions of total subsidence at end of field life. Periodic in-well compaction monitoring data provides insights in elastic and non-elastic deformation at reservoir layer scale, which is compared against core compressibility data. Continuous microseismic monitoring in a dozen or more observation wells highlights geomechanically active faults in the main reservoir, overburden and underburden, thereby identifying potential risk zones on a near-24/7 basis.

All of this data is used both for well and facilities management, and for providing calibration data for geomechanical models. Results provide clarity on future surface subsidence and differential settlement, which helps to identify facilities with potential risk. The project teams are provided with reliable predictions of surface subsidence throughout the field to ensure the current design tolerance is adequate for integrity of the facilities until the end of field life. This paper presents modeling workflow and calibration with monitoring data related to the geomechanical assessment.
Low Cost CO2 Capture: Dream or Reality?
Authors: Seif El Nasr Adel Ahmed , Geuzebroek Frank Haiko , Singh Prachi
Published: November 2018

Carbon capture and Storage is one of the major pathways to reduce carbon dioxide emission. Over the years, the success of this technology has been relatively limited. Reasons for this include lack of acceptance of storage, but also a lack of economic feasibility. In many cases, projects need to be funded through subsidies or are justified on the basis of use for enhanced oil recovery. Meanwhile an enormous effort has been placed into lowering the cost of capture. Many R&D programs have set the target to reduce cost from typically 50 $/ton to 25 $/ton, while even now this kind of reductions have not been realized, to the contrary there has been an increase in reported cost.

This paper addresses the background of the situation. It gives a literature overview of different technologies and the associated cost. A cost analysis is made of the different components in a CO2 capture plant. Comparison is made for the different technologies for post, pre- and oxy-combustion. The reasons for the high cost is analyzed and it is shown that no silver bullets exist. Several smart technologies are currently in development and the latest insights are given in how these technologies can reduce cost. A few studies are given that show why these technologies could not fulfill the initial expectations.

The results show that there is a tendency that advantages of technology solutions are often off-set by disadvantages that are not foreseen at the early Research stages, often because the new systems are more complicated than the state-of-the-art. This includes engineering cost for mitigate these dis advantages. An example is the use of smart solvents with phase change involved. This process may lead to lower OPEX due to lower energy consumption, but cost is increased by the higher cost for doing the separation or for keeping the solvents from leaving the solvent.
Novel Approaches for Remaining Hydrocarbon Saturation Evaluation Through Interpretation of Multi-Detector Pulsed Neutron Logs
Authors: Xian Hong , Anaevune Austin , Anijekwu Chinedu , Nayagawa Mbursa , Egwim Stella Ihuoma , Longe Victor , Ezechukwu Nduka , Lee Robert , Hulea Iulian
Published: November 2018

Novel interpretation approaches for remaining hydrocarbon saturation evaluation were developed from our study and presented in this paper. Innovative power law relationships and algorithms are used for evaluating oil saturation from Carbon/Oxygen (C/O) logs and gas saturation from capture-to-inelastic count rate ratios, based on the principle of the modern multi-detector pulsed neutron tool responses and the total porosity rock model. C/O log interpretation parameters are determined from the crossplot of near detector against far detector C/O logs, and gas saturation interpretation parameters are obtained from the crossplot of near detector versus far detector capture-to-inelastic count rate ratios. An alternative fixed response line method is proposed based on a simplified C/O log response rock model. Integrated interpretation is applied through the post processing combining the interpretations of C/O logs and capture-to-inelastic count rate ratios, to derive the final result.

The developed approaches have been applied to wells from Nigeria Delta and North Sea. Example results have successfully demonstrated greater advantages over the traditional methodologies. These new approaches have markedly reduced the saturation uncertainty related to wellbore effects, especially for wells with complex well completions and borehole fluid phase change. These results were subsequently useful information for the dynamic reservoir simulation models.
Energy Savings of Amine Sweetening Process through Lean and Rich Vapor Compression Approaches
Authors: Hatmi Khalid Al , Mashrafi As'ad Al , Balushi Sa'Ud Al , Al-Kalbani Haitham , Al-Battashi Mundhir , Shaikh Mohammed
Published: November 2018

The natural gas demand for energy production has increased in the last decades and is forecasted to further increase in the future. According to IEA energy outlook report 2008, approximately 40% of proven natural gas reserves are acidic (i.e. contains H2S and CO2). Hence, the need to capture associated contaminants of acidic gases to meet health, environmental, integrity and product specifications with affordable techniques will continue to be a challenge. Amine sweetening process is considered as one of the most acid gas removal techniques being used around the world due to its flexible operation, high removal efficiency and its design maturity. However, energy requirement around amine process has been always an area of a concern for all new and existing units. The top energy consumer is the regenerator re-boiler. Optimization of energy requirement around Amine plant becomes an important exercise for most operating companies to minimize its expenditures either during design stage or operation stage and achieve carbon emission target.

The aim of this study is to examine the effectiveness of two debottlenecking approaches namely Lean Vapor Compression (LVC) and Rich Vapor Compression (RVC) to minimize energy consumption around Amine units. These two approaches are considered to be the most promising in reducing the reboiler duty. These debottlenecking approaches involve modification of standard conventional process flow scheme with modified process flow scheme to enhance heat integration and regeneration efficiencies.

The two approaches have been applied on two different amine sweetening units in Sultanate of Oman with MDEA and MDEA-PZ solvents. ProMax process simulation software has been utilized to perform advanced thermodynamics model which has been initially validated by real field data.

Unlike most of published studies, the study has been conducted using models validated by real field data including different solvents and operating conditions as a base case. Additionally, the study focuses in pre-combustion amine based CO2 and H2S capture processes. By applying the Lean Vapor Compression approach, 40-50% reduction in re-boiler duty was achieved. For Rich Vapor Compression approach, saving of 10-11% has been achieved with considerable changes in amine circulation rate and stripper operating pressure.
Conformance Improvement for Ultra-High-Temperature Reservoir: A Comparative Study between Hydrostable and Conventional Preformed Particle Gel
Authors: Long Yifu , Yu Bowen , Zhu Changqian
Published: November 2018

Conformance improvement for ultra-high-temperature (130 °C) reservoirs is challenging due to the poor thermostability of conventional preformed particle gel (CPPG). To overcome the defect of thermal degradation, a novel hydrostable PPG (HT-PPG) was developed using the high-temperature tolerant crosslinker. In this work, a comparative study between the HT-PPG and CPPG has been presented in respects of their swelling behaviors, rheology properties and thermal stabilities. Particle swelling behaviors and viscoelasticities were firstly assessed in ambient. Using the swollen particles, a long-term aging at 130 °C underwent during which the physical status was monitored through high pressure vials (HPV). Furthermore, characterizations involved Scanning Electron Microscope (SEM) and Fourier Transform-Infrared Spectroscopy (FT-IR) were performed for both virgin and aged specimen. Thereby, an observation of gel microstructures and elucidation upon bonds or functional groups were provided. In addition to aging tests, we deployed the Differential Scanning Calorimetry (DSC) to investigate the inflection temperature as another indicator of particle thermostability. Attributed to the hydrostable crosslinker, the HT-PPG withstood 130 °C for at least 90 d. It was found that the HT-PPG effectively maintained its particulate shape, whereas, the CPPG completely degraded after 3-d aging. The HT-PPG maintained 28.8% of its initial storage modulus (G′). On the contrary, the normalized elasticity (G′/G0‘) of CPPG was only 0.43%. The SEM morphologies illustrated HT-PPG kept its rigid microstructure even after 90-d aging, while indicated destruction within CPPG network. According to FT-IR characterization, the decomposition of pristine crosslinker, N,N′-Methylenebisacrylamide in CPPG may account for its instability. DSC measurements furtherly demonstrated the favorability of HT-PPG in which HT-PPG exhibited a higher inflection temperature of 133.1 °C, however, CPPG only had an inflection temperature of 127.7 °C. This work turned out the novel HT-PPG could withstand ultra-high-temperature (130 °C) for more than 90 d, maintaining its particulate shape and viscoelasticity. This a durable plugging agent was notably superior to the CPPG, offering a candidate material for the conformance improvement in ultra-high-temperature reservoirs.
Impact of Natural Gas Exploration and Production on Mercury Concentrations in Surface Sediment of the Gulf of Thailand
Authors: Sompongchaiyakul Penjai , Bureekul Sujaree , Sombatjinda Siriphorn
Published: November 2018

More than two decades that the Gulf of Thailand (GOT) has been installed with petroleum hydrocarbon production platforms, currently over 400 platforms were installed and operated. Since mercury is a common contaminant in petroleum hydrocarbon production in Southeast Asia, minimal risk and environmental integrity should be concerned. Mercury concentration in surface sediment collected from the Gulf of Thailand in 2003 (89 stations), 2012 (174 stations) and 2013 (45 stations).

Sedimentological characteristics, readily oxidizable organic carbon and calcium carbonate were determined. All analyses were carried out in our laboratory using cold vapor atomic absorption spectroscopy. The results show an increase in trace amount of mercury in the Gulf's sediment. Average concentrations of mercury in surface sediments in the lower GOT collected in 2003, 2012 and 2013 were 24.4±9.00, 34.9±21.5 and 41.4±15.3 μg/kg dry weight (carbonate free basis). It is coincident to an increment in the number of platforms for natural gas exploration and production in the Gulf of Thailand. Spatial distribution of mercury in the sediments indicates a clearly linked to the exploration, development, production, and processing in petroleum and gas operation. Although the elevation of mercury level in the GOT's sediment does not showed high risk yet, treating and recycling of mercury contaminated substances generated during production are required in order to minimize the health risk in consumption of seafood collecting from the GOT.
Wax Deposition and Hydrate Transport Dynamic Simulations on an Oil Pipeline - Experiences Applying Novel Models for Flow Assurance Assessment
Authors: Puente Patricio , Martinez Victor , Richon Vanessa , Morud John , Zambare Neeraj
Published: November 2018

To minimize capital costs, operating companies are choosing to produce oil and gas through longer and longer subsea tie-backs. Transportation of multiphase gas, oil and aqueous mixture over long pipelines under high pressure and low subsea temperatures present some unique challenges. One of the most important challenges in flow assurance for such more common long pipeline designs is the possibility of blockage due to hydrate formation and/or wax deposition.

This paper discusses results using the newly developed wax deposition and hydrate transport models for a pre-FEED study. The models demonstrated are integrated into a generic and well proven multiphase dynamic simulator framework designed to be used for pre-FEED and FEED studies for a green oil field as well as to trouble shoot production challenges and simulate production of an already producing field.

LedaFlow™ is the multiphase, transient simulator that was used during the study. It contains a framework which easily allowed implementation of the new modules for wax and hydrate.

Wax deposition and hydrate transport are two important challenges for pipeline design and operations with waxy oil fluids that are prone to hydrate formation. An accurate model for quantifying the wax deposition and hydrate transport processes is essential to assure secure and safe transportation of these hydrocarbons. In addition, providing accurate predictions of not only the pressure drop along the pipeline but also of the flow behavior during the transport will help to optimize the development schemes, avoiding over-design. There are several options for modeling both processes, however, for the evaluation reported here not only the process itself is important, but to model dynamic operational scenarios is also important. For this study a waxy and hydrate forming stream was selected. This stream comes from a single stage separator in an offshore facility.

The new wax model includes some key features, such as the non-Newtonian nature of the waxy oil, the growth of the wax layer and the effect on heat transfer throughout the pipeline. It is based on a known model from the literature, however, it brings a fundamental new framework for simulating the effect of wax on multiphase flow as it benefits from all the functionalities of the multiphase flow simulator like transient operations, accurate thermal modeling including use of heat tracing. All of this has been considered in our study of normal operations. In the hydrate transport model, mass transfer during hydrate formation, the hydrate former/water depletion in the pipeline and the slurry viscosity with hydrate particles have all been considered.
Innovative Water-Blocking Agent Based on High Stable Emulsion with Nanoparticles for IOR Implementation
Authors: Sergeev Vitaly , Kim Ijung , Zeigman Juri , Yakubov Ravil
Published: November 2018

This article represents the results of the research and development project that has been conducted with the goal to create an innovative and environmental water-blocking agent for the enhancement efficiency of the improved oil recovery methods. The innovation of the developed water-blocking agent lies in the combination of unique physical and chemical properties: high thermal stability (140 °C), improved rheology (viscoplastic properties), outstanding surface activity (regulation of the wettability of rock surface), and selective blocking effect. The key factor to combine all of these properties in one solution is to apply colloidal silicon dioxide nanoparticles with modified surface as a stabilizer and surface-active phase in the emulsion system. Also, a technology on the new water-blocking agent for the effective application in the intensification of oil production (well stimulation, IOP) methods has been developed, and well-tested in the field. For the investigation of the unique properties of the new emulsion systems with colloidal silicon dioxide nanoparticles, different types of laboratory experiments were carried-out, including coreflooding tests on the oilfield cores by using the facility with parallel coreholders for stand modelling of the developed technology in the IOP. The main task of the IOP technology is to redistribute the filtration inflows in the near-wellbore zone by selectively blocking the most permeable water-saturated intervals and to penerate through the less permeable inter-layers of the bottomhole zone by the acid composition.
Bitumen Identification from NMR and Triple Combo Logs in Tight Gas Formation in the Sultanate of Oman
Authors: Lukmanov Rinat
Published: November 2018

The presence of bitumen is an obvious risk for reservoir development. Pore-filling bitumen degrades reservoir quality. Sweetspotting, discriminating between producible oil and gas and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and the optimal development planning. However it is in most cases impossible to make such differentiation using conventional logs.

It is well known that the Nuclear Magnetic Resonance (NMR) log provides an opportunity to identify the presence of reservoir bitumen in oil bearing reservoirs. The zones containing bitumen within oil and water reservoirs are characterized by lower NMR porosity estimates when compared to porosity from the density and neutron tools. But in gas reservoirs, bitumen identification from NMR porosity deficit is not a common industry practice. The porosity deficit could be related not only to the presence of bitumen, but also to the presence of gas in the pore space.

The case studies include tight gas reservoirs in Miqrat and Middle Gharif formations, both located in the Sultanate of Oman. Well tests showed gas rates lower than expected, accompanied by low mobility and sometimes water production from intervals with relatively good porosity and saturation calculated from logs. Besides, bitumen was identified from core. A new methodology was developed which can differentiate between residual gas and bitumen presence based on Density, Neutron and NMR logs in conjunction with resistivity. One of the pre-requisites is that the reservoir lithology must be known. The remaining gas saturation is quantified from Density-Neutron separation. If we know the Hydrogen index (HI) of gas, the NMR porosity deficit can be compensated for residual gas effect. Bitumen saturation can be quantified from the difference of total porosity and NMR compensated porosity.

The methodology was tested on two tight gas reservoirs of the Sultanate of Oman. Core analysis, production data, and total organic carbon (TOC) derived from pulsed neutron logs were used to verify the results of the suggested methodology. The comparison shows that the methodology can be used for semi-qualitative identification of bitumen. It was also observed that the bitumen distribution varies across the field, and overall the majority of reservoir hydrocarbons are moveable. Recommendations on the workflow for static and dynamic modeling were provided.

The suggested novel approach of bitumen identification in gas bearing reservoirs is relatively simple. It provides fit for purpose results for gas bearing reservoirs including tight gas which in turn can be used for more accurate estimation of gas volumes and optimizing development planning.
Deepwater HPHT Drilling through Ultra Narrow PPFG Window: A Case Study by ENI Where the Combination of Continuous Circulation Technology Together with MPD Drilling has been Successfully Applied to Extreme Drilling Environment Condition in HPHT Ultra Deepwater Well
Authors: Squintani Enrico , Uslenghi Andrea , Ferrari Susanna , Affede Luca
Published: November 2018

Ultra Deepwater wells are commonly characterized by a narrow margin between pore and fracture gradients. Eni pioneer of the Continuous circulation technique has pushed the control of annulus dynamic pressure to the limit. The experience presented in this paper cover the drilling of an HPHT Deepwater well, through an ultra narrow PPFG window by means of technology application and strict procedural control.

In the case study presented the reservoir section of an HPHT well was planned to be reached with an adequate kick tolerance and choke margin by applying the ENI near balance drilling technique (e-nbd™) in order to ensure strict control on the primary barrier and achieving the aimed operational and safety performance. The plan required the use of e-cd™ (eni circulating devices) system installed for the first time on a drilling ship with the 6 5/8″ DPs.
Performance of an Electric Submersible Pump with Gas Slugs and Different Inlets
Authors: Perisho Randal , Robinson Mark
Published: November 2018

The oil industry has been experiencing issues with "slugs" of gas that limit the ability of the pump to create head and causes a low amp or underload shutdown. Baker Hughes has developed special gas inlets to improve flow in high gas wells. Electric submersible pump (ESP) performance is evaluated with a new "Slug" test to determine how a "slug" (or short burst) of gas affects the output flow.

Several different inlet devices are tested with a mixed flow pump in a high gas environment using water and nitrogen. An annular ring introduces gas below the pump inlet and partial flow is allowed to bypass the pump inlet to simulate real well conditions. Three inlet devices are compared to a standard pump inlet to determine how long it takes a slug of gas to terminate flow. In addition, these inlet devices are tested at steady state conditions with different flow rates and gas volume fractions (GVF).

The "gas slug handling" capabilities of a standard mixed flow pump stage is compared with three different inlet devices. The test is repeated at several different flow rates to document the time required for a slug of gas to stall the system. A standard pump running at 1000 bpd stalls in 20 seconds as compared to 70 seconds on the best inlet when a slug of 95% gas is introduced. When the system is tilted 30 degrees off vertical, a slug of gas will cause them all stall in 30 to 41 seconds.

Steady state gas tests were conducted at a variety of gas volume fractions to find the resulting output flow and pressure for each inlet device at flows between 500 and 2500 barrels per day. The resulting gas curves are presented for each inlet device with the system running in a vertical and 30 degrees off vertical. One of the inlets was able to generate four times the output pressure of a standard pump at 40% gas volume fraction. The production inlet ran better than any other inlet when the system is tilted 30 degrees off vertical.
Experimental Investigation of Osmosis as a Mechanism for Low-Salinity EOR
Authors: Pollen Erik Norrud , Berg Carl Fredrik
Published: November 2018

The objective of this paper is to describe experiments conducted to investigate osmosis as a mechanism for low-salinity enhanced oil recovery (EOR). For this purpose, an experiment was designed to facilitate enhanced oil recovery by osmosis-induced connate water expansion, while at the same time reducing the contributions of other proposed low-salinity mechanisms. Considerations were also made to achieve osmotic water transport rates comparable to what is expected at reservoir temperature.

The correlation between enhanced oil recovery and the surface-to-volume ratio was of particular interest. Because the osmotic pressure gradients occur over distances comparable to the pore size, it is plausible that fluid redistribution due to osmosis would lead to a fairly local redistribution of oil, and thereby have a small impact on overall enhanced recovery in the field. However, near exposed surfaces, this local redistribution may result in oil production.

Previous investigations of osmosis as an underlying low-salinity mechanism have consisted of visualization experiments, where water transport and oil movement under influence of osmotic gradients have been observed. Our experiments are intended to increase the understanding of the relative importance of osmosis in both small-scale low-salinity experiment results, and for field-scale low-salinity flooding.

In the experiments, oil-wet sandstone samples with different surface-to-volume ratios were saturated with high-salinity water and oil to irreducible water saturation. The samples were first left to spontaneous imbibe in high-salinity water and afterward in low-salinity water. Additional oil production from spontaneous imbibition of low-salinity was recorded and compared with the surface-to-volume ratio. The experiment was performed twice, at both ambient and elevated temperatures.

The experiments at ambient temperature resulted in increased oil production values of 8-22% of pore volume by low-salinity spontaneous imbibition. No clear correlation was found between increased oil recovery and the surface-to-volume ratio. A correlation was, however, seen between increased oil production and the pore volume. Thus, increased oil production by low-salinity imbibition seems to be proportionate to the pore volume.

The experiments at elevated temperature resulted in low values of increased oil production by low-salinity spontaneous imbibition, and the values do not seem to correlate with either surface area or pore volume. The low response is believed to be caused by thermal effects from repeated heating and cooling of the samples during the preparations.

Our results cannot dismiss osmosis as an important mechanism for low-salinity EOR. Possible explanations for the correlation between increased oil production and pore volume are hysteresis and simultaneous connate water expansion throughout the core.
New Model for Wettability Change with Depth in Mixed-Wet Complex Carbonates
Authors: C. Ferreira Flavio , Stukan Mikhail , Liang Lin , Souza Andre , Venkataramanan Lalitha , Beletskaya Anna , Dias Daniel , Dantas da Silva Marianna
Published: November 2018

Oil-water relative permeability and capillary pressure are key inputs for multiphase reservoir simulations. These data are significantly impacted by the wettability state in the reservoir and by the pore space characteristics of the rock. However, in the laboratory, there are several challenges related to the validation and interpretation of the special core analysis (SCAL) measurements. They are mostly associated with the core preservation or restoration processes and resulting wettability states. To improve dynamic reservoir rock typing (DRRT) process, a new model, describing the change of wettability fraction with depth in mixed-wet reservoirs, is proposed. The proposed model is based on solid physics describing the interactions between the rock grain surfaces and the fluids filling the pore space. First, the model considers the oil migration from the source rock into the originally water-wet reservoir and the corresponding capillary pressure rise, as the height above the free water level (HAFWL) is progressively increased. Then, oil-wet and water-wet fractions are estimated for different static reservoir rock types (SRRT) and different HAFWL, based on the wettability change potential of the rock-fluid system and oil-water capillary pressure curves. Additionally, mixed-wet capillary pressure and relative permeability curves are estimated for both oil displacing water (drainage) and water displacing oil (imbibition) processes, based on the estimated mixed-wet fractions and single-wet curves. We discussed the model assumptions and its parameters’ uncertainties. We prepared a comprehensive sensitivity study on the impact of wettability variability with depth on oil recovery results. This study used a synthetic carbonate-reservoir simulation model, under waterflooding, by incorporating the concept of DRRT defined according to the different SRRT and estimated wettability fractions. The results showed a significant impact of wettability variability on oil in place and reserves estimates for waterflooding processes in typical complex, mixed-wet carbonate reservoirs, such as the ones found in the Brazilian Pre-Salt. We also discuss the potential impact of wettability change with depth on well logs like resistivity, nuclear magnetic resonance (NMR) and dielectric logs. The proposed reservoir wettability model and its corresponding DRRT workflow is relatively simple and widely applicable, and may significantly improve reservoir simulation and wettability uncertainty analysis. It also explicitly identifies the required wettability parameters to be obtained from laboratory experiments and well logs. Finally, the proposed model may be integrated with special core analysis, well logs and digital-rock analysis.