bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing Data Acquisition and Data Utilization to Maximize the Value of Reservoir Surveillance: Case Studies
Authors: Zhao Wenyang , Al-Neaimi Ahmed Khalifa , Saif Omar Yousef , Murad Ahmed Mohamed
Published: November 2017

Data acquisition is one of the most critical parts to a sound reservoir management across the whole petroleum industry history. There are more challenges in brown fields, especially offshore fields. With the pace of moving to digital oil field (DOF), more surveillance equipment and methods are becoming available. Hence oil recovery could be improved with more accurate reservoir management. Maximizing the utilization of testing equipment and acquired data are becoming more fundamental than ever.

This paper presents two field cases from one of the biggest offshore fields. The first case is to maximize the value of available testing equipment through optimizing data acquisition plans. The second case shows a trial of maximizing utilization of the acquired data.

As one of the steps moving toward digital oil field, MultiPhase Flow Meter (MPFM) has been installed for more frequent flow tests. In addition to normal flow tests, this paper presents a new role for MPFM, which is to identify communication between strings in dual-string wells. Communication between strings is a high potential risk in this giant offshore field, because majority of the wells are dual strings. Wells with communication between strings have been identified during routine flow tests with no extra cost. In order to assure the feasibility of this approach, conventional communication test through downhole pressure measurement has been performed. Using MPFM to do communication test can save a considerable amount of expenditure comparing to the conventional method. Early actions can also be ensured to avoid reservoir cross-flow. Besides, the volume of communication can also be measured, which could help decide the optimum rate and optimize back allocation.

The flow test results are fundamental data for reservoir management and field development. The widely used results are the fluid flow rates. However, the value of temperature data was not fully revealed. The paper presents an empirical correlation derived from measurements. The empirical correlations between WHFT (Well Head Flow Temperature) and flow rate have been generated for each oil production string based on flow test data. The high quality correlations have been utilized to optimize back allocation with conditions. The value of the empirical correlation is more prominent when there are unseen obstructions in the production system. The temperature data in daily operation also indicates abnormal well performance (e.g. DHSV malfunction, scale deposition). Early actions can be planned and taken to avoid further production loss and improve operation efficiency.

The two field cases in such a brown field happened in a pre-DOF age, which also shed light on the bright future of digital oil field and better reservoir management.
Assessment of Formation Damage Potential of Novel Drilling Fluids via Integration of Fluid Loss Data with Filter Cake Quality and Filtrate Core Penetration Depth from NMR and MRI
Authors: Vryzas Zisis , Matenoglou Grigorios , Kelessidis Vassilios C.
Published: November 2017

Appropriate drilling fluid additives which can build effective filter cakes are key components to minimize formation damage. Today there exists no effective and quantitative technique which can assess the formation damage minimization potential of any novel drilling fluid. This study provides the methodology for such a technique, by integrating HP/HT fluid loss data, derived from standard API HP/HT filter press, with filter cake quality and filtrate penetration depth, derived by Nuclear Magnetic Resonance (NMR) and Magnetic Resonance Imaging (MRI) techniques.

Novel nano-based drilling fluidwas made of de-ionized water, 7 wt% commercial Na-bentonite, and addition of custom made iron oxide (CM Fe3O4) nanoparticles (NP) at 0.5 wt%. Its excellent filtration characteristics were determined at elevated pressures and temperatures using a HP/HT filter press (500 psi/350°F) with ceramic discs, mimicking the formation, as filter media of k=775 mD. NMR T2 relaxation time measurements provided the pore size distribution of the ceramic discs, and a newly developed MRI technique by our team allowed direct visualization on the core-ceramic disc of the produced filter cake and filtrate penetration depth, providing insights on filtration characteristics.

Addition of 0.5 wt% Fe3O4 NP resulted in a decrease of fluid loss by 47% compared to that obtained from the base fluid (BF) without the nanoparticles. The excellent filtration characteristics were attributed to the synergistic interaction of NP with bentonite platelets producing a strong microstructure network leading to rigid and very low permeability filter cakes. Spin-spin relaxation time (T2) NMR measurements revealed different pore size distribution of the nano-enhanced drilling fluid showing its tendency to occupy the smallest pores of the filter medium (ceramic disc). MRI T2 measurements revealed the saturation profiles of the drilling fluids inside the ceramic discs, in 3-D space. This allowed the visual representation of the penetration depth of the filtrate produced in the ceramic discs of the different tested drilling fluids.

Our integrated characterization approach, gives us tools to analyze inter-particle interactions in the filter cakes at HP/HT conditions in order to explain the significant improvement in fluid loss performance of novel drilling fluids. The information gained in this study is considered to be extremely significant for deriving an effective methodology for assessing formation damage potential of any newly developed drilling fluid which can lead to more efficient and cost-effective drilling activities.
Cathodic Protection Effectiveness Evaluation in ADCO Wells Utilizing Multi-Barrier Magnetic Defectoscopy
Authors: Yugay A. , Daghmouni H. B. , Ali A. B. , Gupta T. K. , Grandhe S. P. , Volkov M.
Published: November 2017

The objective of the project is to evaluate effectiveness of the Cathodic Protection (CP) as a corrosion reducing solution after several years of implementation. The project has been initiated based on the Well Integrity Records and Requirements.

5 wells in different Company's fields have been selected to demonstrate the effectiveness of Cathodic Protection. The wells are characterized by different casing design, age, and time of CP installation. The wells represent distinctive fields, where similar integrity issues are observed, such as intense casing corrosion due to lack of isolation and exposure to corrosive environment. Analysis of CP performance is based on actual metal loss identified in 9-5/8″ and 13-3/8″ casings using multi-barrier electromagnetic metal loss evaluation tool. The statistical analysis was performed to correlate the corrosion rate with different key parameters and to evaluate how effective the CP is during the well life cycle.

Several observations were made based on the logging results and statistical analysis. The areas protected by CP demonstrated lower corrosion rates. A clear correlation was observed between the corrosion progress and the period of time the wells were operated without CP. 13 3/8″ casing is relatively more protected compared to 9 5/8″ since the CP effectiveness attenuates with depth and becomes less effective below the 13 3/8″ casing shoe. The corrosion zones identified in several wells in 9 5/8″ casing inside 13 3/8″ clearly confirm that CP is effective only for the outer casing surfaces and does not protect from internal corrosion. Cement quality and bonding also affect the CP performance. The recommendation was given to implement the CP system in all currently unprotected wells and those to be drilled in future.

The results of the conducted study clearly demonstrate effectiveness of Cathodic Protection system in reducing corrosion in well casings. It also helps to identify system limitations and key parameters affecting its efficiency. This paper might be interesting to other Companies with similar well integrity problems due to corrosion.
Oil Spill - Cleaning and Recovery by Multi-Layered Fibre Tube
Authors: Chaturvedi Manu , Adlakha Manan Manoj , Choudhary Animesh
Published: November 2017

In recent years, oil spills have been tremendously harming the environment. The major challenges that the world today faces is its cleaning and recovery. Our aim is to clean the spilled oil at a faster rate and recover it in an efficient manner.

Our idea aims at the use of a specially designed three layered tube, ‘Polycoweed’ which consists of three layers consisting of milkweed fiber, cotton fiber and finally a layer of polypropylene. The tube is mostly made up of naturally occurring substances and so is eco-friendly. 155g (5.7 oz) of milkweed fiber can absorb a total of 7 L (1.8 gal) of oil at a rate of 0.23 L (0.06 gallons) per minute, twice as fast as competing products made from polypropylene. Polypropylene is the outermost layer with milkweed and cotton placed sequentially inside to allow selective absorption.

Polycoweed will not only clean up the oil spill but at the same time recover the absorbed oil. The cotton fiber and the milkweed fiber that we have used have special ability to absorb about 30-40 times of oil of their own weight. Also the tube that has been designed can be reused 4-5 times.

The novelty lies in the fact that this tube ‘Polycoweed’ isn't only cost-effective but will also generate revenue from oil that is recovered. This tube is the solution to all the problems which this oil driven world was searching for.
A New Dual-Permeability Model for Naturally Fractured Reservoirs
Authors: Lu Jing , Qu Jinbao
Published: November 2017

Naturally fractured reservoirs (NFRs) are the reservoirs with two distinct types of porous media called the fracture and matrix. The pressure behavior of naturally fractured reservoirs is usually studied by using Warren and Root model (Warren and Root, 1963).

Warren and Root model assumes that production from the naturally fractured system goes from the matrix to the fracture and thence to wellbore (Warren and Root, 1963). However, this assumption is oversimplified if the contrast between the permeability of matrix system and that of fracture system is not significant. In order to estimate the limits of validity of solutions based on Warren and Root model and to study the behavior of a naturally fractured reservoir when the contrast between the two permeability are not significant, it is necessary to solve the original model proposed by Barenblatt and Zheltov (Chen 1989). But the analytical solutions to this model which were obtained by numerical analysis or numerical inversion are very complex and inconvenient to use (Lu, Zhu and Tiab, 2009).

Assuming that both of the matrix and fractures produce directly into the wellbore, a new mathematical model for dual-permeability naturally fractured reservoirs is presented in this paper. Based on our proposed model, it is concluded that there are four stages for the pressure behavior of NFRs; the double-permeability system behave like a reservoir with a constant pressure boundary when the dimensionless time approaches to infinite.

The solution procedure proposed in this paper is a fast tool to evaluate a vertical well performance in a dual-permeability naturally fractured reservoir.
Reduce Total Cost of Ownership and Improve Industrial Grid Stability at Oil and Gas Facilities with Integrated Power Management
Authors: Shamim Taiyab , Pineda Andrés Felipe
Published: November 2017

This paper will examine the benefits of using integrated power management systems for automatic load shedding and generation control at oil and gas facilities.

Many oil and gas facilities today, such as refineries, offshore installations, pipelines, and well pads located in remote areas operate their own autonomous or partially autonomous power networks to ensure that an adequate amount of electricity is available to run critical equipment in the event of a loss of the utility grid. Load shedding is an important procedure whereby non-essential loads, such as cooling and air conditioning units, motors, furnaces, compressors, pumps, and lighting systems are shut down in a strategic manner in order to ensure that the facility's core processes remain running and costly downtime is avoided if there is a generation failure or disturbance either onsite or within the public utility grid. To achieve this, many operators today use separate independent systems, which shed load in accordance with a predefined priority list. However, because these systems are often deployed in addition to an energy automation system, they have their own hardware, wiring, and maintenance requirements, which lead to inefficiencies, overlap between equipment, and higher lifecycle costs.

This paper will discuss the advantages of embedding applications in existing substation automation infrastructure and combining energy automation and power management applications like load shedding and automatic generation control (AGC). Doing so enables facilities to achieve substantial cost savings and improve the reliability of their onsite power networks. A case study will be presented on a major crude oil pipeline, where the use of an integrated power management solution helped an operator reduce CAPEX and OPEX, improve critical process uptime, and enhance safety by allowing personnel to control systems remotely.

The paper will also discuss how enterprises can use integrated power management systems for operator training and grid simulation purposes.
Enhanced Oil Recovery in a High Stratigraphic Complex Reservoir: Casabe Project Case Study
Authors: Gheneim Thaer , Azancot Annalyn , Acosta Tito , Zapata Jose Francisco , Chaparro Carlos , Lobo Adriano , Jimenez Ana María , Perez Gerson
Published: November 2017

Casabe field reservoir characteristics are multilayer, geological complexity, vertical/areal heterogeneity and commingled production. Due large difference in mobility between oil and water (M ~ 20) and the maturity of water flooding, several operational problems have arisen, such as, increase of water cut, channeling, sand production, etc. These problems together with the high remaining reserves and identification of bypassed oil, were the main reasons to evaluate EOR process as a solution to increase the recovery factor.

A reduced Cycle Time was created to reduce the time from design to full field implementation which involves the following phases: Screening/Conceptual Design, Pilot Design, Drilling-Workover and Facilities, Operation & Surveillance, Pilot Expansion, Full Field Development Plan, Reserves & FID. This strategy is based on multitask parallel process to allow fast track decision making and activities execution for a fast pilot implementation, which allowed to implement the EOR pilot in 24 months form the screening to pilot Operation & Surveillance. After the screening, polymer flooding was considered for mobility ratio modification to improve sweep efficiency and therefore increase RF.

The best producer layers were selected, based on the areal continuity and residual oil in place, as target sands for polymer injection. One pattern was selected for the pilot. Laboratory tests, along with reservoir simulation confirmed the potential of chemical EOR in the selected sands and pilot area. Polymer injection was performed in four injector wells of the selected pattern. The polymer flooding process was monitored in the central producer and in the eight producers of the second line.

A surveillance plan was implemented to collect the information required to evaluate, with the lowest uncertainty, the results of this pilot. An observation well was drilled to monitored changes in oil saturation. The surveillance plan was critical to be able to control the polymer injection process, to have a proper technical evaluation of the pilot and to optimize costs during the future expansion and full field implementation. Polymer flooding have increased the RF on the selected area.

The fast-tracking strategy for an EOR project execution was successfully implemented in Casabe Field and the pilot was delivered in 2 years proving the concept of 5-year road map it is possible. The reduced Cycle Time (5-year Road Map) could be used as reference for implementation of new EOR pilots in other fields in shorter time and optimizing resources.

The workflows used and the analysis procedures created for this pilot could be used as reference for the implementation of future pilots in fields with similar characteristics.
Fast Integrated Reservoir Modelling on the Gjøa Field Offshore Norway
Authors: Sætrom Jon , Morell Eirk , Ravari Reza Rostami , Maitre Claire Le , Seldal Mailin
Published: November 2017

In this paper, we combine reservoir data; reservoir physics; machine learning algorithms; and the "know-how" of the subsurface team in one efficient workflow to quickly build reservoir models that lead to an improved understanding of the Gjøa field offshore Norway. Key elements of the solution include:

Consistent integration of static and dynamic data – when they arrive – in one automated and repeatable modelling process. Ability to address uncertainty in all parts of the modelling chain – from G&G data interpretation to flow simulation and dynamic data conditioning. Single platform for multidisciplinary collaboration between the subsurface disciplines in the modelling and reservoir management efforts. Scalability and robustness – the workflow is equally applicable for small and large reservoirs.

Additionally, we implement a prescriptive analytics solution to quickly identify and rank robust infill-well targets using data conditioned reservoir models as input.

The amount of data we collect from a reservoir is rapidly increasing. Hence, it is more important than ever to utilize tools that address the shortcomings of the traditional reservoir modelling approaches. Having the ability to capture the information found in the collected static and dynamic data in a consistent manner when they arrive, while embracing the inherent uncertainty of the reservoir modelling process, will lead to improved reservoir management decisions, and ultimately an increase in the recoverable volume.
An Integrated Workflow to Close Out the Uncertainties in a Geomechanical Model in a Giant Onshore Carbonate Gas Field in Abu Dhabi, UAE
Authors: Masoud Rashad , Noufal A. , Ateeq B. , Al Ammari K. , El Gohary M. , Al Hammadi H. , Kumar S. , de Joussineau G. , Bois A.
Published: November 2017

A giant lean gas reservoir overlying a large oil rim is producing for more than 27 years became under depletion mode without any pressure maintenance. Formation collapse in reservoirs under depletion can cause permeability reduction, completion damage and well failure, reducing or even interrupting production and affecting the ultimate recovery from the reservoir. It is therefore critical to predict any risk in formation collapse. If such risks exist, recommendations are required to optimize reservoir management.

Stress measurements were acquired and core analysis were performed in intact rocks area and used for 1D MEM (Mechanical Earth Model) and 3D MEM. 1D MEMs for 10 wells were constructed. Rock mechanical tests were conducted on core samples. 3D MEM was created with 13 interpreted seismic overburden horizons and 105 seismic faults. Four scenarios were performed to identify formation failure during the scheduled production. The worst-case scenario will happen of reservoir depletion, in case of weak formation and reactivated faults.

Intensive logging, fracture modelling, coring program across the main fault corridor and RMT (Rock Mechanics Tests) were performed in vertical and horizontal holes across the fault corridor area to fulfil gaps of rock mechanical properties (elastic properties and rock strength) and field stresses. The acquired data were seeds for Lab testing, fracture network analysis and fault characterization which used to update the 3D MEM.

Additional Lab tests to fill gaps in rock samples with high porosity (> 30%) were carried out and 1D MEM of 5 more wells were constructed, and the 3D MEM were updated.

The 2017 updated 3D MEM eliminates three of the 2013 four scenarios and ended up with one robust scenario that shows better reservoir integrity and very small localized areas of pore collapse in high porosity regions only (> 30%) compare to the previous model. The reservoir can produce under depletion mode with production optimization in areas of expected compaction. Well integrity study and compaction monitoring are also considered to be commentary studies.
Enhancing Well Interventions with the Use of Transient Software - New Case Histories from Around the World
Authors: Craig Steven , Aitken Bill , Livescu Silviu
Published: November 2017

Since the mid-1980s, advances in coiled tubing (CT) modelling software have enhanced operational efficiency, reduced technical risks, expanded the acceptable operating envelope and improved well intervention success rates. Until relatively recently, models were the steady-state type. Since 2010 dynamic modelling for CT operations has been utilized. This paper, focusing exclusively on transient modelling, incorporates unpublished novel case histories showing pre-job optimization and post-job investigations. The focus is on showing the simulation advantages of transient versus steady-state conditions.

The transient model predicts the changes over time resulting from varying pumped and produced fluid rates, varying fluid types, two-phase relationships, location of solids, location of the CT and the wellhead choke size. Equations for the conservation of mass and momentum and a unified drift-flux model, valid for all flow regimes, are included in the model. Based on experimental testing on a full-scale flow loop, a critical gas flow velocity model was developed. It has been validated against published case histories and results of other transient models primarily developed for pipeline operations.

Several case histories are presented, showing phenomena that cannot be captured by steady-state CT models. First, a review of two cases of post-job investigations are presented: a re-calculation considering multiple well pressures and fluid content changes, to confirm that the CT weight was accurately recorded prior to an operational incident; and a re-calculation of a solids cleanout operation where incorrect execution resulted in stuck CT. Second, a review of two cases of pre-job analysis includes the modelling the switching of a tool with respect to time instead of pressure (required because high nitrogen rates mask surface pressure indications of downhole changes); and the modelling of a complex situation where the client requested an optimized dewatering operation with only a small volume of nitrogen available. Finally, cases of optimizing solids cleanout removal with multiple changes in fluid rheology are reviewed.

Three prior papers (Salim and Li 2009; Salim et al. 2010; Li et al. 2012) regarding this transient model were focused on the model theory and gas lift optimizations. The practical cases presented in this paper are novel to CT transient modelling papers and provide operators with a greater understanding of the value that the transient modelling can provide to their operations.
Fit-For-Purpose Roller Cone Bit Technology to Improve Performance in Highly Interbedded Carbonates and Anhydrite Application in Southeast Kuwait
Authors: Beheiry Karim , Al Heiny Ahmed , Malik Abdullah , AL Mayyan Haitham
Published: November 2017

A 16-in. section of a well, located in the Great Burgan field of southeastern Kuwait, presents multiple drilling challenges. The section is approximately 4,000 to 5,000 ft long and is drilled through a highly interbedded formation that consists of carbonate, shale, and anhydrite. The carbonate typically generates impact damage, causing high levels of thermal degradation that affect the gauge inserts. In addition, lost circulation is a hazard commonly encountered during this application. The drilling of this section requires control of drilling parameters, specifically the flow rate. Failure to maintain sufficient flow rate results in poor cuttings transmission and insufficient cutting structure cooling that can create further performance complications.

The challenge in this application is to drill the entire section with one bit run at a maximum rate of penetration (ROP).

This paper describes a new tungsten carbide insert (TCI) drill bit design that helped to improve the drilling performance in this challenging section in different well profiles.

This paper provides a detailed study of the challenging 16-in. section in Kuwait and discusses potential issues, problems, and solutions associated with the use of the new advanced roller cone design.
Spheroid Life Extension: Contemporary Approach, Advanced Simulation and Case Study
Authors: Al Omari Ammar , Herzallah Osama , Toubar Ashraf , Awda Zakaria , Mubarak Nouf
Published: November 2017

The spherical shaped tanks/separators represent a common type of equipment in the Oil & Gas industry. The spherical shape is preferred due to the robustness that the geometry offers, in addition to the large fluid surface area that maximizes the gravity separation process. However, these convoluted shapes introduce difficulties in routine inspection and integrity assurance. This paper studies a fitness for service (FFS) assessment of complex damage mechanisms which include localized bottom bulge formation, local shell buckling and underside soil corrosion.

This research analyzes a case study of atmospheric Horton Spheroid separation tank with 20,000 barrel capacity, 20 m diameter and 15 m height. The analysis includes a design calculation review of the spheroid via Finite Element Analysis (FEA), API 620 (API 620 1962-2014) standard review from 1962 to 2014 and simulation of the steam desludging maintenance procedure. 3D nonlinear Finite Element model (FEM) was introduced to analyze the spheroid fitness for service under several bulgings and localized buckling. The FEA results were compared to inspection results to validate and confirm the bulging locations, bulging sizing and spheroid integrity.

The FEA model results showed that the vacuumed spheroid is subjected to inward bulge formation at the crown upper shell and lower bottom plates. Due to the non-uniform curvature of the spheroid, the bulge locations are difficult to be predicted, however, the FEA results were able to detect precisely the location and geometry of bulges. The plastic strain failure criterion was used to assess the fitness for service of the spheroid for continuous operation with the presence of those deformations. The FEA model results showed excellent agreement with internal inspection results and findings. The FEA model results were used to conduct semi-qualitative risk assessment on other identical spheroids; an endorsement extension was granted based on the semi-qualitative assessment.
New Approach Using Dual Porosity Dual Permeability and Dissolved Pore Network to Simulation Modeling for Fractured Carbonate Reservoir in Abu Dhabi
Authors: Uematsu H. , Auxiette G. , Bellah S. , Virlan V. , Stojic T.
Published: November 2017

In this paper, we present a case study of using dual porosity dual permeability (DPDP) simulation for an offshore Abu Dhabi carbonate oil reservoir exhibiting complex flow behavior through matrix, fracture system and conductive faults. The main objective of the study is to present and explain the reservoir flow behaviors by constructing and using advanced reservoir geologic and simulation models. The results of the study will be utilized as part of the inputs for full field development plan.

Initially, an extensive work on the faults and fractures characterization was conducted to properly integrate this information into a dynamic model using DPDP modeling approach. However, the poor response of some wells or field sectors indicated the insufficiency of this concept to capture the full complexity of the reservoir system. Consequently, a new geological concept was proposed to represent the effect of enhanced matrix permeability related to facies dissolution process in the reservoir model properties distribution.

To perform such model modification, an innovative new approach was developed called "Dissolved pore network" concept, linking matrix permeability to the fraction of matrix rock macro pores system inferred from the pore size distribution of MICP plug analysis. This "Dissolved pore network" concept was originally developed by Schlumberger in previous projects based on their worldwide experiences. The concept was successfully implemented in this study using an empirical equation to enhance the permeability of a certain category of facies affected by the dissolution process.

The study successfully demonstrated that the proposed geological concept integrating the dissolved pore network concept with the faults and fractures system in the reservoir modelling workflow allowed better understanding and representation of the reservoir complexity and the well flow behavior. This smart combination of the two distinct systems was never implemented in a similar manner in the oil industry. Therefore, we strongly believe that this successful implementation will pave the way for constructing more realistic reservoir models for a complex reservoir with multiple pore systems.
Keyless Pigging
Authors: Tharmalingam T. , El-Sawah Mohamed , Sensarma Pradip Kumar , Shabaka Ashraf , Al-Ameri Ali Hamed , Nessim Amr
Published: November 2017

Oil and gas operators are driving towards ‘Digital Oil Field’, injecting best available technologies (BAT) coupled with the modern control systems and networks. This will help to offset a shrinking labour force, higher operational costs and supports the growing demand for improved efficiency and HSE throughout their oil production facilities. Emphasis has been made to explore various innovative schemes, taking the advantage of technology and automation, to provide safe operating environment with minimized OPEX. ‘Keyless’ pigging interlock scheme is one such innovation introduced to overcome the operational difficulties experienced with the existing key pigging interlock schemes without compromising the safety.
Removal of Gas-Condensate by CO2 Huff-n-Puff Injection: A Simulation Study
Authors: Ayub Muhammad , Ramadan Moemen , Bataweel Mohammed A. , Al-Mulhem Abdulrahman A.
Published: November 2017

Accumulation of gas-condensates in near wellbore regions, and consequently reduction of gas production rates, is a well-known phenomenon in most gas reservoirs all around the globe. In this study, injection of CO2 in "huff-n-puff" mode and its potential advantages of removing accumulated gas-condensates are thoroughly investigated. A compositional simulator was used to capture the near wellbore fluid flow physics causing the condensate dropout under various wellbore/field operational conditions. The severity of condensate blockage was evaluated using detailed sensitivity and uncertainty analyses of various key static and dynamic influencing parameters such as porosity, permeability, fluid composition, boundary flux, and flowing bottomhole pressure. Under various scenarios of condensate blockage, studies related to effectiveness and optimization of CO2 slug-size, soaking-time, and flowback rate are conducted. As prove of concept, it is observed that miscibility of CO2 in condensates, and near wellbore re-vaporization of accumulated liquids, are two of the main mechanisms of removing the condensate blockage. It is also concluded that CO2 is relatively more effective in removing near wellbore condensates as compared to far-field regions. Finally, based on various optimization analyses, a viable approach to adopt huff-n-puff CO2 injection scheme is suggested.
An Integrated Approach for Comprehensive Formation Evaluation in Mixed Lithologies using Source-Less Logging While Drilling and Advanced Cutting Analysis: A Case History
Authors: Taher Ahmed , Aki Ahmet , Zeriek Rachad
Published: November 2017

Accurate formation evaluation relies heavily on the quantification of rock matrix constituents. Rock mineralogy identification is commonly based on wireline spectroscopy measurements. Logging while drilling (LWD) techniques traditionally rely on density and neutron data to derive lithology. Historically, density and neutron tools that contain radioactive chemical sources were also the primary sensors used to determine porosity within the reservoir, which is a fundamental petrophysical attribute necessary to accurately quantify reserves. Although the potential irradiation and contamination risks associated with radioactive sources have always been known, the industry is now focusing toward reducing or eliminating their use, where possible.

The alternative source-less sensors for density and neutron tools, such as acoustic and nuclear magnetic resonance (NMR) measurements, were commonly used for porosity calculations. However, calculated porosities from acoustic measurements could contain significant errors arising from the uncertainty associated with the mineralogical composition. In addition, NMR porosity values can contain errors as a result of the effect of density and the hydrogen index of the hydrocarbons in place.

Advanced cutting analysis (ACA), either by X-ray fluorescence (XRF) and/or X-ray diffraction (XRD), provides an independent lithology from downhole tools. The lithology, matrix density, and slownesses computed from the minerals or directly measured by the XRD can, in turn, be used as input data for porosity calculations from sonic and/or NMR data. This helps to provide more accurate porosity measurements, as compared to the traditional calculated porosities, without using density and neutron tools. In addition, scanning electron microscopy (SEM) helps to enable the use of wellsite mineralogy, porosity, grain size distribution, and grain density from cuttings to calibrate the measurements from LWD acoustic and NMR tools.

This paper presents a comprehensive, cost effective method for multimineral formation evaluation using a combination of LWD and advanced mud logging, without the use of radioactive sources. A practical workflow with limitations is also presented.
Assessment of Field Scale Commercial Development for Miscible EOR in a Giant Offshore Carbonate Reservoir
Authors: Willingham Thomas W. , Kohata Akihiro , Al Sowaidi Alunood , Martin John D. , Irwin Drew D.
Published: November 2017

In this work we present the evaluation of field scale commercial miscible EOR for a giant offshore carbonate reservoir. The current assessment leverages the prior multi-year evaluation assessing the attractiveness (‘do-ability’) and prize for miscible EOR within each geologic area and reservoir within the field.

Two geologic areas, the "heterogeneous" and "homogeneous" geologic regions of the Crestal area in the largest reservoir were identified as the primary targets for field scale miscible EOR based on the prior multi-year assessment and are the focus of the current assessment. Commercial field-scale miscible development is predicated on a 1-to-1 line drive waterflood with 1km spaced extended reach horizontals with 10,000 ft completions and 500m spaced infills in the more heterogeneous area of the field.

Given the offshore environment, base development utilizes four artificial islands which support facilities for field development and serve as drilling centers. Commercial development with miscible EOR will be implemented in a ‘phased’ (staged) approach where the initial developments will be from the Central Island in the late 2030s followed in succession by the South Island in the early 2040s and North Island in the 2050s.

This assessment uses a novel phased approach where a ‘Tapered WAG’ scheme is used. By utilizing a phased (‘staged’) approach, multiple development concepts can be evaluated expediently. In this work we (i) show an efficient field assessment process for miscible EOR, (ii) illustrate how subsequent patterns can be brought on-line over time as part of a Tapered WAG process and (iii) demonstrate the importance of commercial assessment as part of field development planning and pilot assessment.

The full field assessments included here allows multiple development strategies to be assessed expediently and facilitates the selection of an injection solvent (hydrocarbon gas or CO2). Full field economics have been completed and hydrocarbon gas has been identified as the target solvent. Hydrocarbon gas has the benefit of being commercially attractive and is compatible with existing facilities. Currently two pilots are in preparation to assess the incremental recovery beyond waterflood and assess the commerciality of miscible EOR in a giant offshore carbonate reservoir. Key learnings in this paper include (i) an efficient methodology to assess phased field development for miscible EOR, (ii) incremental recovery of miscible EOR beyond waterflood, (iii) metallurgy and facility requirements for the two solvent schemes and (iv) a preliminary assessment of field scale commerciality including economics for the two solvents, hydrocarbon gas and CO2.
High-Power Mudhammer: A Promising Solution for Hard Formations Drilling
Authors: Souchal R. , Tarek M. , Gerbaud L.
Published: November 2017

A new percussion drilling system, combining a mud hammer with specific hammer drill bits, has been developed to increase drilling performances in hard formations. This system is based on a high-power down-the-hole hammer, capable of delivering high-energy impacts at high frequency. Weighted mud pressure is used as a power source, making it fully compatible with current drilling rigs and existing drilling procedures.

The hammer bits used are specifically designed depending on the formation properties and overburden pressure, using on a semi-empirical model developed from a large series of unitary and full-scale impact tests.

This system was tested extensively, using a full-scale drilling bench capable of accurately simulating deep downhole drilling conditions. Results showed significant performance gains over rotary techniques: ROP improvements from +100% to over +300% were obtained in different hard lithologies. The mud hammer and optimized 6″ bit were then used during a field trial to drill through a hard gneiss formation, increasing the ROP over roller cone bits fourfold, from 1.1 to 4.5 m/hr.
The Case for Requirement Management: How Industrial Design Requirements are Specified and Executed in the Oil Subsea Production Systems SPS vs. Shipbuilding Industries
Authors: Piciaccia Luca A.
Published: November 2017

None of the recent Floating Production Storage and Offloading Unit (FPSO) projects was delivered on time or on budget. This paper, part of a PhD in Systems Engineering at the Norwegian University of Science and Technology (NTNU), endeavors to make visible some Root Causes by comparing the design process in two industries enabling the upstream oil energy value chain, Subsea oil Production Systems (SPS) and shipbuilding. The comparison uses Systems Engineering concepts and techniques to illustrate the current practices and their reliance on different domain specific conventions.

Particular attention is given to possible commonalities and synergies in the design process to enable a more integrated approach to the industry needs. The purpose is to enable seamless requirement transfer between the user of the vessel and the shipbuilder.

The comparison of the two design processes is leveraging on the 25 years subsea oil production experience of the writer and the guidelines established by professor Stein Ove Erikstad at the Department of Marine Technology at NTNU in his course "Introduction to Marine Systems Design Models and Methods".
A Study on the Factors Affecting the Reliability of Laboratory-Measured Gas Permeability
Authors: Salahshoor Shadi , Fahes Mashhad
Published: November 2017

Laboratory measurements of gas permeability are used in many petroleum engineering studies, from core analysis for reservoir formation characterization to research work on reservoir engineering, formation damage, and various enhanced recovery techniques. The value of this data depends on how well they translate from one measurement condition to another. In this study, several factors affecting laboratory permeability measurements are investigated. Experimental results show that negligence of these factors may result in errors exceeding fifty percent.

Permeability measurements are performed for limestone and sandstone samples using a conventional steady-state technique. The effect of variations in core length, gas type, pressure of gas supply, and the flow rate and pressure of the flowing gas is systematically studied. An accurate mass flow meter for gas is built in-house to eliminate the calibration error of commercially available flow meters that depend on the gas type. Nitrogen, helium, and ethane are used in these measurements. Temperature variations of the flowing gas are recorded, and gas slippage and inertia effects are also taken into account.

Our study shows a significant reduction, bordering 25%, in permeability values measured for some shorter cores compared to the permeability value of the original whole core. This difference is more pronounced in highly permeable sandstone samples but is till significant in low permeability carbonates, bordering 20%. Permeability values measured using helium are higher than those measured using nitrogen. The difference is more pronounced in shorter cores, bordering 50%. It is important to note that this variation in permeability between nitrogen and helium exists even when corrections for the gas slippage or Klinkenberg effect are considered. Gas slippage effects are more pronounced for helium compared to nitrogen and for shorter samples compared to longer ones. The effect of length on the non-Darcy permeability and the high-velocity coefficient can also exceed 50% even when the same gas type is used. To the best of our knowledge, almost all laboratory permeability measurements neglect the temperature effect by considering an isothermal process. The effect of length on measured permeability is hinted in a few publications but no systematic study is reported. Our data show that models accounting for the effect of gas type are not accurate. We conclude that permeability measurements need to be corrected for the core length and flowing gas type effects, which vary with rock type and experimental conditions.
Risk Assessment for Groundwater Contamination from Hydraulic Fractured Shale to Aquifers
Authors: Li Weirong , Dong Zhenzhen , Wang Cai
Published: November 2017

Using hydraulic fracturing in shale gas and oil reservoirs to develop natural oil and gas has caused concern regarding the risk of groundwater contamination. Failed well casing, bulk media and fractures are three potential pathways that allow the transport of contaminants from the fractured shale to aquifers. Models built and simulated by CMG are used to investigate the potential risk of water contamination from hydraulic fractured shale to aquifers. This study focuses on the role of vertical fractures permeability/failing casing, aquifer permeability, reservoir permeability, distance between reservoir and aquifer, distance between fracture and water well in aquifer in controlling the contamination risk at environmentally sensitive locations.

The results show that risk strongly depends on well casing quality, initial water saturation, and fracture parameters. Furthermore, the measured risk value is more sensitive to leakage depth and leakage rate through well casing/permeable fracture when compared to the hydrogeological properties. The study shows that transport could require up to tens of thousands of years to move contaminants to the surface when well casing is integrity and without fractures/fault in the overburden layers, but also that fracking the shale could reduce that transport time to tens or hundreds of years. Conductive faults or fracture zones could reduce the travel time further. Well casing failure would reduce the travel time to months. The study identifies the important of well integrity for minimal risk to water contamination in fracturing, also the finding requires that monitoring systems be employed to track the movement of contaminants when fractures and faults appear in the overburden layers.
Simulator and Controller Tuning/Testing Rig for Artificial Gas Lift
Authors: Matraji Imad , Wang Weiliang , Boiko Igor , Al-Durra Ahmed , Abushawish Ibrahim Y.
Published: November 2017

Artificial Gas Lift (AGL) technology is used in mature oil wells to increase the oil production rate. Improper control of this system can produce casing heading instability resulting in slug flow and problems in downstream equipment. The AGL system has very complex nonlinear dynamics, which makes the tuning of the controller parameters difficult on a real system. In this paper, an AGL simulator is developed to test and tune the controllers before installation in the field. The simulator uses the concept of Hardware-In-the-Loop (HIL) which emulates the real behavior of gas lift system and connects to a Programmable Logic Controller (PLC) or Distributed Control System (DCS) to design and optimize control algorithms. The AGL simulator uses accurate model and high performance processing. It is equipped with a Human Machine Interface (HMI), which displays the status of AGL system using animation and trending so that slugging can be easily identified. The HIL can be operated in two modes: real time and accelerated time. An example of control tuning method using Modified Relay Feedback Test (MRFT) is used to demonstrate controller gain tuning in accelerated mode, based on its performance on the AGL simulator. The proposed HIL simulator can prove to be a convenient practical tool used for testing automation solutions before connecting them to real gas lift process in the field.
Unlocking Egypt’s Unconventional Potential
Authors: Zaher Amr , Loubens Etienne , Zayed Mohamed , Gill Nicholas , Sadhu Oneil , El Hares Layla
Published: November 2017

The objective of this paper is to discuss the journey of developing the first unconventional gas opportunity in Egypt. The transformation of the development concept through successful appraisal and pilot phases will be discussed, emphasizing the key learnings and outcomes from the first pilot project including a horizontal well with a multi-stage hydraulic frac. The integration of the early results from the pilot into some stochastic techniques to evaluate a range of EUR/well and range of production forecasts will also be discussed.

The Apollonia gas-bearing chalky carbonate reservoir has been appraised by 6 vertical wells. Initial attempts to evaluate Apollonia reservoir potential have relied on either natural flow or relatively small scale propped sand frac jobs with limited success. In early 2012, foam fraccing was performed to improve well productivity and ultimately project economics. Whilst significant productivity improvement was observed, the higher production rates could not be sustained.

The key uncertainties were establishing a reliable long term production profile and achieving sustainable production flow to make the development commercially viable. Estimated well ultimate recoveries from vertical wells are uneconomic. An alternative well concept was therefore required that could deliver an economical development.

A pilot phase was designed in 2015 to deploy and test 3 long reach horizontal wells, stimulated with multi-stage hydraulic fracs. Two pilot wells were drilled in 2016 and currently in production with a data acquisition program in place to determine the technical viability and commerciality. Learnings from the 2 pilot wells are being assessed to optimse the design concept for the planned 3rd pilot well.