bluuebunny/crossref_metadata_2025 huggingface dataset:
Design of Cone-Launcher System for SET Applications in Well Drilling
Authors: Al-Abri Omar S.
Published: June 2014

Due to the continued forecast of increasing energy demand, oil in particular, it is expected that oil companies will intensify their efforts in meeting the global demand. Drilling deep and accessing difficult reservoirs are already posing serious challenges to local, regional and international players in this business. A part from this, there is a continuous push on performance improvement, cost reduction and innovating new techniques/tools/ procedures to push toward realizing the dream of having mono-bore diameter well. Solid Expandable Tubular (SET) Technology has already made significant inroads in resolving these challenges. Various operators around the world are already using the technology towards zonal isolation, repairing ageing wells to have profitable production, etc. Numerous experimental, numerical and analytical works have been reported in literature related to solid expandable tubular. The recently designed and commissioned expandable tubular test-rig in Sultan Qaboos University - Oman - has helped local operators to use the technology with confidence as well as to search for low cost expandable solutions. Still many issues are either not understood at all or have very little understanding about it. These include post expansion mechanical characterization, lowering the cost of expandable tubular, simplify the expansion operation and cost either through the design of optimal tools or reducing the number of steps needed in an expansion process.

The students at Sultan Qaboos University were actively involved in many expansion related works in Engineering Research Laboratory. However, the students have never made an attempet to complete the question of having own indigenously design cone and launcher system. The task of designing a new cone and launcher system which can be effectively and efficiently used in down-hole applications was initiated last year. In Oman, there is no such in-house developed design to deliver this work. It will be nice to have one's own design, which with time can be improved. In view of this, the objective of this work was set to design a Cone and Launcher System for SET applications. A design was proposed to expand the tubular in a stroke of 2-ft length. Multiple strokes can be done in one cycle of operation. 7⅝" tubular system was selected for this specific task. The design work was done from component to sub-system to product level either analytically or numerically using finite element method. The constraints of cost and ease of manufacturing locally were prime concern during the design work. The working of proposed system has been simulated in SolidWorks software to demonstrate its operation.
An Easy to Use Well Design Software Package for Educational Training
Authors: Dalamarinis Panagiotis
Published: June 2014

One of the biggest challenges in teaching well and drilling design to undergraduate and graduate students is availability of easy to use and understand software simulator programs. Hence a design package is needed for educational use which will not only introduce well design principles but also could be a support package for more advanced drilling programs (like for e.g. Payzone, Petris).

In this paper such a program is presented which has six major parts:

Hydraulics calculations for flow of non-Newtonian fluids in pipe and annuli, pressure losses in drill pipe and annulus, at the bit, considering well geometry, eccentricity and pipe rotation. Bit optimization, specific maximum pump pressure for maximum bit hydraulic horsepower or maximum jet impact force. Mud Cap technique design, with analytic design for parts of the well bore, aiming to introduce the Managed Pressure Design for a well. Pipe design, offering a stress design analysis for the selection of drill pipes. Casing design, making a stress design for the casing at each part of the well Directional drilling calculations for the support of Payzone drilling program.

We present the components and the interface, developed in Matlab environment, together with instructions for use.

The results of this work is a well and drilling design software package for training undergraduate and graduate students, easy to understand, while allowing fairly complex computations.

Technical Contributions: Easy to use, not heavy, yet fairly accurate simulator built in Matlab environment, allowing teaching important drilling concepts such as hydraulic calculations along the wellbore, bit optimization, pipe and casing design, introduction of mud cap drilling technique, and ability to perform computations for directional drilling.

Relevant Applications: The developed program can be used in undergraduate and graduate classes and in not-very-technical training programs, for teaching important aspects of drilling engineering.
The Past, Present and Future of Aphron Based Drilling Fluids
Authors: He Xiaoqing
Published: June 2014

Aphron based drilling fluid is an advanced technology which has been successfully developed for ten years in petroleum drilling industry. This paper firstly summarizes the field applications and laboratory study of aphron based drilling fluid of the past ten years. Then it describes undergoing researches in China, which include the foundation of aphron's structure model, explanation of special properties of aphron based drilling fluid and its sealing mechanism, agents selection method, the way of making typical useful formulas, and field applications in China. At last, the author predicts the potential and expanded use of aphron in petroleum industry in the future.
Characterization of the Horizontal Intermittent Air-Water Flow Using Ultrasound Technique Aided by High-Speed Filming
Authors: Grangeiro Fernando Antonio
Published: June 2014

Two-phase flow is very common in petroleum industry. During off-shore production, liquid and gas phases travel long distances through flow-lines and risers before being separated at different flow patterns. In the present work, air-water horizontal slug flow hydrodynamic parameters are investigated using ultrasound technology aided by high speed filming. The test rig is composed by a 54mm inner diameter acrylic pipe where two stations composed of four ultrasonic transducers each were placed. The parameters obtained were: elongated bubble velocity; elongated bubble, liquid slug and unit cell lengths, and unit cell frequency. These parameters made it possible to calculate flow rates of both phases using the ultrasound technique. Results shown by both techniques agreed against each other.
Appraisal Strategy for a Tight Gas Discovery
Authors: Al Kindi Suleiman , Weissenback Markus , Mahruqi Sultan , Curtino Joe , Al Siyabi Hisham
Published: June 2014

Exploring and developing tight gas accumulations are both technically & commercially challenging due to the large subsurface uncertainty and low expected ultimate recovery (EUR) per well. In this paper, the appraisal phase of a tight gas discovery is described in three parts.

The first part highlights the main geological uncertainties associated with rock properties for tight sands with porosity as low as 5% and permeability of few tens to hundreds of microDarcy. As a consequence, free fluid contracts for such accumulations are difficult to pinpoint using conventional petrophysical analysis of open logs and due to the lack of reliable fluid pressure data. Tight gas accumulations are known to be associated with large gas-to-water transition zones, leading to much broader and uncertain estimates of the gas resources. This in turn adds to the complexity in identifying and planning development options for such discoveries.

The second part describes some new technologies adapted to narrow down the subsurface uncertainties and to speed up the appraisal phase of a tight gas accumulation. Such technologies include: under-balanced drilling (UBD), high resolution gas chromatography measured at drilling site, special core analysis and dedicated petrophysical evaluation for tight sands. In addition, new technologies related to seismic imaging and fracc optimisation are also considered with the ultimate aim of improving gas production rates and EUR per well.

The last part of the paper describes the underlying strategy in maturing a tight gas discovery into field development. The strategy in principle has three main elements: 1) narrowing down the subsurface uncertainty; 2) reducing well cost; and 3) improving expected ultimate recovery per well. The campaign takes advantage of the ongoing development of nearby gas fields that provides the opportunity for hooking up appraisal wells at an early stage for extended well test. This appraisal plan is managed and executed by a dedicated and well-integrated multi-disciplinary team.
Integrated Drilling-Maximize Land Well Drilling Efficiency
Authors: Farooqui Shoaib , Hafeez Iftikhar , Ahmed Sumair , Ahmed Faizan , Siddiqui Ibad , Attaullah Hammad
Published: June 2014

In conventional drilling scenario, the Drilling Manager has to deal with similar drilling problems several times during field development phase. In addition to this he has to manage several service providers which results in increased workload. This increased workload prevents him to focus on the solutions of drilling problem & drilling optimization.

Integrated Drilling Services is a new concept in which all services and equipments are integrated under one contract. It is a contractual model which is technically and economically feasible with efficient risk management. This model reduces non productive time and non conformances with efficient project management and Technology Advancements in order to encourage Drilling Managers “Doing Right Things” rather than “Doing Things Right”.

This paper describes an engineering approach towards well optimization and efficient project management. Moreover, economic benefits are also the part of study.
Kick Detection and Well Control in a Closed Wellbore
Authors: Nas Steve
Published: June 2014

Closing the wellbore at the top with a Rotating Control Device (RCD) for some kind of Managed Pressure Drilling (MPD) operations raises a number of issues with regards to well control and kick detection. The wellbore is closed and the standard flow check of looking into the well is no longer possible. The use of a rotating control device provides drillers with an additional level of comfort because it is a pressure management device, but it doesn’t eliminate the need to have well control as a primary objective. In recent MPD operations, it was observed that well control procedures were relaxed as a result of managed pressure drilling. The installation of an MPD system provides the sense that well control is now taken care of by the MPD provider. This raises the question "Is Managed Pressure Drilling the same as primary well control?", and how do we deal with kicks in Managed Pressure Drilling operations? At what point in a well control process do we change the well from Managed Pressure Drilling to well control and who is responsible?

This paper will present some of the issues that need to be considered when planning and conducting MPD operations. arly kick detection and annular pressure control are promoted as an essential part of managed pressure drilling operations, but there can be confusion as to where the responsibility for well control lies. Does this remain with the drilling contractor and Operator or is this now shifted to the provider of the MPD services. The paper provides some case stu ies where MPD and well control conflicted, causing a number of issues that in some cases led to the loss of the well.
Comprehensive Study of Asphaltene Precipitation due to Gas Injection: Experimental Investigation and modeling
Authors: Zadeh Gholam Abbas , Moradi Siyamak , Dabir Bahram , Emadi Mohammad Ali , Rashtchian Davood
Published: June 2014

Asphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. In this work, static precipitation tests are conducted to investigate effect of pressure, temperature and gas type and concentration on asphaltene instability. Three different oil samples are studied under reservoir conditions with/without nitrogen and methane injection. Besides applying common thermodynamic models, a new scaling equation is presented to predict asphaltene precipitation under HPHT gas injection. Published data from literature are also used in model development. The scaling approach is attractive because it is simple and complex asphaltene properties are not involved in the calculations. Moreover, the proposed model provides universal parameters for different fluid samples in a wide range of pressure and temperature that makes it novel for evaluation of future gas injection projects when simple PVT data are available.
i-field™ Programs Enable Operational Excellence in a Challenging Environment—Pushing the Limits of Large Data Transfer for Real-Time Monitoring and Surveillance Operations in the San Joaquin Valley
Authors: Popa Andrei , Cassidy Steve
Published: June 2014

Chevron's San Joaquin Valley (SJV) Business Unit (BU) is a mature, heavy-oil, thermally enhanced asset consisting of large fields that have been producing for more than a century. To ensure continuing technology transformation, in 2003 SJV started its own i-field program, being among the first BUs to pursue Chevron's enterprisewide effort in building the Digital Oil Field of the Future. From its initiation, the program has been focusing on creating solutions to manage and optimize operations and enhance recovery.

This paper showcases one of the most technologically advanced i-field heavy-oil solutions implemented in SJV thermal assets, involving a high-accuracy-tiltmeter program implemented by a partner service company to advance the understanding of diatomite operations and monitor the surface ground movement.

In 2008, Chevron's SJV i-field team partnered with its Information Technology (IT) department to develop a state-of-the-art application called Integrated Diatomite Operations Tool (i-DOT). The product incorporated current field workflows for mapping the grid deformation with business data (well locations and status, steam volumes and dates) in relevant time. This was accomplished by establishing a live connection between Chevron and partner-service-company servers whereby terabytes of grid data would flow seamlessly into Chevron's SJV servers. Data-acquisition, data-processing, and data-storage efforts were accomplished through an integrated effort between IT, geographical information system (GIS), and PetroWeb development teams. Workflows were built through close collaboration between i-field engineers, petroleum engineers, earth scientists, IT professionals, and the operations group.

The i-DOT solution has become the single point of operation monitoring and activity scheduling for multiple groups such as Operations, Asset Development, and the Drilling team. The benefits of implementing i-DOT solutions are significant and transformed our decision-making process in diatomite fields. This paper includes not only value creation but also lessons learned during development, deployment, and end-user acceptance.
Implementing i-field-Integrated Solutions for Reservoir Management: A San Joaquin Valley Case Study
Authors: Popa A.. , Cassidy S..
Published: June 2014

To achieve more-efficient business processes by exploiting data and knowledge management, real-time systems, and advanced analytical tools, most major integrated and service companies have developed, or are in the process of developing, intelligent programs also known as "Digital Oil Field of the Future" (CERA 2002). The i-field™ program represents Chevron's efforts to integrate people, processes, technology, and information to achieve its vision of upstream transformation. Ultimately, this vision translates to higher-quality decision making and changes the method in which assets are operated.

A new multiyear i-field™ program, Integrated Reservoir Management (i-RM), was initiated in the San Joaquin Valley (SJV) to enable efficient reservoir management (RM) and quality decision making for heavy-oil assests operating under steamflood enhanced-oil-recovery (EOR) technologies.

The paper describes the journey undertaken by the project team to build a proprietary steamflood-integrated RM tool that answers the basic never-ending engineering requirements: instant access to clean data, single source of information for everyone, and seamless data-tools linkage. The ultimate benefit is not only increased time spent by engineers and earth scientists to analyze data, but also consistent project design workflows and decision-making processes across fields. In addition to the previously described documented benefits, the manuscript includes the operator's experience with project framing, development, deployment, and user acceptance.
Innovative Use of Open-Hole Wireline Formation Pressure Testing in Waterflood Optimization of an Ultra-Tight, Light Oil Reservoir, Belridge Field
Authors: Zannitto P. J. , Rahman M. , Allan M. E.
Published: June 2014

There are not many oil reservoirs in the world with permeabilities less than 1 md that are under waterflood. Aera Energy's Diatomite reservoir at Belridge field in California is one of the few: a massively thick reservoir, with very low permeability, very high porosity, and high rock compressibility that has been undergoing water injection for pressure maintenance for over 20 years.

Optimizing subsurface injection conformance, or injection profile, is the key to operating a successful waterflood in the Diatomite. However, because of wellbore obstructions, the majority of Diatomite injectors are not accessible to conventional radioactive tracer tools for monitoring injection profile. Without a good understanding of vertical profile, it is difficult to balance voidage on a layer by layer basis. Failure to maintain good zonal pressure support can result in poor vertical sweep, as well as reservoir compaction that can lead to irreversible permeability reduction and productivity impairment.

Due to reservoir compaction and elevated rate of well failures, sustaining Diatomite production requires continuous drilling of replacement and infill wells at very close well spacing (20–50 ft). Aggressive replacement drilling programs (300 wells per year) have made it possible to run open-hole Wireline Formation Tests (WFT) in sufficient density over time to effectively monitor vertical and areal pressure profiles. As a result, reservoir intervals lacking injection support have been identified for optimization.

Between 2003 and 2008, Aera ran over 300 open-hole WFT surveys in the South Grande area at Belridge field, vertically covering the Opal-A and upper Opal-CT reservoirs. Large-scale pressure testing has aided in pressure maintenance operations by improving completion strategy in new injection strings, targeting differentially depleted zones. This has improved overall layer voidage profiles, as evidenced by lower producing GOR and greatly reduced occurrence of producer-failures. WFT surveys continue to serve in a feedback loop to optimize injection target setting, voidage management, and strategy for completing replacement wells.

This paper reports on the innovative use of wireline formation testing to optimize water injection pressure maintenance in a major onshore waterflood, with the unique challenge of not being able to monitor injection profile in a majority of wells. The learning may apply to other tight, light oil waterfloods.
The Next Opportunity To Improve Hydraulic-Fracture Stimulation
Authors: Vincent M.C.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Abstract

Forty years ago, most people in our industry would have claimed that producing economic flow rates from nanodarcy formations was simply impossible. Thirty years ago, tax incentives were introduced by the US Congress to encourage drilling of ’unconventional’ tight gas reservoirs in which the permeability was near 0.1 md. Today, our industry is voluntarily drilling into formations that are 1/1,000 as permeable, and making tremendously profitable wells! The technology that facilitated this ’impossible’ feat is hydraulic fracturing-specifically, the opportunity to initiate multiple transverse fractures from horizontal wells.

While hydraulic stimulation has provided tremendous advances in our ability to develop lower-permeability resources, the corresponding challenges have not been addressed fully. This article summarizes one perspective on future opportunities that will allow even more-thorough and more-cost-effective recovery of hydrocarbons from tight reservoirs.

Reservoir Contact

In highly permeable formations, conventional wells may be completed without stimulation. The borehole and perforations provide sufficient reservoir contact to achieve profitable hydrocarbon production. However, more than 90% of the wells currently drilled in North America require fracture stimulation to recover reserves from low-permeability formations at economical rates. Hydraulic fracturing involves pumping a fluid at sufficiently high rates and pressures to extend cracks into the formation surrounding the wellbore. Granular materials are injected to prop the created fissures open to delay their collapse. These created fractures can increase the contact between the wellbore and reservoir dramatically and are the key that has unlocked tremendous hydrocarbon resources contained in tight formations.
Effect of Surfactant Partitioning Between CO2 and Water on CO2 Mobility Control in Hydrocarbon Reservoirs
Authors: Ren Guangwei , Zhang Hang , Nguyen Quoc P.
Published: June 2014

This paper presents a systematic study of the effect of surfactant partitioning between supercritical CO2 and water on surfactant transport and foam propagation during two-phase flow. A series of corefloods were conducted on Silurian dolomite cores with different non-ionic and anionic surfactants that represent respective wide ranges of partition coefficients and solubility in supercritical CO2. Foam robustness and displacement efficiency were related to these surfactant properties. Coreflood results and all measured surfactant properties were used in a commercial reservoir simulator to determine the variation of surfactant partitioning effect from laboratory to field scale. Optimization of surfactant partition coefficient for field-scale foam process was performed with different injection strategies.

The results from this study enable us to tailor properties of CO2 soluble surfactants (i.e. partition coefficient) to a wide range of reservoir conditions and optimal injection strategies. The understanding of surfactant partitioning effect is also important in overcoming technical challenges encountered in the injection of surfactant in CO2.

The partition between CO2 and water phases was much more sensitive to surfactant structure than temperature and pressure. Strong foam development was observed for all non-ionic and anionic surfactants while an increase in surfactant partition coefficient lowers the rate of foam propagation. Field-scale foam simulations indicate that foam performance and surfactant transport was governed not only by constrained injection strategies, but also surfactant partition coefficient. For a given injection strategy, the latter could be optimized to improve injectivity and sweep efficiency.

The optimal partition of the surfactant between the CO2 and aqueous phases minimize wasting expensive surfactant in water that is never contacted with CO2. This novel CO2 soluble surfactant concept diversifies injection strategies with respect to operational constraints, broadening the application of foam process.
Applications of Accurate In-Situ Fluid Analysis in the North Sea
Authors: Achourov Vladislav , Gisolf Adriaan , Kansy Andreas , Eriksen Kåre Otto , O'Keefe Michael , Pfeiffer Thomas
Published: June 2014

As we strive to complete more complex reservoirs, we are challenged to better understand the nature of the fluids contained within. In the North Sea, classical "black oils" are still encountered; however scenarios where volatile fluids that exhibit a bubble point are found in close proximity to fluids with dew points are not uncommon. In addition, knowing the CO2 content is paramount to completion engineering and facility design with high penalties incurred when CO2 quotas or production limits are exceeded.

Characterizing these fluids is difficult. Typically wireline formation testers with fluid analyzers are used for early fluid characterization and sampling. However, with the increasing fluid complexity subtle differences need to be understood. This requires comprehensive compositional analysis, high resolution answers and quantified accuracy.

This paper describes the technology and answers provided by an accurate in-situ fluid analyzer. Several case studies are discussed. In the first example oil is sampled from two depths, only a few meters apart. The in-situ fluid analysis data from these two depth, including C1, C2, C3-C5, C6+ CO2, GOR and density are compared, indicating excellent tool resolution. In addition these data are compared to laboratory sample analysis result with observed differences falling well within the quoted tool accuracies. A second example involves several closely stacked reservoirs. An in-situ compositional analysis was obtained for each reservoir fluid. By changing the flow rate of the formation tester downhole pump the flowing pressure was manipulated. This allowed to measure different ranges of bubble point pressures for each fluid. Only a few meters below a second fluid exhibiting a dew point was encountered. An indication of the fluid dew point pressure was detected by again manipulating the flowing pressure. Fluid analysis revealed compartmentalization and fluid grading through the different reservoirs in this well.
The Cumulative Risk Assessment Barrier Model
Authors: Blacklaw Alan , Ward Al , Cassidy Kevin
Published: June 2014

Description

The Cumulative Risk Assessment Barrier model – a methodology that simply demonstrates performance against Safety Critical Barriers and communicates key risks in basic terms to workforce and management.

Application

The Cumulative Risk Assessment Barrier Model has been used within BG Group’s UK Upstream asset as a highly effective and visual communication and decision-making tool for the past 18 months.

This tool has been further enhanced and automated with the introduction of Barrier Model Dashboard. This has enabled a more detailed, accurate and interactive approach to cumulative risk management.

The Barrier Model Dashboard links to live data from the Permit to Work (PTW) and Computerised Maintenance Management System (CMMS). Information is extracted from PTW and CMMS on key risk areas including: initial risk from impaired systems and systems where maintenance is overdue;residual risk from these systems after mitigation measures have been taken into account; andsafety-critical element reliability information (providing information on the statistical likelihood of hidden failures and the potential for systems to fail when called upon in an emergency).

This data is combined to provide a traffic-lighted risk profile for each installation, based on the series of barriers in place to prevent Major Accident Hazard events and prevent their escalation.

Results, Observations, Conclusions

The interactive display provides visual cues for operations and maintenance teams whilst providing real time information on the safety of continued operation. This enables clear understanding of risks and provides prioritisation on the remedial works that will have the greatest impact on reduction of cumulative risk. Local teams can ‘zoom’ into specific locations within a site, while management teams can get an overview of the status across multiple sites and can trend cumulative risk profiles over time.

Significance of Subject Matter

The tool is of significance industry-wide as it provides transparent measures based on collected corporate system data which is then merged with "soft" measures such as the human/environmental elements, all of which are collected, clearly presented, and stored. The information is updated on a daily basis and provides up-to-the minute, accurate information.
Intelligent Exploration and Appraisal Program for a Multiprospect Development
Authors: Delfiner Pierre
Published: June 2014

While many companies are hunting for elephants, exploration results in deep offshore plays over the past years show the increasing trend away from giant-field discoveries toward smaller fields in the 50-100 million bbl range, which tend to be geographically dispersed. These resources need to accumulate to a critical mass, a global threshold, to justify an economically viable development. This is not only a question of volume but also of geographic location of the discoveries, and the threshold, of course, also depends on economic factors.

A methodology is proposed to evaluate the potential of a block to lead to a multiprospect development and to optimize exploration and appraisal. It is illustrated by a real deepwater case study including five discoveries and four prospects, 10-30 km apart. The practical approach taken is to define circles or ellipses on a map representing potential hubs and their catchment areas. For each area, a global resource threshold is defined by analogy with other regional developments or by a detailed economic study of representative cases (not discussed in the paper).

A probabilistic model of the resource base is derived from the geological assessments of discoveries and prospects. It is entered into Monte Carlo simulation to generate a large number of scenarios representing exploration outcomes and discovery volumes, which are stored in a scenario database. This allows a probabilistic evaluation of the performance of an exploration and appraisal program, using specially developed indicators such as the cumulative discovered P50. Intelligence is introduced in the process by evaluating after each well the probability of meeting the threshold with the remaining wells. If it is low (10% or less) the program is stopped, which has a great impact on risked economics.

The main results of the analysis are the economic decision tree with the probability of a development decision and the P90/ P50/P10 of the developed resources; the number of wells in the dry branch of the tree, which actually is not a fixed number but a probability distribution; the definition of a firm and contingent well program; and an optimum drilling order, which may also reduce the well count.
Lattice Boltzmann Simulation of Non-Darcy Flow In Stochastically Generated 2D Porous Media Geometries
Authors: Newman M.S.. S. , Yin X..
Published: June 2014

It is important to consider the additional pressure drops associated with non-Darcy flows in the near-wellbore region of conventional gas reservoirs and in propped hydraulic fractures. These pressure drops are usually described by the Forchheimer equation, in which the deviation from the Darcy's law is proportional to the inertial resistance factor (β-factor). While the β-factor is regarded as a property of porous media, detailed study on the effect of pore geometry has not been performed. This study characterized the effect of geometry on the flow transition and the β-factor using lattice Boltzmann simulations and stochastically constructed 2D porous media models. The effect of geometry was identified from a large set of data within a porosity range of 8–35%. It was observed that the contrast between pore throat and pore body triggers an early transition to non-Darcy flows. Following a quick transition where the correction to the Darcy's law was cubic in velocity, the flows entered the Forchheimer regime. The β-factor increased with decreasing porosity or an increasing level of heterogeneity. Inspection of flow patterns revealed both steady vortices and onset of unsteady motions in the Forchheimer regime. The latter correlated well with published points-of-transition. In developing a dimensionally consistent correlation for the β-factor, we show that it is necessary to include two distinctive characteristic lengths to account for the effect of pore-scale heterogeneity. This finding reflects the fact that it is the contrast between pore bodies and throats that dictates the flow properties of many porous media. In this study, we used the square root of the permeability and the fluid-solid contact length as the two characteristic lengths.
Removing Formation Damage and Stimulation of Deep Illitic-Sandstone Reservoirs Using Green Fluids
Authors: Mahmoud M. A. , Nasr-El-Din H. A , DeWolf C. A.
Published: June 2014

Illitic-sandstone reservoirs are very sensitive to HCl-based fluids. When HCl contacts illitic-sandstone it breaks down and causes fines migration and formation damage. The migration of fines through the porous media will block the pores, reduce permeability and decrease the production rate of oil and gas wells. Literature showed that all clay minerals are essentially unstable in HCl at temperatures greater than 300 °F. In turn, there is an essential need to look for stimulation fluids other than HCl to stimulate deep sandstone reservoirs.

Alternative fluids to HCl/HF mud acids were introduced to stimulate and remove the damage from illitic-sandstone reservoirs. These fluids are chelating agents such as EDTA (ethylene diamine tetraacetic acid), HEDTA (hydroxyl ethylene diaminetriacetic acid), and GLDA (glutamic acid-N, N-diacetic acid). In this study, sandstone cores with different illite contents were examined. Illite content of 1, 10, 14, and 18 wt% of the sandstone cores were used in the coreflood experiments at 300 °F. Different combinations of GLDA/HF were tested to determine the optimum ratio of GLDA/HF. CT scan and permeability measurements before and after the treatment were used to assess the effectiveness of each fluid in removing the damage and stimulation of sandstone cores.

Our results showed that 15 wt% HCl caused severe damage to sandstone cores with different illite contents. GLDA, HEDTA, and EDTA showed a good compatibility with the illitic-sandstone cores at 300 °F. Permeability measurements and CT scan results showed that GLDA performed better than HEDTA and EDTA at pH of 4. The optimum ratio of GLDA/HF concentration was found to be 20 wt% GLDA/1 wt% HF, which gives the maximum increase in core permeability. The three fluids tested in this study showed good compatibility with illite. They can be used to stimulate illitic-sandstone reservoirs alone or in combination with HF acid. GLDA was found to be compatible with the sandstone cores that contained up to 18 wt%. No sands deconsolidation was noted with any of the three fluids. The results obtained from this study will significantly improve the outcome of acid treatments in illitic-sandstone reservoirs at high temperatures.
Developing Oil in Monobore Well Completion Using Permanent Coil Tubing Gas Lift Application
Authors: Kramadibrata Ari Taufiq , Sumaryanto Sumaryanto , Panjaitan Pahala
Published: June 2014

VICO Indonesia has operated the Sanga-Sanga PSC in East Kalimantan, Indonesia, since 1968. More than 750 development wells have been drilled to date in the complex Mahakam Delta in East Kalimantan. The mature reservoirs are predominantly gas, extremely depleted and have an average recovery factor of about 70%. To optimize the development cost VICO changed the completion from multi string and multi packers to monobore in 1997 and furthermore to dual monobore in 2005. VICO has also focus to optimize oil production and recovery. The current oil recovery factor is relatively modest and needing further detail study and optimization.

A multi-disciplinary team was performed to further evaluate oil potential in all VICO fields including review of historical performance, geology and development opportunities. These reservoirs were also evaluated using material balance to understand the initial volumes in place, the drive mechanism and the opportunity to maximize production and oil recovery through the existing wells.

One of the challenges in maximizing oil recovery is artificial lift system in monobore completion. VICO has evaluated and selected gas lift as optimum artificial lift method. There are two possibilities to gas lift oil wells (1) using a side pocket mandrel in the conventional dual string completion and (2) inject gas lift through coil tubing in the monobore completion.

The paper describes innovative gas lift system in monobore completion where gas lift mandrels were not pre-installed. This technique has been implemented, by running 1.5" coil tubing into a well through a special tubing hanger attached to the top of the Christmas tree. This technique allows gas lift to an oil reservoir in monobore well completion without requiring rig for recompletion. This application is known as "Permanent Coil Tubing Gas Lift" or PCTGL. This technique has been implemented in "MUT-X" well that was not capable to flow naturally, and then PCTGL was installed to resume oil production. The well was flowing 600 BOPD initially and now is continue flowing at 350 BOPD.

In summary, PCTGL is a proven favorable and simple method for artificial lift application in monobore completion to maximize oil production and recovery. Furthermore, this technique has helped VICO in synergizing gas and oil development to maximize value of the assets.
Optimization of Equity Redeterminations Through Fit-for-Purpose Evaluation Procedures
Authors: Worthington Paul F.
Published: June 2014

Equity redetermination is most commonly encountered where a straddling field is developed as a discrete entity through a process of unitization. It is enacted through evaluation procedures that prescribe the technical methodology for requantifying different license shares, or tract participations, in a field unit as more data become available. The formulation of these procedures usually takes place at unitization, it is based on appraisal data, and, therefore, it is guided by simplified perceptions of reservoir character. For this reason, many such technical procedures have been found to be lacking when they are applied later at the equity redetermination stage. These shortcomings can take the form of ambiguous wording, misleading definitions, technically inappropriate specifications, contradictory prescription, or simply a lack of sufficient detail to render the intended process meaningful. They have impeded the determination of revised tract participations by triggering interlicense disagreements that might otherwise have been avoided.

With the objective of reducing this unhelpful impact, experience of redetermination situations is used to illustrate the nature and consequences of poorly constructed procedures for the recomputation of tract participations. The analysis is then flipped to generate a framework of key elements of technical procedures together with indications of how they are best implemented. These matters form the basis for a high-level set of protocols for a more efficient and effective redetermination of equity that would avoid the previously encountered shortcomings. The protocols encompass the proper incorporation of data character, a sound technical basis for redetermination, a balance between under- and over-prescription, an auditable deterministic ethos, and adherence to good international petroleum practice. They constitute recommendations for a better approach to the compilation of fit-for-purpose evaluation procedures within those unitization agreements that make provision for a future redetermination of equity. The recommendations are equally applicable to domestic and international unitizations. The principal benefit lies in an enhanced efficiency of the equity-redetermination process, which feeds through to a greater collective asset value.
A New Approach To Simulate the Boundary Layer in the Vapour Extraction Process
Authors: Nourozieh Hossein , Kariznovi Mohammad , Abedi Jalal , Chen Zhangxing John
Published: June 2014

The vapour extraction (VAPEX) process, as a nonthermal process, may be suitable for the recovery of heavy oil and bitumen. In this process, the injected solvent diffuses into the heavy oil/bitumen, reduces its viscosity, and drains it to the producing well. The VAPEX process is more acceptable than other processes because of its environmental friendliness, low capital and operating costs, and suitability for thin reservoirs.

Most of the efforts in the modelling of the VAPEX process have concentrated on the application of fluid-flow equations to the solvent and the diluted oil inside each gridblock used in the simulation of the VAPEX. This is adequate when very fine gridblocks are chosen to simulate the process in which the boundary layer (transition zone) occurs over a number of gridblocks. Fine gridblocks, however, require a large amount of simulation time, which is not applicable for field-scale simulation even with today's computing power. To deal with this problem, a new approach is introduced that is based on the application of the fluid-flow equations to three phases: solvent, diluted oil, and heavy oil/bitumen. With this approach, it becomes possible to have mobile solvent, mobile live oil, and immobile or slow-moving heavy oil/bitumen inside a gridblock. The main feature of the proposed model is its ability to capture the boundary layer within a gridblock, making very fine gridblocks unnecessary in the simulation of the VAPEX process. In addition, this approach can be applied to model the viscous fingering inside gridblocks.
Global Unconventional Gas Resource Assessment
Authors: Dong Z.. , Holditch S.A.. A. , McVay D.A.. A. , Ayers W.B.. B.
Published: June 2014

Most estimates of the resource endowment [original gas in place (OGIP)] reported for world unconventional gas start with Rogner's top-down study (Rogner 1997). That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The data from these new reservoirs add substantially to our understanding of the unconventional resource base. Furthermore, the uncertainty of Rogner's assessment was not quantified. Thus, considering the uncertainty, a new assessment of original unconventional gas in place worldwide is needed.

The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight-sand, and shale reservoirs worldwide. To accomplish this objective, we reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight-sands gas, and shale gas] and the conventional hydrocarbon (coal, conventional gas, and oil) resource endowments for North America. Then, we used this relationship to extrapolate original unconventional gas in place worldwide. Our assessment of the world resource endowment established an unconventional OGIP of 83,400 Tcf (P10) to 184,200 Tcf (P90), which is 2.6 to 5.7 times greater than Rogner's estimate of 32,600 Tcf.

Our regional assessments of unconventional OGIP should help industry better target its efforts to rapidly accelerate the development of unconventional gas resources worldwide. The methodology used to assess the distribution of each type of unconventional OGIP may be used to estimate unconventional gas resources at the country or basin level, given knowledge of the coal in place and technically recoverable resources of conventional hydrocarbons.
The ABCs of In-Situ-Combustion Simulations: From Laboratory Experiments to Field Scale
Authors: Gutiérrez Dubert , Moore R. Gordon , Ursenbach Matthew G. , Mehta Sudarshan A.
Published: June 2014

Air-injection-based recovery processes are receiving increased interest because of their high recovery potentials and applicability to a wide range of reservoirs. However, most operators require a certain level of confidence in the potential recovery from these (or any) processes before committing resources, which can be achieved with the use of numerical reservoir simulation.

In a previous paper, (Gutiérrez et al. 2009) it was proposed that after successful laboratory testing, analytical calculations and semiquantitative simulation models would be used for pilot design and further optimization of the actual operation. However, the specific steps for building the field-scale-simulation models were not addressed explicitly. This paper discusses a detailed workflow that can be followed to engineer an air-injection project using thermal reservoir simulation.

The first step of the simulation study involves the selection of a kinetic model that either can be developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudocomponents employed by the kinetic model, and relevant pressure/volume/temperature (PVT) data would be matched to develop a fluid model for the thermal simulator. This new fluid model is used in the field-scale-simulation model to history match the production history (i.e., before air injection) of the field. Third, relevant combustion-tube tests would be history matched to validate the kinetic model and refine the thermal data that would be entered into the field-scale model. Finally, the results and knowledge gained from the combustion-tube match(es) are applied to the field-scale model with the proper upscaling of some parameters. This simulation model would aid in selecting optimum well locations and operating strategies of the pilot. It would then be refined as the actual operation progresses to enhance its predictability and allow further optimization of the project.

Technical considerations, advantages, and limitations of each step of the workflow are discussed in detail. This paper also presents workflow variations and recommendations applicable to new and already-mature air-injection projects for which simulation models are being developed.
Propagation of Nanocatalyst Particles Through Athabasca Sands
Authors: Zamani Amir , Maini Brij B. , Pereira Almao Pedro
Published: June 2014

This paper presents results of an experimental study that systematically examined the propagation of nanodispersed catalyst suspension in sandpacks prepared with Athabasca reservoir sand and operated at the reservoir conditions. The concentration and size distribution of the particles at the injection and production end were measured. The pressure drops in different segments along length of the sandpack were monitored continuously. The retention behaviour of particles at the end of each experiment was examined by measuring the catalyst concentration in the bed as a function of the distance from the injection end of the sandpack and also by analysis of extracted samples using scanning electron microscopy. The results show that it is possible to propagate the nanodispersed catalyst suspension through sand beds without causing permeability damage, but a small fraction of the injected particles is retained in the sand. It was found that significantly higher retention occurs in the entrance region of the bed (compared with downstream regions) and that the total particle retention was higher in the Athabasca sand beds than in clean silica sand with the same flow and suspension properties. To the best of our knowledge, this is the first experimental study on transport of nanoparticles dispersed in viscous oil through reservoir sand beds. It provides valuable information on propagation and retention behaviour of nanoparticles. Considering the rapidly rising use of nanoparticles in industry, such transport will be encountered in numerous industrial applications and environmental problems.