bluuebunny/crossref_metadata_2025 huggingface dataset:
An Experimental Study of Cyclic Gas Injection to Improve Shale Oil Recovery
Authors: Gamadi T. D. , Sheng J. J. , Soliman M. Y
Published: September 2013

Low oil recovery in shale oil reservoirs and vast shale reservoir volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. A recent numerical study has indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs, and gas channeling can be mitigated. This paper presents our experimental verification and quantification of the potential to improve oil recovery by cyclic gas injection in shale oil reservoirs. Core plugs of Barnett, Marcos and Eagle Ford shales were used. The oil used was Mineral oil (Soltrol 130) and the gas used was Nitrogen. Unfractured cores were used in the experiments. The effects of cyclic time and injection pressure on oil recovery, among other parameters, were investigated. Our results also showed that cycle gas injection could increase the recovery from 10 to 50% depending on the injection pressure and shale core type. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase. The cyclic gas injection provides an effective and practical method to improve oil recovery in shale reservoirs because the gas needed is available in liquid-rich shale plays.
Optimizing Water Injection in a Mature Chalk Field by Application of Streamline Simulation
Authors: Johansen K. , Jensen L. J. , Marsden C. , Bakshi S.
Published: September 2013

The South Arne field, located in the Danish sector in the North Sea, has been produced since 1999. The field is Operated by Hess with Dong energy and Danoil as partners. Initially, the field was developed with production wells only but water injectors were added after 1½ years which increased the recovery potential of the field significantly. Currently the field is operated with 20 wells (7 injectors and 13 producers). All wells are fitted with sliding sleeve doors that allow zones to be opened or shut. This provides the valuable opportunity (or obligation) to pursue a more efficient recovery of oil by manipulating sliding sleeve doors – both in injecting and producing wells. In order to understand the long term effects from such well interventions a full field streamline simulation model has been built that will allow the injection efficiencies of individual zones to be quantified. Knowing the injection efficiency of zones enables the right zones to be chosen for interventions and to optimize the overall field water injection efficiency. The main goal has been to reduce water recycling and improve the macroscopic sweep by diverting flow from injectors into less swept areas. An associated benefit from reducing water recycling is the reduced need for lift gas, that can then be allocated to other wells.

It will be shown how an existing conventional simulation model was adapted to a streamline simulator and how this model was used to predict future optimal interventions in injection wells to optimize oil recovery. Excluding the positive effect from freeing up lift gas a ∼1% increase in oil recovery is expected from relatively few yearly interventions.
A Project Based Production Engineering Training Course for Improved Job Performance
Authors: Phillips James , Wilkie David , Aggour Tamir
Published: September 2013

A key element of the training strategy of Saudi Aramco's Upstream Professional Development Center is to utilize simulated work environments and project-based learning that is customized to the actual job roles, workflows, tools and data that trainees will encounter on the job. This paper presents details of the design, development and implementation of a project-based training course that serves as the capstone learning event in a program designed to develop new university graduates into independently contributing production engineers. The course provides participants with an opportunity to integrate and practice job-critical skills learned during the four-year program, using real company data, workflows and tools to work through a realistic well surveillance and testing project. The outcome of the course is a plan to optimize and manage a field that includes free flowing wells, artificial lift wells and gas wells. The learned skills are reinforced by having the participants repeat the exercise for an area of their assigned fields upon leaving the course, culminating in a presentation to their local management on their findings and recommendations. Project-based training that reflects actual work environments results in high learner engagement, higher retention levels and improved job performance. The opportunity to immediately practice the learned skills upon returning to work ensures the adoption of learning and adds business value. This work provides a model of training that can be utilized in any technical environment to design, develop and deliver training that improves individual job performance and adds value to the business.
Flow Path Characterization: A Deterministic Approach for Reconciliation of Flow Capacity Changes from Matrix and Fractures Productivity in Deep Jurassic Reservoirs in North Kuwait
Authors: Acharya Mihira N. , Chakravorty Sandeep , Rao Dhiresh G. , Joshi Girija K. , Pradhan San P. , Rao Narhari S. , Singh J. R. , Dashti Qasem M.
Published: September 2013

The Deep carbonate reservoirs of North Kuwait are broadly divided into deeper assemblage consisting of diagenitically modified dolomitic layer and shallower fractured-laminated tight limestone and Kerogen units. It is a challenge to establish and quantify the known phenomenon of dynamic changes in the flow path characteristics and properties of the reservoir rocks, as the natural stability condition are altered by production of reservoir fluid. The parameters of the flow path characterization become more uncertain in case of deep HP/HT digenetically altered reservoirs and fractured-tight limestone with laminated kerogen, then similar to the North Kuwait deep reservoirs.

In this study an integration of static data such as, borehole image, core and petrophysical evaluation with time lapse dynamic reservoir parameters like production, pressure data from buildup and pressure transient analysis was carried out to understand the flow path characteristic changes. A deterministic approach has been used to characterize the reservoir flow system and to estimate the fracture aperture for each time step. Thus the time dependent alternations in the flow path properties such as reduced fracture aperture and linked causative phenomena have been studied with multiple scenarios.

A detailed inventory and analysis of various well intervention operations between the time lapse measurements was carried out to distinguish the natural vs. work over induced causatives of flow path changes. This has assisted proper calibration of fracture properties for the static conditions, dynamic simulation and history matching. This workflow has also optimized the application of appropriate reservoir health checkups and remedial interventions. Cases of two representative wells completed in each of the deep reservoir assemblages are presented as examples to demonstrate the study.
Gas Lift Troubleshooting with Interactive Workflow and Rule Based Inferencing
Authors: Arellano Jose Luis , Khan Kashif , Istami Rashid , Partington Ben , Bakshi Amol
Published: September 2013

We describe a dynamic, real-time workflow for gas lift surveillance and troubleshooting that allows engineers to quickly identify a range of potential problems with the well and identify ways to optimize gas lift performance. This functionality has been implemented as a software program that makes innovative use of dynamic visualization, mathematical models, real-time data, and rule-based reasoning. The program logic uses PVT and multiphase flow correlations to allow engineers to understand the main variables that affect performance of the wells. The algorithms incorporate a simple set of IF-THEN rule-based inferencing to solve control problems in conjunction with the mathematical model. Based on real time data from field historians, recent well tests, and an up to date well model, the program estimates the current stability condition of gas lift wells with a single point of injection or multiple valves. For a given gas lift valve port size, productivity index and gas injection rate, it displays a stability map that provides an idea how much gas needs to be increased in order to improve the stability condition. The user (engineer) has the ability to dynamically vary parameters such as well head pressure, gas lift injection rate, orifice size, type of valve, etc., and thereby determine the best optimization approach. We describe a number of case studies where an application of this workflow logic improved gas lift performance.
Post-Treatment Assessment of Induced Fracture Networks
Authors: Taleghani A. Dahi , Gonzalez M. , Puyang P. , Lorenzo Juan M. , Le Calvez J. , Xu W.
Published: September 2013

An integrated methodology is proposed to generate a grid of potential paths for hydraulic fracture growth in naturally fractured reservoirs based on formation properties and recorded microseismic maps. The generated grid can be further used for treatment simulation to determine induced fractures geometry, height growth and respected proppant transport in the induced fracture network. For different realization of natural fracture distributions generated by computer simulations, cohesive interface technique is used to model evolution of induced fracture network. Microsesimic map is used to
Ultrasonic Curable Nanoparticles Strengthening Technique While Drilling
Authors: Xu Zichen , Jin Yan , Chen Mian
Published: September 2013

This paper proposes that nano-scale ultrasonic curable polymer and initiators can enter into the rock with drilling fluid in drilling process, in the presence of VDW force and electrostatic force, the polymer is absorbed and accumulates in fractures. Under the influence of ultrasonic transmitter set in the BHA, the initiator generates reactive free radicals to cure the polymer. In addition, the acoustic resistance in the fracture generates local high temperature, which can make the polymer crosslink and cure into a type of material of certain tenacity and strength, thus consolidate rocks near the wellbore as well as fill in fractures to strengthen the borehole wall. According to above theory, the study puts forward the design of ultrasonic curable drilling system and the design of downhole ultrasonic transmitter, and tests its properties. In addition, the study carries out the development of the ultrasonic curable system and the relevant downhole equipment and the application method, examines the application prospect of the technique from multiple aspects such as the impact of the fracture depth on the curing condition, the impact of the ultrasonic curable material on the permeability of the fractures, the impact on contact angle of shale surface and the impact on the strength of shale. The results show that the filter loss under HTHP is close to zero. This technique can effectively restrict the propagation of fractures, maintain the shale strength, and improve the strength of shale with faults. It is concluded from these tests that the ultrasonic strengthening technique can be applied to consolidate the caving section during shale gas drilling. The technology will be on trial in the shale gas drilling in West China, and is expected to be widely applied on unconsolidated sandstone and deepwater drilling to stretch the extension limits of the open hole.
Modeling Coupled Heat Transfer and Multiphase Flow during the Expanding Solvent Steam-Assisted Gravity Drainage (ES-SAGD) Process
Authors: Azom Prince N. , Srinivasan Sanjay
Published: September 2013

By solving a 1D heat conservation equation for single phase flow, Butler (1981) derived his classical SAGD equation which has excellent predictive capability at experimental scales but performs poorly at field scales. Several authors have tried to remedy this by acknowledging the existence of multiphase flow ahead of the steam chamber during SAGD, but have only empirically accounted for it using multipliers that seem to vary for each reservoir. Recently, by coupling the mass and energy conservation equations, Azom et al. (2013) solved this problem and showed that the multi-scale phenomenon is controlled by the classical Marangoni or thermo-capillary number.

In this paper, we extend the concept of thermo-capillary imbibition (Azom et al., 2013) to include the additional coupling of a solvent component mass balance to the mass and energy conservation equations in order to derive an expression for oil recovery during ES-SAGD.

Our results show that in addition to the thermo-capillary number, additional dimensionless groups like the condensate Lewis number, the ratios of the solvent's condensate to bitumen dispersion coefficient and solvent viscosity to bitumen viscosity at steam temperature influence multiphase flow and hence ES-SAGD flow performance. An important conclusion is that heterogeneity will have a complex effect on the ES-SAGD process as it causes more thermo-capillary imbibition (thereby decreasing bitumen rates) while at the same time causes the further transport of solvent into the bitumen phase (thereby increasing bitumen rates).

Our method involved accounting for capillary pressure in the conservation equations and decoupling it into its temperature and saturation components. This then forms the basis for coupling the mass and energy conservation equations. The solvent is assumed not to affect capillary behavior for the ES-SAGD process. The entire modeling was done in dimensionless space making the results applicable across varying scales and for a range of reservoir parameters.

This work presents a viable semi-analytical model for the ES-SAGD process while at the same time accounting for the effect of multiphase flow during the process. It is also important to note that currently no commercial simulator can model thermo - capillary behavior and hence cannot account for multiphase flow effects during non-isothermal recovery processes. Our model solves this problem for the ES-SAGD process and can be used together with the original Butler model as a fast ES-SAGD predictive model that also accounts for multiphase flow in any proxy-based history matching process.
Open Hole Fluid Displacement Analysis - Forward vs. Reverse Circulations
Authors: McNerlin B. , Gao Q. , Mohiuldin G. , Oakey N.
Published: September 2013

Angola is home to two of BP's largest subsea developments, Greater Plutonio and PSVM. High rate production wells have been achieved through the use of long open hole gravel pack completions, with alternate path screen design. Since the screens are deployed in conditioned oil based mud, the open hole is displaced to aqueous fluid prior to gravel packing the well. The early Greater Plutonio wells extensively utilised what is referred to as the ‘conventional,’ ‘forward,’ or Heel-to-Toe technique to displace the oil based fluid to water based. However, depletion of some of the reservoir sands increased the likelihood of screen plugging in wells with long open hole sections, as demonstrated by a handful of incidents. Also, the tight pore pressure to fracture gradient (PPFG) windows and small screen gauge sizes in the PSVM development made the ‘forward’ technique less suitable to adopt as a basis of design. As such, both projects developed a different displacement technique referred to as ‘reverse’ or Toe-to-Heel circulation to overcome the issues of sand control screen plugging and small PPFG windows. Work was performed to confirm that service tools could maintain full functionality, the fluid pill train properties were appropriate, and that hydraulic models could adequately predict the ECDs generated during the displacement. Eight open hole gravel pack wells, across both projects, have now been successfully completed using the Toe-to-Heel technique. Using the data from these wells, along with the existing data set from the earlier Greater Plutonio wells, it has been possible to determine a set of guidelines which indicate which technique is best suited under certain conditions.

This paper briefly describes the history of the two projects, details the operational differences between both methods, describes the evolution of the modelling work done for ECD prediction, including several pros and cons associated with each method. The actual displacement data is also presented, and is compared with the predictions from the initial modelling simulations. The development of even more accurate modelling techniques is also discussed.
Successfully Managing Mature gas Fields in the Netherlands
Authors: Yavuz Ferhat , Jansen Floor
Published: September 2013

Many Dutch gas fields are in the mature or tail-end production phase. Operating and producing these assets presents operational and financial challenges. Lower production rates, combined with ageing infrastructure, not only require effective management of expenditure but also implementation of emerging technologies to ensure sustained gas production. Liquid loading and salt precipitation are two major issues in managing mature gas fields in the Netherlands. Additionally the Dutch mining regulations require the use of sub surface safety valves (SSSV) which brings economic and operational challenges.

In 2012, EBN carried out an analysis on the historical production performance of all Dutch gas fields. During the last ten years operators have implemented various "End of field life" (Eofl) techniques, which and these have proved to be very effective. The commonly applied Eofl techniques are foam injection (batch and continuous), velocity strings, fresh water injection, jet pumps, plunger lift and mobile well head compressors.

Over the last ten years annual gas production from the small fields (i.e. all fields except Groningen) was between 30 to 40 Bcm/yr. (1050 - 1400 Bcf/yr.) from some 750 wells. Eofl techniques were applied to approximately 200 wells. So far an additional 2.5 Bcm (70 Bcf) has been recovered. These techniques did not only increase recoverable reserves from the specific fields, but also extended the life of infrastructure. They facilitated extra recovery whilst enabling continued operation of the assets for an extra five years.

From the analysis the authors conclude that the Eofl techniques were successful, even though to date they have only been applied on a small scale. The most common production issues are: liquid loading, salt and scale deposition and water breakthrough. The focus in this paper is on liquid loading and salt and scale deposition. The potential for improvement of recovery factors has a significant economic value. It is expected that operational experience and know-how will reduce the underlying costs in the near future.
Development of a Compact Topside Processing Plant
Authors: Mikkelsen René , Verbeek Paul , Akdim Mohamed Reda
Published: September 2013

Compact separation technologies have been gradually introduced into topside facilities during the last decade. Deployments have typically been motivated by a need to debottleneck facilities in mature fields, where a compact unit could be installed into a congested process plant without major reconstruction. While the advantages of compact separation technologies are generally acknowledged, the lack of data regarding performance, flexibility and reliability - as well the absence of process simulation tools - has until now resulted in a limited utilization of compact processing concepts in new field developments.

In close collaboration with a major oil operator a program has been established with the aim of developing a Compact Topside Gas/Oil/Water Processing Plant, with high efficiency and reliability, capable of handling the new oil properties and high CO2 content that characterizes the recent Pre-Salt discoveries. Inline ultra-compact separation technologies have been combined with optimized vessel designs to achieve a flexible and reliable processing plant for future FPSO's.

During the conceptual design phase extensive process simulations of the complete processing plant have been performed. Dynamic performance modelling has been included into these simulations for each component, allowing detailed predictions of plant performance in the presence of transients. This has been used for design optimisation, evaluating impact of component failure, as well as the development of a control and automation philosophy. Feedback from existing installations has been used to perform a Technology Maturity Assessment of each new technology incorporated in the compact topside facility and to establish a reliability database. For any technology not ranked at the highest Technology Readiness Level the gaps and required qualification activities have been identified.

This paper presents the activities executed during the development of a novel topside facility based on compact separation technologies, including Technology Maturity and Reliability Assessment, as well as capabilities of new process simulation tools.
Simple and Cost-Effective Hydrate Prevention for Flowback After Hydraulic Fracturing: Kinetic Hydrate Inhibitor (KHI)/Methanol Mixture
Authors: Huff T. , Cook S. , Trebing R. , Glover M. , Garza T. , Thieu V.
Published: September 2013

A mixture of KHI (Kinetic Hydrate Inhibitor) and methanol has demonstrated significant success in preventing hydrate formation for gas wells within a Wyoming field. Prior to this treatment method being utilized, gas hydrate blockage formation, in surface flow lines and production equipment, was an operational risk and a costly source of downtime during flowback operations following hydraulic fracturing. The well start-up phase, following a shut-in period, was particularly hydrate-prone due to the higher pressure and lower temperature conditions created by the shut-in itself. Flowback of new high pressure wells through separation equipment, rather than to a pit or tank, also increased the likelihood of hydrate formation due to the presence of back-pressure. Increasing occurrence of hydrates was associated with the use of ‘Green Completion’ separation equipment, which was being used in order to comply with the Wyoming Department of Environmental Quality requirement that emissions associated with natural gas flaring and venting during fracturing flowback are to be minimized. Due to delays and mitigation costs resulting from surface hydrate blockages, the operator has estimated an overall increase in flowback costs of more than $500,000 for wells completed over a nine-month period using this ‘Green Completion’ approach.

KHI, methanol and controlled mixtures of both chemicals were all considered as potential hydrate prevention methods. Laboratory results suggest that mixtures of KHI and methanol are in fact a more cost-effective solution than methanol alone. In turn, the presence of methanol actually enhances the effectiveness of KHI at these high sub-cooling values of up to 20 °F.

During high pressure well start-up, KHI and methanol was injected into surface lines at rates of 5 to 10 gph, for a dosage rate of between 2 to 10% in the water phase. The inhibition was stopped once the production stream had warmed up to a temperature outside the stable hydrate formation region, usually within 4 hours of initiating the start-up. These injections required only minimal additional equipment in order to safely deploy the inhibition chemistry. Following the successful treatment of 11 wells, the KHI/methanol mixture has become the prevention technique of choice for this Wyoming gas field.

This work is particularly relevant to onshore US wells that are hydraulically fractured. Applicable Federal EPA requirements mandate that, starting January 2015, operators in all states must reduce VOC emissions during fracture flowback operations. Compliance with this requirement may increase the frequency of hydrate blockages, and this simple and cost-effective hydrate prevention technique offers significant benefit in these situations.
Design, Installation, and Initial Performance of Ultra-High-Rate Gas Deepwater Completions - Tamar Field, Offshore Israel
Authors: Healy John , Sanford Jack , Dufrene Kerby , Fink Josh , Reeves Donald , Hopper Tim
Published: September 2013

A case history from Offshore Israel is presented that describes the successful delivery of five (5) ultra high-rate gas wells (+250 MMscf/D) completed in a significant (10 TCF) gas field with 7 in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a gas reservoir with high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of ultra high-rate gas wells was made to select and finalize the design concept after which the commensurate engineering rigor was applied. This paper will highlight key accomplishments within various phases of a completion delivery process for critical wells. The completions were installed with minimal operational issues (Average NPT ≈4%). Production commenced on March 31, 2013 without incident thus far. Each well is designed for production rates in excees of 250 MMscf/D.
Perforating Instrumented and Smart Well Completions: Available Technology, Testing, Development, and Lessons Learned
Authors: Blount C. G. , Grubb S. A. , Kable W. , Lynch P. H. , McCracken S. M. , Smith B. E.
Published: September 2013

Increasing numbers of ‘smart’ and instrumented wells are being completed worldwide. Many of these types of completions will require perforating as part of the initial completion and many more may require perforating at some time during the life of the well. Even completions that do not require perforating, such as common packer/sliding sleeve open hole completions, still rely on perforation technology to provide a back up contingency.

This paper identifies challenges and methods developed to mitigate problems associated with and to enable perforating instrumented and smart wells. This paper will also review the tools and techniques available to perforate these types of completions, while avoiding damage to pipe external control lines, cables, gauges, fiber optic lines, and other critical completion equipment. Discussions will cover a brief history and limitations of currently available tools and techniques. Details of testing and tool developments will be discussed followed by lessons learned from a multi-well field program.

The instrumented ‘smart well’ development program discussed in this paper includes six wells ranging from a 2,600' measured depth vertical well to 3 horizontal completions with measured depths exceeding 16,000'. The program included running over 20 logs ranging from magnetic based detection tools to ultrasonic tools, and perforating 129 separate intervals. Results of testing available tools and details of development of new equipment, tools and techniques will be discussed. No external cables or other smart well components were damaged during the 129 perforating operations.
Geomechanics of Hydraulic Fracturing Inferred from Composite Radiation Patterns of Microseismicity
Authors: Rutledge J. T. , Downie R. C. , Maxwell S. C. , Drew J. E.
Published: September 2013

Hydraulic-fracture microseismicity sometimes exhibit fairly uniform radiation patterns as revealed by systematic patterns of P- and S-wave first motions and amplitude ratios. These patterns suggest a predictable failure condition and allow composite source mechanism information to be obtained from sparse receiver coverage. Commonly, one of the nodal planes is aligned close to the hydraulic fracture. We present two case studies and interpret the composite radiation patterns in terms of expected stress conditions near the hydraulic fracture. In the first case, strike-slip failure is prevalently aligned with SHmax direction in a series of hydraulic fracture injections in the Cotton Valley tight sands. We interpret the alignment of nodal planes with principal stress direction as a preference for extension-shear fracturing. A preference for extension-shear fracturing requires conditions of low differential stress and high pore pressure, a condition produced immediately adjacent to a hydraulic fracture. In the second case dip-slip nodal planes are aligned with SHmax and hydraulic fracture direction in the Barnett shale. The alternate failure plane for a near-vertical dip-slip mechanism is a horizontal fracture plane. We interpret the uniform Barnett radiation patterns as an indication that shearing prevalently occurs on bedding planes, driven by and accommodating hydraulic fracture opening.
A New Method for Modeling Bypassed Oil Recovery in EOS Compositional Simulation
Authors: Zhang B. , Okuno R.
Published: September 2013

The conventional reservoir simulation uses the local equilibrium assumption, where fluids are completely mixed and at equilibrium within individual gridblocks. This assumption allows for no bypassing of oil at the sub-grid scale in gas injection simulation. Oil bypassing by gas, however, always occurs due to micro and macroscopic heterogeneities, gravity, and front instability.

There are a few methods proposed in the literature that attempt to model the effects of sub-grid heterogeneity in gas injection simulation. The concept of miscible residual oil saturation (i.e., the Sorm method) excludes the immobile oil from flash calculations and explicitly models bypassed oil. However, the Sorm method cannot model bypassed oil recovery because it allows for no mass flux between the bypassed and flowing fractions. The alpha-factor method uses transport coefficients to adjust components’ flux in compositional simulation. It has been used to retain a desired amount of residual oil in history matching for predominantly single-phase flow. However, its applicability to partial miscibility conditions is not fully understood. This is likely because the presence of more phases with partial miscibility yields more non-linearity and severer non-uniqueness in the history matching process.

In this research, we develop an efficient method to model bypassed oil recovery in multiphase compositional simulation. Oil bypassing in gas injection simulation is first explained using dual-porosity-flow (DPF) models. We show that DPF can capture the characteristics of the dispersion-capacitance model, where oil held up in the bypassed fraction gradually migrates to the flowing fraction through intra-block mass flux. Fluid flow in the presence of capacitance is characterized using the DPF parameters; the bypassed fraction, throughput ratio (RT), and Peclet number.

A new fluid characterization method is then used to efficiently reproduce DPF characteristics using a single-porosity-flow (SPF) model. An EOS fluid model is corrected for capacitance by adding heavier oil components that are characterized depending on RT. A case study demonstrates successful application of the new method to reflect capacitance effects observed in corefloods in field-scale gas injection simulation. Prediction of residual oil distribution within a reservoir depends significantly on how bypassed oil is modeled in the simulation. Unlike the alpha-factor method, our method requires no changes in the governing equations and in relative permeabilities.
Experimental Study of Liquid Viscosity Effect on Two-Phase Stage Performance of Electrical Submersible Pumps
Authors: Banjar H. M. , Gamboa J. , Zhang H.-Q.
Published: September 2013

Experiments with a seven-stage Electrical Submersible Pump (ESP) have been carried out to study the effect of liquid viscosity on the gas-liquid two-phase stage performance. The experimental tests provided data about the stage pressure increment as a function of the liquid flow rate at constant rotational speed, inlet pressure, and volumetric gas flow rate. Two different mineral oils were used so that the ESP two-phase stage performance was measured for 1 cP, 1.2 cP and 8.5 cP liquid viscosities, and for 8 different gas flow rates.

The experimental results demonstrate that the increase of liquid viscosity causes gas surging in the stage to initiate at lower normalized gas flow rates, reducing the gas handling capability of the stage. Increasing the liquid viscosity also causes the stage to reach a zero pressure increment at a higher normalized liquid flow rate. The pressure increment deterioration caused by the gas worsens with increased liquid viscosity. The performance map is analyzed and compared with that of another pump (GC-6100) with a higher inlet stage pressure.
Density-Based Rate-Time Production Analysis of Unconventional Gas Reservoirs Under Gas Slippage and Desorption
Authors: Vardcharragosad Pichit , Ayala H. , Luis F.
Published: September 2013

Accounting for gas-slippage and desorption effects is a critical step towards the reliable analysis of production performance in unconventional gas systems. This study demonstrates how to account for gas slippage and gas desorption effects in gas reservoirs using a density-based approach of analysis—an approach recently proposed for analyzing unsteady state flow of natural gas reservoirs. Gas-slippage and gas desorption models are incorporated into the original density-based approach by modifying the definitions of depletion-driven variables which are the basis of the density-based type of analysis. The proposed modification of the original approach successfully enables associated analysis techniques to be applicable to natural gas reservoirs with gas slippage and absorbed gas. Results indicate that by modifying the definitions of the depletion-driven variables, the density approach can effectively and successfully capture the effects from gas slippage and desorption. It is shown that gas flow rate can be successfully predicted by rescaling liquid solution with the modified density-based variables. This work illustrates the methodology required to do so and its application to production data prediction analysis for unconventional assets.
Smart Alarms Tool Development Approach for Oil Production Monitoring System
Authors: Pchelnikov R. L. , Mironov D. V. , Salikhov R. , Gladkov A. V. , Kogan G. A. , Gareev R. R. , Khabibullin R. A.
Published: September 2013

Data analysis and event alarms are essential part of any production monitoring system. Most often standard event alarms in production monitoring are based on selected measurements. Oil rate, pump intake pressure and temperature, water cut are some of them. Less often alarms are based on calculated values, for example production increase potential. However, they always indicate something goes wrong but never indicate why. Alarms can indicate there are deviations from planned values but do not give any clue about deviation reasons. Production engineer should investigate deviation reasons himself.

From author's point of view, smart alarms are the tool to overcome these challenges. Smart alarms in production monitoring system should be able to determine reasons of parameters deviation and to predict deviations before they become critical.

Smart alarms should use all the information available in order to increase estimation and prediction accuracy. They should classify and rank problems and problem reasons identified from potential future problems to problems required immediate reactions. Smart alarms should give reasonable results based on partial data, and should be able to analyze thousands wells per day.

Primary goal for smart alarm tool is to automate business process for 80% of well stock working in a standard way and to allow engineers to concentrate on 20% of complicated wells.

Smart alarm tool based on Bayesian network framework is under development and pilot implementation in TNK BP of Samotlorskoe oil field. Smart alarm tool is a part of corporate production monitoring system. This paper discusses Bayesian network application for engineering tool development and results of pilot implementation including algorithm accuracy, lessons learned and development plans.
A State-of-the-Art Completion Technological Innovation: The First 25,000- psi 500°F Permanent Bridge Plug
Authors: Ruffo Tony , Deng Guijun , Doane James , Anderson Gary , Lehr Douglas , Collins Scott
Published: September 2013

Global growth in demand for hydrocarbons is the key driver for the development of high-pressure/high-temperature (HP/HT) completion and isolation technologies. However, completion of ultra-HP/HT wells (T ≥ 450°F, P ≥ 20ksi) presents tremendous technological challenges to the operator and service companies. Conventional HP/HT packer and bridge plug technology is generally limited to long-term operation at 15,000 psi and 450°F, and the same can be stated for conveyance technology for these devices. A great deal of research and development effort has been put into extending performance beyond these limits for completion and isolation applications in the last 10 years. Recently, an innovative approach was applied to the solution of this problem, with the objectives of increasing these pressure and temperature limits and enabling long-term isolation in ultra-HP/HT wells. This approach resulted in the development of the world's first Ultra HP/HT Permanent Bridge Plug for long-term exposure at 25,000 psi and 500°F.

The Ultra HP/HT Bridge Plug was developed to satisfy a number of operational requirements that are unique to HP/HT wells:

Bridge plug longevity equal to that of the liner in which it is set. Bridge plug design which is capable of isolating reservoir pressures in standalone mode, without the aid of a column of cement on top of it. Bridge Plug operational reliability when conveyed into the well on electric line.

All these "mission critical" requirements were met. This paper discusses the development of this new Ultra HP/HT Bridge Plug. This discussion will cover elements of materials, design, prototype testing methodologies and conveyance. The validation testing processes in ISO14310/API11D1 Grade V0 requirements, as applied to this bridge plug, will also be described in detail. The application of state-of-the-art metallic and polymer material and design processes will also be discussed. Finally, the paper will conclude with the status of field installations.
Field Production Optimization Using Closed-Loop Direct Feedback Control of Intelligent Wells: Application to the Brugge Model
Authors: Dilib F. A. , Jackson M. D. , Khairullin A. Y.
Published: September 2013

Optimized production strategies using intelligent wells have been shown in numerous studies to improve economic performance. However, most optimization methods are model-based, effective only if the reservoir model captures the range of all possible reservoir behaviors at the individual well and completion level. This is seldom the case. Furthermore, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. Motivated by this, recent studies have shown that direct feedback control, triggered by monitoring at the surface or downhole, can increase net-present-value (NPV) and mitigate reservoir uncertainty. This approach does not neglect model predictions entirely; rather, a model-based approach is used to optimize adjustable parameters in a generic feedback control algorithm. We evaluate the benefits of using direct feedback control for multi-well production optimization using the synthetic Brugge field case study. We test three inflow control strategies. Two are based on direct feedback control, but differ in the level of monitoring and control. In the first feedback control strategy, all monitoring and control is taken at surface, using surface multiphase flow meters and on/off well-head control valves. In the second, monitoring and control can take place either at surface or downhole, using on/off well-head and variable completion inflow control valves, in response to measurements from surface and downhole multiphase flow meters. These control strategies are optimized on a subset of the published model realizations; the other realizations are then used to simulate unexpected reservoir behavior. For benchmarking purposes, we implement a third, reactive rule based approach, heuristically developed with prior reservoir knowledge of the truth model. We also compare our results to previously published, model-based inflow control strategies developed by optimizing NPV with perfect knowledge of the Brugge truth case. Our results suggest that closed-loop direct feedback control, implemented at surface and downhole, can yield significantly higher NPV compared to surface feedback control alone. Moreover, despite the simplicity of the direct feedback control approach, the NPV returned is higher than a heuristic reactive approach, particularly when reservoir behavior is unexpected. In contrast to model-based optimization techniques, direct feedback control is straightforward to implement and can be easily applied in real field cases.
Experiences with an Efficient Rate Management Approach for the 8th Tortonian Reservoir in the Vienna Basin
Authors: Kornberger Martin , Thiele Marco R.
Published: September 2013

Active well rate management is a simple way to increase recovery in brown fields while minimizing costs and preserving existing field/well fluid handling constraints. In this work, we present the application of an efficient flow-based surveillance technique to drive rate management decisions for the 8th Tortonian reservoir in the Vienna Basin, Austria. The 8th Tortonian is a typical example of a decade-long peripheral water flood on a long, steady decline for which it is difficult to justify expensive drilling/workover programs. Active rate management to improve sweep patterns presents a cheap solution to increase recovery. In case of the 8th Tortonian, Euro 10,000 (US$13,000) were spent to modify well rates resulting in ∼5700 m³ (∼35000 STB) incremental oil recovered over a 30-month period. The current oil rate remains above the oil rate before the start of the project.

Our approach takes advantage of streamline-derived well allocation factors (WAF's) that quantify injector-producer connections. It is simple and efficient to estimate WAF's using total historical well fluid rates, well locations, and a geological model. The geological model can vary in complexity from being a single homogenous layer to a sophisticated, 3D geo-model. With the WAF's known, the efficiency of each injector/producer pair can be estimated by using the historical observed phase rates times the well allocation factors. Well pair efficiencies are the starting point for the rate management approach described in this work.

A simple, single homogenous layer system was used in conjunction with historical rates and well locations to estimate the WAF's for the 8th Tortonian reservoir. Connections were compared to available tracer data, and an area of interest was subsequently selected based on streamlines and tracer data both indicating recovery by injected water. A key constraint was to maintain the total gross rate of the area selected at current capacity. New target rates we determined and implemented resulting in a 30% increase of oil rate over a 30 month period. Considering the simplicity and efficiency of the approach, this is a notable result. The production response of the selected wells showed an increased recovery in conjunction with a decreasing watercut suggesting contact with previously unswept oil. All operations and modifications were done at minimum cost. There were no perforation changes or acidizing jobs involved and rate changes were obtained simply by changing pump sizes or increasing the number of strokes by changing the V-belt pulley.
Novel Measurement of Asphaltene Content in Oil Using Microfluidic Technology
Authors: Sieben Vincent , Kharrat Abdel , Mostowfi Farshid
Published: September 2013

We present a state-of-the-art microfluidic technique for measuring the asphaltene content in crude oil samples. The automated microfluidic system improves data quality, reduces turnaround time, and minimizes solvent-volume consumption compared with conventional wet-chemistry measurements. The method is based on conventional precipitation techniques, such as the ASTM D6560, in which n-heptane is used for precipitation. However, instead of using gravimetric techniques commonly utilized in conventional methods, we use a novel spectrophotometry method for quantifying the asphaltenes. The optical technique is based on the spectral difference of crude oil before and after precipitation of asphaltenes using the titrant. We show a strong linear correlation between the optical method and the wet-chemistry technique for a broad selection of samples. The sample set included more than 50 crude oils with asphaltene contents as high as 15 wt.-%.

The unique microfluidic platform developed for this study uses a 200 µL sample loop to deliver the crude sample into a microfluidic chaotic mixer, where the sample is mixed with toluene. After dilution, we injected the sample into a 2.5-mm path-length flow cell, where a visible spectrum of the oil is recorded. To measure the spectrum of the maltenes, the sample is mixed with n-heptane in the microfluidic mixer at a predefined volume ratio. The mixture then flows into a reactor channel, where the aggregation process takes place and asphaltene molecules grow into large aggregates. After precipitation, the mixture is passed through a 200-nm-pore membrane, where asphaltenes are trapped and maltenes permeate through the membrane. The spectrum of maltenes is then measured using the 2.5-mm path-length flow cell and a UV-VIS spectrometer.

Using the microfluidic technique, a complete measurement takes only 40 minutes, a considerable improvement over conventional wet-chemistry techniques that require a minimum of 2 days. Furthermore, conventional wet-chemistry measurements are highly operator dependent. We show that, for our optical technique, the repeatability of measurement is better than ±0.1 wt.-%. The microfluidic measurements require only 200 µL of sample and 40 mL of solvent, which reduces the environmental impact of measurement. Finally, the small footprint of the apparatus makes it highly desirable for wellsite and offshore applications.
Industry Trends Utilizing Larger Diameter Coiled Tubing for Extended Reach Operations in Northwestern Canada
Authors: Edillon Lemuel
Published: September 2013

Coiled tubing (CT) operations in Canada have evolved significantly due to advancements in horizontal, multi-stage fracturing. This evolution has caused a shift from using smaller diameter tubing (31.75 mm to 50.8 mm) less than 3,000 m in length to using larger diameter tubing (60.3 mm to 73.0 mm) with lengths over 6,000 m. The preference for larger diameter CT is a result of operators drilling longer lateral lengths to stimulate as many zones as economically possible. To illustrate recent trends in Canadian CT operations, statistics from the past 10 years of horizontal drilling are briefly analyzed followed by an examination of operational data from a leading CT service provider. The surface equipment and CT string design required to perform these operations is also reviewed. Three recent case studies of CT milling operations in Northwestern Canada are discussed to highlight the importance of purpose-built equipment and accurate string selection in today's horizontal market. The industry trend to larger CT is significant because CT capability has become a key component in the overall feasibility and economic evaluation of extended reach, multi-stage horizontal wells.