bluuebunny/crossref_metadata_2025 huggingface dataset:
Polymer Field Trial: Deployment of Intelligent Technologies for Horizontal Wells and Real-Time Approach for Surveillance
Authors: Awan K. , Al-Mjeni R. , Al-Abri K. , Rajhi S. , Al-Azri N. , Al-Bulushi N. , Ghulam J. , Sinha M. , Furaisi S. , Edwards J.
Published: June 2014

This paper describes key factors related to intelligent horizontal well completion systems and surveillance activities for a polymer field trial within a sandstone reservoir in the South of Oman. The existing field predominantly comprising of horizontal producer wells drilled and located at the crest of the reservoir to ensure optimum oil production rates via artificial lift techniques. Many wells have encountered early water breakthrough, resulting in large volumes of un-swept oil. Improved sweep efficiency, hence improved oil recovery is expected by polymer flooding using a horizontal well approach [1].

The polymer field trial location consists of: 4 horizontal producers each completed with wire wrap screens, blanks and external zonal isolation packers within the reservoir section for segmentation and isolation. Each producer has a downhole gauge for real-time pressure and temperature monitoring. Three horizontal smart injectors each consisting of 4 zones completed with 7 inch pre-drilled liners, blanks and external zonal isolation packers across the reservoir section for segmentation and zonal isolation. These injectors are internally completed with intelligent completion systems with remote access and control whereby each of the 4 zones consists of a mechanical retrievable packer for zonal isolation, on-off intelligent flow control valve with hydraulic multi-drop module system for conformance control, quartz pressure-temperature gauge, double ended pump down DTS system for real-time monitoring and internally lined GRE tubulars in order to prevent polymer degradation. Two horizontal observation wells each completed with GRE casings and predrilled liner joints for logging along with downhole gauges for real-time pressure-temperature monitoring. One vertical observation well completed with GRE casing and carbon steel casing below the oil water contact for surveillance purposes.

A detailed surveillance plan for the current producers, injectors and observation wells is of utmost importance for pre and post injection data gathering in order to successfully evaluate key subsurface risks and uncertainties associated with the polymer flood technique. The field trial has been designed and executed with an optimum approach to ensure continuous real-time surveillance. This is facilitated by remote access and control thereby minimizing well interventions for surveillance activities for the duration of the trial.
Reducing Key Uncertainties Prior to a Polymer Injection Trial in a Heavy Oil Reservoir in Oman
Authors: Al Abri K. , Al-Mjeni R. , K Al-Bulushi N. , Awan K. , Al-Azri Nasser , Al-Riyami O. , Al-Rajhi S. , Teeuwisse S. , Ghulam J. , Abu-Sheikha Issa , Douma Sippe
Published: June 2014

Polymer flooding was selected as the preferred enhanced recovery process for a high permeability (2-5 Darcy) heavy oil (250 – 500 cP) reservoir with a strong bottom aquifer in South Oman. Several key uncertainties were identified through simulation modelling which would have a crucial impact on the process efficiency. These uncertainties formed the basis of a field trial design, and a detailed surveillance programme aimed at reducing these key uncertainties.

The presence of a strong bottom aquifer in this field resulted in near original reservoir pressure, which could provide a challenge to injectivity. The close proximity of injectors to the oil water contact reduces the efficiency of the polymer flood through water fingering, and polymer loss to the aquifer. Additional uncertainties include: reservoir heterogeneity, Kv/Kh, permeability distribution, baffles, natural fractures, remaining oil saturation, injectivity, induced fracturing and inflow profile along the horizontal well (producers and injectors). Hence, extensive data gathering was carried out in order to reduce these uncertainties through updating the static and dynamic models and allowing for a better understanding of the field behavior prior to polymer injection.

This paper details a fully integrated evaluation of the gathered data through a multi-disciplinary team during the drilling of the trial wells. The data includes: open hole logs, borehole images, core analysis, fluid sampling, dielectric measurements, vertical interference testing, production logging and existing dynamic production data. Also, single well water and polymer injectivity test and extended leak-off test were carried out to understand the injectivity and fracture behavior. The wealth of well data coupled with geological and dynamic data reduced the overall reservoir properties and fluid distribution uncertainties. Furthermore, the data were crucial to design the optimum injection and data gathering requirements during the field trial. Finally, the paper provides an overview of the surveillance aspects of the field trial.
TPM's: A New Class of Viscoelastic Solutions for Enhanced Oil Recovery
Authors: Siggel L. , Radloff M. , Reimann S. , Hansch M. , Nowak M. , Ranft M. , Weiss H. , Schreiner E. , Brand F.
Published: June 2014

A new class of viscoelastic solutions -Triphenoxmethanes (TPM)-has been under development since early 2010 and remain a fruitful yet highly challenging research topic. The TPM's are viscoelastic at low concentrations (<0.5%w/w) and show good stability in highly saline hard brines. They have been tested in hard brines up to 25% TDS with high divalent cation concentration and show increasing performance with increasing salinity. The current lead candidate "TPM", which is also being scaled up for a first field trial, displays good performance to 75°C. Adsorption/retention measurements show quite acceptable values for the harsh conditions under study. Porous media testing has shown that the TPM's have good injectivity properties and mobilize significantly more oil than brine alone. In addition, oil displacement experiments with cores at residual oil concentration (Sor) have clearly shown that TPM mobilizes residual oil (ca.7% OOIP) without significant reduction of the IFT and with less than 1 PV injected fluid.

The suitability for use in a particular reservoir is a complex interplay of the molecular structure of the TPM, temperature and brine salinity: lowering the salinity increases the application temperature. The interrelationship of the different factors is an on-going, high priority activity of the integrated R&D team. Here we report on the relevant aspects for application in harsh environments and give an outlook for field application.
Secondary and Tertiary Polymer Flooding on Highly Permeable Reservoir Cores: Experimental Results
Authors: Cottin C. , Bourgeois M. , Bursaux R. , Jimenez J. , Lassalle S.
Published: June 2014

This paper presents laboratory polymer core floods in secondary and tertiary mode carried out on highly permeable aged sandstone reservoir cores at reservoir temperature, with oil viscosities ranging from 7 (reservoir A) to 55 cP (reservoir B). Oil recovery is measured through three redundant techniques: mass balance, X-Ray saturation and miscible tracer test. Experimental results are interpreted to obtain polymer relative permeability curves by history matching oil production profiles, differential pressure and in-situ water saturation profiles at every step of the experiments.

The main results can be summarized in three points. Small scale heterogeneity and core quality have a large impact on the experimental results, making the comparison between different floods cumbersome, as well as between water flood and polymer flood. Polymer injection in this oil-wet high permeability reservoir changes the balance between capillary and viscous forces, leading to oil recovery in layers where capillary trapping is observed during water injection. Finally, there seems to be a difference in behavior between secondary and tertiary polymer floods, where the local residual saturation to polymer injection, as quantified by X-ray, is lower in secondary mode than in tertiary mode, while in tertiary mode both water and polymer injection have the same local residual oil saturation. Possible reasons as to why secondary polymer injection behaves differently than tertiary polymer injection are still being investigated.
Comprehensive Correlations to Calculate Viscosity of Partially Hydrolyzed Polyacrylamide
Authors: Gao Chang Hong
Published: June 2014

Polymer flooding is the most successful chemical enhanced oil recovery (EOR) method. This technique has achieved large-scale field applications at Daqing and Shengli oilfields in China. At Daqing oilfield, polymer flooding has improved oil recovery by 10%. At Shengli field, polymer flood has contributed to more than 22 million tons of oil since 1992.

The most common polymer for EOR projects is partially hydrolyzed polyacrylamide (HPAM). Since 1970s, continuous efforts have been spent on understanding the factors that influence the viscosity behavior of HPAM. It was discovered that shearing, heat, divalent ions and monovalent ions all have negative impacts on polymer viscosity. However it is still a challenge to predict the viscosity of HPAM under given reservoir conditions. The commonly used Carreau equation and Meter equation fail to consider the various factors that lead to loss of polymer viscosity.

In this paper, extensive laboratory tests were conducted to measure the viscosity of HPAM solution under the influences of shearing, high temperature, Calcium concentration and sodium concentration. Based on the test data, numerical correlations are proposed to predict the power law parameters. These formulas take into consideration the various factors that affect polymer viscosity. These correlations will help to improve the prediction of polymer viscosity under reservoir conditions, and will lead to more reliable design for polymer flooding projects.
Application of Streamline Simulation for Gas Displacement Processes
Authors: Nagib Mohamed , Burns Alan , Ingham Derek , Pourkashanian Mohamed , El-Banbi Ahmed H.
Published: June 2014

Streamline methods, in which fluid is transported along the streamlines instead of the finite difference grid, are widely used d in the oil industry. Larger time steps and higher spatial resolution can be achieved in streamline simulations. 3D flow problem is decoupled into a set of 1D problems solved along streamlines, which reduces the simulation time and suppresses the numerical dispersion. However, finite-difference reservoir simulation is widely used for solving large-scale multiphase displacement problems, streamline proved to be a faster tool for proper reservoir managment.

Proper assessment of miscible and near-miscible gas injection processes are usually carried out through conventional finite difference (FD) compositional simulation. Due to high-resolution simulation of the detailed geological model (Fine grid) is time consuming, coarse grid (Low resolution) models are normally used for testing the performance as a fast track process. Low-resolution compositional simulation is adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately. Streamline application will properly describe displacement and volumetric sweep in the fine grid model that capturing all reservoir heterogeneity.

Streamline computations assume incompressible fluids, and therefore they are not usually used for reservoir simulation of gas injection processes and for depletion studies below the bubble point. This paper presents the results of investigating the use of streamline techniques in gas displacement processes. A detailed comparison is given between the results of conventional FD simulation and the streamline approach. The comparison demonstrates that streamline simulation can be used in gas displacement processes under certain conditions. In such cases, the CPU time requirements and numerical dispersion can be reduced significantly while allowing the engineer to use a finely gridded model capturing the heterogeneity of the reservoir.
Experimental and Numerical Investigations into the Effect of Heterogeneity on Heavy Oil Recovery by VApour EXtraction (VAPEX)
Authors: Al-Hadhrami M. M. , Alkindi A. S. , Muggeridge A. H.
Published: June 2014

We used a combination of experimental, analytical and numerical approaches to examine the oil drainage rates obtained from VAPour EXtraction (VAPEX) process to recover heavy oil. In particular we investigated the influence of macroscopic scale heterogeneities through a series of experiments. These heterogeneities comprised layers, a quadrant model and two cases with discontinuous shale barriers above the injection well. All experiments were performed in well-characterized glass bead packs using glycerol and ethanol as analogues of heavy oil and solvent respectively. All the porous medium and fluid properties (including permeability, porosity, viscosity, density, diffusion and dispersion) were measured independently. The experimentally measured rates were compared to the estimates derived from the Butler-Mokrys analytical model. Numerical simulations were validated using the experimental observations from the homogenous and heterogeneous systems.

The findings confirmed the square root dependency of the oil rates on permeability (at least for the range of permeabilities used here) which is consistent with findings from previous studies. Despite that, the results indicated that the Butler-Mokrys derived expression under-predicts the physical oil rates, even when the effects of convective dispersion and end-point density difference (as suggested by other works) were factored in. Results from the heterogeneous models suggest that layering may not reduce VAPEX oil drainage rates significantly. They also showed that oil was not recovered from the lower permeability layers. For models with discontinuous shale barriers, the simulations tended to over-predict the oil rates compared with the experiments.

Overall the estimated rates from the simulations were more comparable to the physical rates than those estimated from the original Butler-Mokrys analytical derivation. Moreover the simulator was able to capture the pattern of solvent-oil distribution for both homogeneous models and heterogeneous models. This would suggest that the Butler-Mokrys model does not properly describe all the physical processes that are controlling the oil drainage rate even in homogeneous models.
Challenges in ‘Surface Facilities Implementation’ for a Full field Polymer Flood Project
Authors: Bhaumik Premashis , Mohanram Santosh
Published: June 2014

This paper discusses the key challenges in Surface Facilities implementation for a Full Scale Polymer Flood Project. The key challenges discussed include (a) availability of limited technology for high concentrated polymer dissolution, (b) transfer of high viscous Polymer Mother Solution with minimum viscosity loss, (c) water quality issues, (d) designing a feasible supply chain strategy for polymer logistics and (e) handling back-produced polymer associated with the well fluid.
Design of Horizontal Polymer Injectors Requiring Conformance and Sand Control
Authors: Bouts Marcel N. , Rijkeboer Marleen M.
Published: June 2014

For the redevelopment of a heavy oil field (160 cP), polymer flooding as an EOR technique has been studied. To minimize the number of wells and still achieve significant injection rates of 500-750 m3/d in the 30m thick reservoir, horizontal wells were designed. The completion included sand screens (WWS) with outflow control devices (OCD) to maximize injection conformance.

Key to the success of polymer injection at high rates is to ensure that the solution viscosity is maintained such that effective oil sweep takes place. Since EOR polymers are sensitive to mechanical shear (i.e. loss of viscosity when flown through restrictions), the completion design has been optimized by addressing the following:

Shear degradation tests in lab experiments using capillaries, sand screens, OCD nozzles and reservoir cores Assess the expected shear rates through the sand screens, the OCD nozzles and the near wellbore area, the latter is based on the Blake-Kozeny relationship and used in coreflow tests. A nodal analysis model using the non-Newtonian fluid model was constructed to analyse the conformance benefits and optimize the OCD nozzles.

The presented work indicates that horizontal polymer injectors requiring both conformance and sand control can be designed such that high injection rates can be achieved without jeopardizing the polymer viscosity.
Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs
Authors: Han Ming , Fuseni Alhasan , Zahrani Badr , Wang Jinxun
Published: June 2014

As part of the screening process for chemical EOR, several polymers have been screened as co-injectants in a surfactant-aided water flood scheme. Due to their higher viscosity, polymers improve sweep efficiency and reduce the permeability of rock matrix, therefore help to improve oil recovery. Aimed at a representative carbonate reservoir in the Middle East, a polymer screening study has been conducted with respect to polymer solubility and viscosity retention in high salinity brines, equivalent to our reservoir parameters. The polymers have to pass through a stringent screening process to meet the harsh conditions encountered in the reservoir: high temperature, high salinities and carbonate nature. Salinity effect was studied in a range of brines that included shallow formation water, produced water, and connate water. Among the polymers studied, six were found compatible and have been short-listed. Based on rheological measurements and flow curves, the concentrations of polymers have been determined to achieve the target viscosity under reservoir conditions. Long-term stability and adsorption tests were conducted to ensure the efficiency of the polymer exposed to reservoir conditions. Oil displacement tests with a selected polymer showed an increased oil recovery factor of 11% by polymer flooding and 18% by surfactant-polymer flooding. This study demonstrates the potential application of polymers under extremely harsh reservoir conditions and their promise to be good additives for chemical flooding.
Evaluation of Fluorosurfactant Performance with Super-Critical CO2 Flooding for High Salinity Carbonate Reservoirs
Authors: Jangda Z. Z. , Sultan A. S. , Gajbhiye R. N. , Abu-khamsin S. A. , Arshad A.
Published: June 2014

Super-Critical CO2 flooding combined with surfactants is one of the latest methods being used for Enhanced Oil Recovery. This overcomes the shortcomings associated with CO2 gas injection like gravity override and viscous fingering to an appreciable extent. It restricts the mobility of the injected fluid leading to higher contact with the resident crude resulting in better sweep efficiency. A number of surfactants have been tested with CO2 to appraise performance in different scenarios. However there have been problems of surfactant instability at real reservoir conditions i.e. at high temperature and high salinity. Adsorption of surfactants on the rock surface is another issue that usually decreases the effectiveness of the system.

In the core-flood experiments performed in this work, an amine oxide-based amphoteric fluorosurfactant has been injected with super critical CO2 for the first time on foot long carbonate cores saturated with high saline formation water (Total Dissolved Solids > 200,000 ppm). High temperature (90°C) and pressure (2500 psi) were applied coupled with 5 days of aging time with reservoir crude to recreate actual reservoir environment. Different injection strategies were studied including co-injection of super-critical CO2 and surfactant solution, and alternating injection of super-critical CO2 and surfactant solution in different ratios, and then compared to find out the optimum injection strategy.

Results from the study exhibit a significant increase in the oil recovery due to this CO2-surfactant system as well as foam generation in high saline environment for the co-injection scheme.

This research provides a new and viable option for CO2-Surfactant flooding especially for high salinity carbonate reservoirs. It displays the usefulness of the surfactant even at very low concentrations, thus mitigating the high cost of this type of surfactants. Furthermore, this surfactant does not contain environment harmful substances making it a greener substitute to conventional hydrocarbon surfactants.
The Novel Use of Deep Eutectic Solvents for Enhancing Heavy Oil Recovery
Authors: Mohsenzadeh A. , Al-Wahaibi Y. , Jibril B. , Al-Hajri R.
Published: June 2014

The World has abundant deposits of heavy crude oils. In the past, production of such heavy oil was disfavored due to discouraging economic feasibility and availability of lighter oils. Increasing demand and dwindling supply of crude oil have spurred efforts towards enhancing heavy oil recovery. Recently, applications of ionic liquids (ILs) for heavy oil recovery and catalytic upgrading have been reported. However, ILs are generally considered too expensive for industrial applications. Moreover, certain types of ILs are non-biodegradable and toxic. An alternative class of ILs called Deep Eutectic Solvents (DESs) have recently been discovered and investigated upon. A DES generally composed of two or more components that are capable of self-association, to form eutectic mixture with a melting point lower than that of each individual component. DESs are non-toxic, biodegradable, recyclable, nonflammable, environmentally friendly and cheap. Therefore, DESs have found application in fields like extraction/separation, solvent development/reaction medium, hydrometallurgy, etc. In this study, and for the first time to our knowledge, the effectiveness of two different types of DESs, Choline Chloride:Glycerol(1:2) and Choline Chloride:Urea(1:2), in enhancing heavy oil recovery is thoroughly investigated. Effect of the two DESs diluted with water on emulsification, altering wettability, spontaneous imbibitions, surface and interfacial tensions and tertiary residual heavy oil saturation reduction are studied experimentally at different temperatures. Heavy oil with 16 °API and formation brine from one of the Omani heavy oil fields was used. The core flood experiments were conducted at reservoir condition and using Berea sandstone core plugs.

The results showed that the two DESs did not make emulsion with the heavy oil. They increased the IFT of oil-brine system. Moreover, the two DESs altered the wettability of the sandstone rock surfaces from strongly oil-wet to neutral-wet conditions. The core flooding runs at different temperatures showed high potential of using these DESs for enhancing heavy oil recovery; where 14-30% of water flooded residual heavy oil was recovered after injecting the DES solvents as tertiary recovery stage.
Oil Production From Heated Core Plugs: Experimental Results and Thermal Simulation
Authors: van Heel A. P. , Oedai S. , van Wunnik J. N.
Published: June 2014

Recovering medium to heavy oil from fractured carbonate reservoirs, which typically have a low matrix permeability, is challenging. Steam-injection is a promising EOR application for such reservoirs, as it initiates beneficial processes like thermal expansion and viscosity reduction of the oil, leading to an increased rate of gas-oil gravity drainage, resulting in accelerated recovery. In addition thermal solution-gas drive and distillation of lighter components can be activated upon heating.

We present experimental results and thermal simulation results of oil production from carbonate core-plugs during heating, which were designed to determine the contribution of the various thermal recovery mechanisms. Two carbonate core-plugs were cleaned, aged with formation brine and live-crude to restore original wettability, and were subsequently heated from 50 C to 235 C at a constant pressure of 31 bara, in a dedicated set-up.

The liquids and gas expelled from the core-plugs were continuously collected in a separate collection vessel, also at 31 bara.

The recovered oil volumes were substantial. We simulated the experimental results by thermal k-value simulation and obtained good agreement with experimental results. Progressive heating activates several recovery mechanisms: thermal expansion, thermal solution-gas drive and distillation. The temperature ranges where each of these recovery mechanisms are dominant are clearly distinguished in the experimental and simulation results.

The results provide quantitative estimates for the contribution of the various thermal recovery mechanisms in carbonate reservoirs subject to steam-injection.
CEOR Facilities: Onshore Concept as an Alternative to Offshore
Authors: Mahbob Izwan Nizam , Abd Satar Fairudul Azhar , Mohamad Othman Khairul Anwar , Amirrudin Farahnajwa , Yaacob Aisha A'shikin , Halim Nor Hadhirah , Zainal Suzalina
Published: June 2014

PETRONAS is currently embarking on a project to implement Chemical Enhanced Oil Recovery (CEOR) by injecting 160,000 BWPD of chemically enhanced water consisting of Alkaline and Surfactant (AS) for a period of four (4) years. The oil field is located in the South China Sea and has been in operations for thirteen (13) years.

Initially in terms of facilities development, the base case identified for the project was a floating vessel (ship) concept which was preferred to other options considered at the time such as having a new standalone platform or a bridge link platform to house the water treatment and chemical mixing and injection facilities. Short duration of CEOR injection, opportunity to redeploy the floater to reduce lease costs as well as the ability to store large volumes of treated water and chemicals were key factors in selecting the floater to be the base case. Further studies using the floater concept i.e. Basic Engineering Design (BED) and Front End Engineering Design (FEED) were carried out in 2011 and 2012 to mature the development concept.

High project cost and chemical logistics challenges learnt from these engineering works resulted in a decision to explore other alternative facilities development concept which could meet the project requirements but at a lower cost and risks. One of the options identified is to build the CEOR Plant at onshore and deliver the chemical mixture by using a pipeline. The opportunity to consider this option was made possible with the availability of an existing oil pipeline that connects the CEOR Field and an existing Onshore Crude Oil Terminal belonging to PETRONAS. A feasibility study was immediately carried out to assess this option which included evaluation of the compatibility of the cocktail with the pipeline internal walls as well as its effectiveness after travelling the whole length of the pipeline at varying seawater temperatures. In parallel, potential locations to construct the plant were surveyed, a preliminary layout of the plant was drafted and numerous seawater intake options evaluated including the potential of using river water as alternative to seawater to produce the designer water required.

Results from the feasibility study were encouraging and high level cost estimates indicated significant savings could be achieved by pursuing the onshore plant option. More importantly logistics challenges associated with transportation of huge amount of chemicals to offshore and other operational constraints would be eliminated via this option. This new alternative concept has given a new lease of life for the project to be realized.
Polymer Flood at Adverse Mobility Ratio in 2D Flow by X-ray Visualization
Authors: Skauge Tormod , Vik Bartek Florczyk , Ormehaug Per Arne , Jatten Berit K. , Kippe Vegard , Skjevrak Ingun , Standnes Dag Chun , Uleberg Knut , Skauge Arne
Published: June 2014

Polymer flooding is a mature EOR technology, but several pore scale phenomena with possible large influence on the reservoir scale are poorly understood. This paper describes and analyses oil mobilization experiments of heavy oils by imaging instable displacement at adverse mobility ratio water and polymer floods. Two-dimensional flood experiments have been performed using Bentheimer outcrop slabs. X-ray imaging is utilized to visualize displacements and to determine the underlying flow mechanisms. Viscous fingering, water channel formation and oil displacement are described for a series of mobility ratios.

Mechanistic understanding of development and propagation of viscous fingers at adverse mobility ratio may be used to improve reservoir simulations. Description of oil mobilization for various mobility ratios may give guidelines for choice of polymer concentration and slug size for polymer floods.

Bentheimer slabs were drained using oils with 4 viscosities (5 − 616 mPa∙s). X-ray imaging revealed differences in water-finger formation, and width and growth of fingers with increasing mobility ratio. Lower mobility ratios showed formation of wide fingers or water channels. Oil recovery was dominated by propagation of these channels, but still showed poor sweep efficiency (water breakthrough 0.3 – 0.5 PV). At high mobility ratio, water breakthrough occurred very early at 0.08 – 0.15 PV. Here, the oil recovery mechanism was totally different. Oil was mobilized by polymer injection through cross-flow into the water channels. Polymer flood showed rapid change in oil cut and high total oil recovery efficiency. Through analysis of 2D x-ray images, mechanisms for fingering initiation and propagation and for oil mobilization by polymer is visualized and discussed as a function of mobility ratio.

The results presented here may impact polymer flood design, in particular the choice of polymer injection strategy for heavy oil reservoirs. Data show that relatively low polymer concentrations are sufficient for mobilizing heavy oil.
Overview and Analysis of a Thermal Trial in a Deep Ultra-Heavy Oil Field in South of Oman
Authors: Al-Hinai Rashid , Al-Bahlani Al Mutasim , Al-Maharbi Abdulaziz , Al-Qassabi Dawood , Abdullah Jahdamy , Nasser Omairy , Musallam Mandhari , Al-Hinai Nasser
Published: June 2014

A thermal steam trial is applied in a multi-billion barrel STOIIP oilfield with very complex reservoir and oil properties. With low permeability, and saturation, deep thinly laminated formation and ultra heavy oil viscosity (100,000 cp at reservoir temperature of 65o C), the field introduces extreme challenges for conventional thermal development. This requires innovative solutions to stretch the thermal development boundaries to achieve technical and commercial success. In order to accommodate such subsurface challenges, unique surface facilities were acquired which made it possible to inject heat at high pressures.

Despite all these challenges, Phase 1 of the trial successfully conducted 4 cyclic steam stimulation cycles where over 13,000 tons Cold Water Equivalent (CWE) were injected into the formation at high pressure (21,000 Kpa) and high temperature (360o C) environment. With such extreme conditions, the project team managed to perform 11 PLT runs during injection, soaking and free-flow periods, making such success an industry-first in the region.

Previous paper (Stretching the EOR Boundaries: Thermal Trial in one of Petroleum Development Oman's Deep Reservoirs containing Heavy Oil, M. Mandhari et al) provided an overview of the early stages of the development of the trial. This paper will provide a thorough overview of the surveillance data during Phase 1 of the trial. "It will also provide an extensive representation of the analysis done on the gathered data which led to the design of Phase 2 of the trial and the methods selected to achieve higher latent heat injection into the formation."
Construction, Operations and Performance of the First Enclosed Trough Solar Steam Generation Pilot for EOR Applications
Authors: Palmer Daniel , O'Donnell John
Published: June 2014

This paper presents performance, results and learnings from the first solar enhanced oil recovery (EOR) project in the MENA region.

The following areas are covered in the paper: the motivation for solar EOR in Oman, description of the enclosed trough design employed in the Amal field, operations and performance data in the Oman desert environment, integration with oilfield operations and an update on results at the time of publication.

According to industry forecasts, the GCC region faces a significant shortfall of gas supply. In Oman today, over 22% of gas consumed is used for oil production including power generation, gas injection and steam generation for EOR.

The pilot project deployed in Amal West field was of a new enclosed trough design in which solar radiation is concentrated using parabolic trough mirrors that are enclosed to protect them from dust and wind loading. The "once-through" design allows the use of standard OTSG feed-water to produce 80% quality steam at 100 bar, matching typical EOR specifications.

The key objective for the pilot was to prove that the system is able to be deployed practically and economically at scale in the region. To do this several key elements had to be field proven. First, it was important to prove that the steam output could be modeled and predicted with certainty. The paper will discuss performance verses model and the enhancements implemented during the year to improve steam production and quality. Second, the oilfields of Oman lie in a region with about fifteen times higher dust or "soiling rate" than locations where concentrating solar power (CSP) is typically deployed. The performance of the system in extreme weather was tested. In conclusion, the data will point towards the feasibility of full field deployment of solar EOR in the region and explore some of the challenges that lie ahead in its adoption.
Study of the Hydraulic Performance of Drill Bits Using a Computational Particle-Tracking Method
Authors: Moslemi Ali , Ahmadi Goodarz
Published: June 2014

The hydraulic performance of fixed-cutter drill bits was studied with the ANSYS-FLUENT code (ANSYS 2012). Cuttings were modeled as spherical particles that were injected from the bottom of the hole, and discrete particle modeling (DPM) was used to track the cuttings in which particle/particle interaction is ignored. The ratio of average particle velocity to average annulus fluid velocity, referred to as the cuttings-transport ratio (Ct), was then evaluated to study the hydraulic performance of drill bits under different conditions.

The simulation results show that Ct increases as nozzle-jet velocity and HSI (hydraulic horsepower per square inch of bit) increase. Comparing Ct with rate-of-penetration (ROP) data available in the literature revealed that the rate of Ct change is less than that of ROP as HSI changes. Ct decreased slightly in a bit with seven nozzles when compared with the same bit with five nozzles with the same total flow area (TFA) of nozzles and inlet flow rate. Also, Ct was found to be insensitive to the nozzle-size arrangement and bit-waterway profile in the studied bit size. Overall, the current method (with the assumption of negligible particle/particle interaction) is more appropriate for predicting drill-bit hydraulic performance when drilling hard and nonreactive formations.
Digital Energy Assessment: The First Step Towards Operational Excellence
Authors: Arcot Senthil , Lochmann Mark
Published: June 2014

Digital Energy (DE) describes broad initiatives to improve asset performance and boost corporate value through operational excellence and engineering design. It has been described in many papers presented at SPE meetings such as Digital Energy in Houston and Intelligent Energy in Europe and the Middle East. Digital energy introduces new principles and information technology (IT) tools, frequently requiring new work processes, workforce adoption, and changes in behavior. One description of digital energy (Davidson and Lochmann 2011) includes:

Fully-integrated, multi-disciplinary operations Task and process automation Digitally-enabled technology Business or operational intelligence Innovative, efficient methods to maximize performance

The move from ‘good enough’ practices to operational excellence is a transformational change (evolving from one ‘look’ to another or one culture to another)and poses challenges and opportunities for organizations. Applying DE principles to promote operational excellence inevitably leads to new ways of working and unfortunately, organizational stress. Some of the challenges include aligning people, technology, and the organization to the new vision.

The first step in the digital energy process, regardless of a project’s size, should bean assessment of an organization’s current state including its level of understanding of DE, readiness to change, and what a digital energy initiative may contain. An assessment is a way to look into the world of DE and identify the functionality that may be best suited for a company’s operating environment and assess its impact on performance. Assessments have proven essential for success when organizations undertook major projects to improve asset performance and increase corporate value. Assessments often uncover unexpected paths to better performance.

The objective of an assessment is to identify and articulate the organization’s operational vision (different than broad IT or engineering objectives) and follow a structured approach to uncover and identify how DE initiatives can support and solidify the organization’s strategic objectives. During an assessment, information is gathered to identify and understand business drivers and goals while analyzing business priorities and developing value propositions. Through the evaluation and analysis of this information, a working solution roadmap is produced.

Because E&P organizations are largely unfamiliar with the practical aspects of DE, the assessment step is often undervalued and, in some cases, skipped altogether. This means suboptimal results, increased project risk, and diminished returns.
Economic Implications Of The Current Geopolitical Forces Vis-à-vis Hydrocarbons On Global Energy Markets
Authors: Michael Andreas
Published: June 2014

Energy, coming in its great majority from oil and gas has become a strategic factor in global geopolitics. It is key to national power and a major requirement for economic growth. Energy consumption has become the most palpable national characteristic that separates rich from poor countries. The United States, the richest nation in the "room" is also the most intense user of energy per capita.

There is a substantial imbalance in the location of energy producers and consumers, an imbalance that has precipitated world conflicts and one that will likely cause future upheavals. There is huge activity by China buying energy resources all around the world. Russia's recent ascendancy in the energy world has been an important counterbalance to the power of OPEC. However, recent events surrounding Russia's energy industry have exposed fissures within the economic and political makeup of the country.

The United States Shale Revolution has, and will, bring market distortions throughout the entire nation and to many others such as the energy-starving, Southeast Asia markets of China and Japan. The recent removal of restrictions on LNG exports by the American government means that new forces will be implemented on both demand and supply of those markets. I believe that the globalization of gas trade will make prices of natural gas to converge and thus we will witness a more "unified" price regime in the not-too-distant future. Predictions of the future supply of petroleum have typically been far less accurate than predictions of demand. Flawed predictions have caused public bewilderment, distrust and, more importantly, government inaction or poorly conceived reactions. The cause of every energy crisis, like oil climbing to $150 per barrel in 2008 before dropping to $40, is above the ground geopolitics and never behind the valve issues.

This paper applies basic economic principles to assess the effects of present-day geopolitical forces on energy markets, particularly those of natural gas, around the globe arriving on a number of interesting conclusions. Topics touched include Chinese urbanization, United States LNG exports, Keystone XL Pipeline, Russian nationalization over its energy industry and its relationship with former Soviet Union countries.
An Integrated Life-Time Artificial Lift Selection Approach for Tight/Shale Oil Production
Authors: Khan N. , Ganzer L. , Elichev V. , Ali N.
Published: June 2014

The application of horizontal drilling coupled with hydraulic fracturing technology has enabled tight oil economic production from tight oil reservoirs (well known as "shale play"). In North America, tight oil production has emerged as a reliable crude oil source. The contribution from tight oil resources is expected to grow further and could share a significant amount of future energy demand. However, the challenge is to produce difficult reservoirs economically, and key enablers are identification of "sweet spots" and well placement optimization, improving drilling efficiency, optimizing stimulation treatment and decline rates/OPEX reduction.

The main challenge for long economical production is high decline rate –normally production rates could drop to 70 percent of initial rates after the first year. There are basically three reasons of such reservoir behavior: transient inflow effect, no pressure maintained and fractures deterioration. Handling of high variety of production rates with high efficiency is a significant challenge to artificial lift technique.

This paper presents an integrated life-time artificial lift selection approach to optimize bottom-hole pressure and production lifting efficiency and therefore minimize production OPEX. The methodology incorporates integrated fit-for-purpose modelling approach, with taking into account the most important factors like transient reservoir behavior, lifting efficiency, equipment reliability and economics. The procedure is based on production optimization by determination of artificial lift method change necessity over well life and optimal switching point finding. The main criterion for the technique selection is a generation of maximization of value (like NPV) with minimal risks over well-life within given production constrains.
Facilities Selection Impacts Reservoir Performance
Authors: Simpson David A
Published: June 2014

Facilities decisions are often disconnected from anticipated reservoir performance. A frequent result of this disconnect is operating reservoirs in a sub-optimum manner to protect surface facilities that have inadequate strength. This paper will review the facilities decisions that have been made in several Coalbed Methane (CBM) and Coal Seam Gas (CSG) fields around the world and discuss the reasons for and the impact of those decisions on the performance of the reservoirs. The source of the disconnect is that "everyone knows" that CBM and CSG fields "require very low pressures". With that assumption you then apply safety and procurement principles to come to a design. There is a stage in the production life of these fields where very low pressures are required for reasonable recovery levels, but that stage is typically reached 10-15 years after first production. Setting late-life surface facilities at first-production results in choking the reservoir for over a decade, setting compression many years before it is actually required, and less ultimate recovery as a percentage of original gas in place than would otherwise be achieved. These problems can be overcome by understanding the life cycle performance and risks of an unconventional reservoir and accepting that any tradeoff between facilities performance and reservoir performance must be biased in favor of optimizing reservoir performance in order to have acceptable economic results.
Impact of Storage Tax Credit on Economic Viability of CO2 Storage with EOR
Authors: Ettehadtavakkol Amin , Lake Larry W. , Bryant Steven L.
Published: June 2014

A partnership between oilfield operators and the federal government in the coupled CO2 enhanced oil recovery (EOR) and storage projects may bring long-term benefits for both. This paper quantifies the win-win condition for this partnership in terms of an optimum storage tax credit.

We introduce a basic conceptual model for the CO2 market and investigate the market sustainability conditions. We quantitatively show how the storage tax credit affects the optimum economic storage capacity of an oilfield as well as the benefits for the oilfield operator and the government. Two field-scale models for the EOR-storage operation are developed, namely Sandstone and Carbonate. The Sandstone model is tuned according to the top 10% performing West Texas CO2-EOR reservoirs while the Carbonate model is tuned according to the moderately performing reservoirs. The EOR-storage performance of the simulated Sandstone and Carbonate reservoirs is likely to be moderate to optimistic where the oil production performance is between 50 and 100 stbd/well and the CO2 utilization is between 5 and 10 Mscf/stb. Assuming $60/stb oil price and $80/tonne anthropogenic CO2 cost, the storage tax credit should be between 20 and $40/tonne to allow for an economically feasible EOR-storage operation and satisfy market sustainability (win-win) for both the oilfield operators and the federal government. Below this range, EOR-storage is infeasible and neither the operators nor the government gain benefits (lose-lose); above the optimum tax credit range the government spends too much while the operator gains benefits (lose-win). This study, however, does not consider the intangible social, economical, and environmental benefits of anthropogenic CO2 storage.
Design of Fiscal System for Exploration of Shale Gas: How is it Different From Conventional Oil and Gas?
Authors: Amorim LÍvia
Published: June 2014

Due to the success of shale gas developments observed in the US and the absence of domestic legislation specifically for unconventional gas projects in the countries, an arising question is whether replicating the fiscal terms conceptually conceived for conventional oil and gas exploration would be appropriate for the exploitation of unconventional gas deposits. To assess this issue, this study approached the question with a fiscal policy formulation perspective. It was assumed that a desirable fiscal system, able to balance opposed objectives from the Government and private investors would be a flexible, neutral and stable one, favourable to maximize the present value of the project. To address the question, this article makes a comparison between shale gas projects and conventional gas projects to examine if they have structures similar enough to be covered by the same fiscal regime or if the legislation needs to cover issues that are exclusive to shale gas projetcs. The analysis showed that, first, the basis of comparison would be better segmented between oil projects and gas projects – either from conventional or unconventional sources, since this last category has less margin of rent available to be taxed. Besides that, shale gas projects have particularities that should be considered by policy makers when designing a fiscal system to encourage its development. Furthermore, fiscal instruments can be a powerful tool to guide tax payers behavior and hence address other concerns not necessarily related to revenue-raising, bur, for example, environmental and social issues.