bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation Study of a New CO2-WAG-Based Method to Improve Oil Recovery of an Abandoned Water-Invaded Reservoir
Authors: Taheri R. S. S. , Tavakkolian M.
Published: July 2010

Active aquifer is one of the most common driving forces in a producing oil reservoir. But invasion of water from the aquifer into reservoir and raising the level of WOC cause a volume of oil to be remained in water-invaded zone, which is significant in most cases.

As a research, we studied on a field case with an active aquifer which has been encroached the oil zone till abandonment condition. As a remedy, after abandonment of the reservoir, we inject a miscible gas (CO2) to recover the remaining oil. It works like a one-cycle WAG injection, in which, water injection has been done naturally by aquifer and we continue the process by gas injection.

We investigated different gas injection scenarios to inspect the effect of this method on recovery of the oil remained in water invaded reservoir. This study shows that it is possible to increase the recovery factor considerably by choosing the right gas injection scenario. The feasibility study based on economical and surface facilities considerations would help us to select the best scenario.
Enhancements To GPS-Based Subsidence Monitoring At The Wilmington Oil Field
Authors: Baghdikian S. , Jepson J. D. , Henry M. J. , Holtz K. , Bock L. , Fayman J. , Mader G.
Published: July 2010

Subsidence was first identified in the Wilmington Oil Field in the 1940s. The City of Long Beach, Gas and Oil Department (LBGO) has been conducting surface elevation surveying using spirit leveling and, since 2002, the Global Positioning System (GPS). Recently, software for the LBGO Deformation Network of 12 real-time GPS stations was upgraded with new state-of-the-art technologies and solutions to provide more reliable and accurate continuous monitoring to support elevation survey campaigns. Current oil field waterflood management practices as they relate to surface elevation changes and benefits from the software upgrade for Wilmington Oil Field subsidence monitoring and control are discussed.

Waterflood operations in the Wilmington Oil Field are managed for effective oil recovery and injection/production balancing while maintaining stable surface elevations for continued regional economic growth. For cost-effective and timelier surface elevation monitoring, a real-time GPS network provides control for all LBGO subsidence monitoring activities. Using mobile GPS survey equipment, quarterly and semiannual elevations of over 240 bench marks are calculated from the 12 permanent GPS stations' elevations.

The LBGO GPS network and software allow for realtime elevation monitoring of key locations and automated data processing, with the regional picture updated semiannually. Surface elevation contour maps and individual survey bench mark elevation trends as a function of time allow for timely adjustments to the waterflood operations to maintain effective oil recovery.

Real-time GPS monitoring of surface elevations provides the capability for early detection of surface deformation resulting from production/injection imbalances. The necessary operational adjustments can then be identified and implemented to mitigate the situation. The advantage of early detection is in minimizing the extent of irreversible reservoir rock compaction, resulting in more stable future surface elevations and preventing elevation changes detrimental to surface infrastructure.
Rebutting Enhanced Oil Recovery by Cyclic Water and Oil Floods
Authors: Yu Li
Published: July 2010

In a recent work by Loahardjo et al. (2008), it was shown that a consistent trend of increase in oil recovery can be achieved by cyclic water and oil floods into an asphaltic reservoir. However, our experimental results obtained from strict one-dimensional two-phase flow at a low constant flow rate demonstrate that it is impossible to enhance the recovery under the same experimental conditions as theirs.

We find that the oil productions before and after water breakthrough consistently decrease in the subsequent injections (floods). The consistent decrease in oil recovery in the cyclic injections is confirmed both experimentally and theoretically, and comprised as follows: Less oil recovery before the water breakthrough is caused by colloidal asphaltenes that block the throats during the preceding oil injection. Consequently, the continuous large-throat-controlled domain shrinks and the pore-throat aspect ratio reaches the critical value in greater number of pores, so that less channels for the invading front and additional disconnection of oil by snap-off occurs during the subsequent water injection.Less oil recovery after the water breakthrough is caused by destruction of the asphaltene layers deposited on the solid surfaces by the preceding water injection, so that there is even more disconnection of oil by snap-off during the subsequent water injection due to the solid surfaces that have become more water-wet.

Furthermore, experiments in this work show that the original wettability can be restored only if the water-wetted channels in a rock are soaked with asphaltic crude oil under high temperature for a long time period. Therefore, under oil-field operational condition, the wettability of the oil formation will not be restored as much as it has been in the original reservoir, unless more heat is added into the recovered reservoir.
Horizontal Well Performance Flow Simulation CFD-Application
Authors: Zeboudj F.. , Bahi L..
Published: July 2010

An understanding of flow along horizontal wells can be important for reservoir management, specially: Tight and shale reservoir. As the completed length in such wells is considerably larger than that in conventional vertical wells, the flow field inside the wellbore can have a significant impact on the overall production characteristics of an oil reservoir. Flow in a well-bore is different from conventional pipe flow due to the presence of wall inflow (as in production wells) or outflow (as in injection wells), and this affects the wall friction, acceleration, and flow patterns inside the pipe. To better understand wellbore flow, Computational Fluid Dynamics (CFD) simulation has been used. A significant advantage of such simulation, besides the fact that they could potentially replace actual experiments, is that they offer a large amount of information on the turbulent velocity and pressure fields, the K-epsilon turbulent model was used to identify the entrance lenth and serve petroleum engineers to locate Pwf inside the horizontal drain for IPR calculation. One of the applications of such information is the development of new techniques in the perforation technology and fracturation of shale and tight reservoir, based upon FLUENT

(a commercial CFD software) simulations.
New Insights into Wormhole Propagation in Carbonate Rocks Using Regular, Gelled and In-situ Gelled Acids
Authors: Gomaa A. M. , Nasr-El-Din H. A.
Published: July 2010

It is well known that the efficiency of regular acid treatments goes through a maximum at an optimum acid injection rate where it gives the maximum wormhole propagation rate (ratio between wormhole length to pore volume of acid required to breakthrough). This rate is a strong function of the acid-rock reaction: diffusion of the acid to the rock, surface reaction, and mass-transport of the reaction products. Adding a polymer and other additives to the acid may affect the wormhole propagation rate. However, literature survey didn’t highlighted in details how the wormhole propagation rate will change when polymer and crosslinker will be existing with the regular acid. Therefore, the objective of this study is to determine the wormhole propagation rate of gelled and in-situ gelled acids as a function of the injection rate. The effects of temperature, lithology, and initial permeability on the wormhole propagation rate were considered in this work.

A coreflood study was conducted using calcite cores at temperature range 100 to 250 °F. Injection rate was varied from 1 to 20 cm3/min using 5 wt% HCl regular, polymer gelled, and in-situ gelled acids. Calcium, cross-linker, and acid concentrations were measured for the core effluent samples.

The wormhole propagation rate of gelled acid required was higher than regular acid where gelled acid required less acid volume to breakthrough. However, the wormhole propagation rate of in-situ gelled acid required was lower than regular acid where in-situ gelled acid required a higher pore volume to breakthrough. Three regions were obtained for the wormhole propagation rate of in-situ gelled acid as a function of the injection rate: Region I, where acid injection rate is low, and in-situ gelled acid wasn’t able to breakthrough from the cores at injection rate less than 5 cm3/min. Region II, where the acid volume required to breakthrough decreased as injection rate increased in the range between 5 and 10 cm3/min. Region III, where the acid volume injected increased with the injection rate at injection rate higher than 10 cm3/min. The optimum injection rate wasn’t affected by temperature, or initial core permeability. The volume required to breakthrough decreased as the temperature was increased, and as the initial core permeability increased.
Cost Per Foot Reduction by Bit Run Optimization: A Simulation Study
Authors: Ebrahimi M. , Noveiri E.
Published: July 2010

Weight on bit, rotary speed, bit hydraulics and more importantly bit types, are the most important parameters affecting rate of penetration and consequently the economics of drilling. Pulling a worn bit is necessary to make the drilling operations more efficient. Cost per foot calculation is a popular criterion used to predict when to pull a bit.

Simulation is a powerful tool to enhance drilling performance and thereby reducing total drilling cost. In this paper, the first 3 thousands feet of a reservoir lithology including four bit runs are simulated so that factors affecting penetration rate are optimized and the lowest possible well cost is achieved. The effects of using other bit types, weight on bit, rotary speed and bit hydraulics are simulated in an attempt to determine the optimized parameters, which result in the lowest drilling cost.

Overall, it was found that in bit runs 2, 3 and 4, a lower cost per foot can be achieved using milled tooth bits instead of tungsten carbide types. Furthermore, it can be concluded that by increasing weight on bit and reducing rotary speed in harder rocks, more favorable results are obtained while in softer rocks it is vice versa. In addition, by lowering both mud flow rate and nozzle sizes, hydraulic horse power dissipated at the bit is increased, hence decreasing cost per foot. These optimizations would save about 17% of the original well cost, which is a considerable amount of money.
Enhanced Estimation of Reservoir Parameters Using Decline Curve Analysis
Authors: Ebrahimi M.
Published: July 2010

Traditional decline curve analysis is an empirical procedure used mainly to predict recoverable reserves and future production rates, based on the boundary dominated declining rate. Modern (typecurve) analysis, however, are partially (Fetkovich) or fully derived analytically, based on reservoir fluid flow equations and assuming some simplifying conditions. Such typecurves are generally used for predicting reserves and future production rates as well as reservoir parameters.

In the current study, two cases have been analyzed using traditional and modern decline curves in an attempt to estimate key reservoir parameters. In the first case, an implicit reservoir simulator has been used for generating a set of declining rates for a well operating at ideal conditions, i.e. a homogenous cylindrical reservoir with isotropic permeability producing single phase oil at a constant bottomhole pressure. The generated data ware then used as an input for a decline curve analysis software to investigate the reliability and accuracy of estimated permeability, skin, and drainage area. In the second case, the declining rate of a real oil well is analyzed in terms of the previously cited parameters by the same software. The results of both cases indicate a good agreement between the actual and estimated parameters, with the Blasingame typecurve as the most accurate decline curve analysis technique.
Gas Lift Optimization in One of Iranian South Western Oil Fields
Authors: Ebrahimi M.
Published: July 2010

Gas lift is an artificial lift technique used to increase oil wells flow rate. In this method, high pressure gas is injected into the well oil column to reduce its average density and make it flow to the surface. The main objective in gas lift system design is to obtain the optimum gas injection rate. Obtaining the optimum gas injection rate is important because excessive gas injection will reduce production rate and also increase the operation cost. Some other parameters are also important in a successful gas lift operation that if not chosen properly, make the operation impossible or at least uneconomical; namely gas injection pressure, well head pressure, depth of operating and unloading valves, valves spacing, etc.

Field A, located in south-western Iran, has been producing oil for more than 60 years. Through that period, the early average oil production rate of 20 MSTB/D for each well has dropped severely by a factor of 8. At present, the field produces 185 MSTB/D through 73 active oil wells. However, the high reservoir pressure drop and continuous increase of water cut and gas oil ratio through the years, have influenced some of the wells to a greater extent such that the oil does not flow or flows at a lower rate than that of scheduled.

In this paper, nodal analysis is used to compare and analyze the effects of different parameters on a sample well production.Firstly, a model is constructed and matched with the real data and thereby the best fluid and well production correlations are selected. Secondly, Sensitivity analysis tests are performed and the results are compared. Finally, the optimum parameters are chosen considering economical aspects. By applying the stated optimizations of this paper, the flow rate can be increased by 80%.
Optimization of Sand Control for Unconsolidated, Shallow, and Low-Pressure Sandstone Reservoirs: A Suriname Case Study
Authors: Haskell J. B. , Toelsie S. , Mohan A.
Published: July 2010

Oil and gas production from unconsolidated sand reservoirs generally requires a production sand screen and usually a gravel pack in the well bore for optimum sand control. Existing criteria such as Tiffin, Saucier and Coberly have provided guidelines for conventional gap based filtration technology. However they do not apply very well to some newer technologies of today. Some of these newer technologies include Premium (2D) screens, with fusion-bonded laminates, or MeshRite (3D) screens with angular compressed metal fibers as Stand Alone Screen (SAS) completions. These screens may use multiple layers of wire mesh and a complex shaped pore opening, which result in retention performance quite different from conventional gap-based systems. Therefore with SAS completions, compatibility with the formation sand size is critical in providing optimum performance. Consequently it might be desirable to adjust existing criteria for specific types of reservoirs, in this case unconsolidated sandstone reservoirs.

A combination of SAS lab data with SAS field performance will show that existing criteria need to be adjusted specifically for unconsolidated sandstone reservoirs. A Staatsolie case study in Suriname will be presented to demonstrate the performance of these newer technology screens for specifically unconsolidated shallow-reservoirs. Staatsolie produces heavy oil from shallow, low-pressure, unconsolidated sandstone reservoirs. Wells are mainly completed as vertical open hole gravelpack with production based on progressive cavity pumps. Additional completion methods include cased hole/openhole gravelpacked and or screenless (SAS).

In the SAS pilot, 28 wells were completed with Premium or MeshRite screens. Of these, only in 6 wells fine formation sand production was measured.

Based on available Particle Size Distribution (PSD) data of 9 wells, a comparison is made between field and lab screen performance. These results will be matched up to Tiffin's criteria [8]. Based on summaries of these screen performance, guidelines for screen type selection for various completion scenarios will be developed for unconsolidated low-pressure shallow reservoirs.

Completion types to be covered in the analysis will be open and cased SAS, as the primary focus with respect to 2D and 3D screens applications.
Evaluation of Uncertainty Associated to Analytical Water Injection Models by Assisted History Match and Probabilistic Techniques
Authors: Sandoval P. , Ordoñez A. , Gomez A. , Perez E.
Published: July 2010

Implementation of probabilistic methods, in the analysis of the reservoir variables allow obtaining more realistic models and identifying opportunities that generate greatest impact on the models.This finally leads to obtain better a developing plan, supported in ranked desitions. Colombian Petroleum Institute (ICP) in 2003 developed the methodology ASIA (Advanced System Analysis for Injection) wich is an adaptation of CGM technic for the analytical modeling of water injection. Within it Areal and vertical distribution of water in the reservoir is modelated by the history match of the oil water ratio behavior. This paper shows the strategy used to incorporate the risk and uncertainty analysis to the ASIA methodology in order to obtain an assisted history match and a panoramic review of the parameters behavior.
A Unified Approach for Falloff and Buildup Tests Analysis Following a Short Injection/Production Time
Authors: Fuentes-Cruz Gorgonio , Camacho-Velázquez Rodolfo , Mario Vásquez-Cruz
Published: July 2010

Falloff/buildup tests with short injection/production time are common because of economical and operative reasons; there exist several works addressing the transient pressure tests analysis recorded under this flow conditions; however, there is no available a methodology that allows to analyze in an integral fashion the response observed under these situations. Furthermore, the two-region radial composite model (2RRCM), which considers an abrupt change in the properties of the concentric regions, is frecuently used.

This study presents a general methodology for analyzing falloff/buildup tests, particularly with short injection/production time; this methodology consists of a simultaneous match of the shut-in pressure change, superposition and normalized impulse derivatives of the test, by using the pressure drop, first and second drawdown derivatives of the model. Furthermore, a new radial composite model with a fractal transition zone (RCMFT) is also proposed for falloff tests, which considers an intermediate region with fractal behavior between the invaded zone by the injected fluid and the non-invaded homogeneous zone. New short-, intermediate-, and long-time approximations for the pressure response are introduced.

The results obtained with the proposed methodology are promising, since there is a better control on the flow model selection and parameters determination. The methodology is general for analyzing falloff/buildup tests, but it is particularly suitable in those cases where neither the conventional semi-log nor modern methods based on first derivative, can be applied. The RCMFT is helpfully for falloff tests in low mobility reservoirs, since it honors the flow dynamics occurring when an injected fluid displaces another one with lower mobility. From the field cases presented, there is evidence of the fingering phenomenon at greater scales than those ones of laboratory experiments. Therefore, it is recommendable to incorporate these tools into the transient pressure analysis workflow.
New Technology in the Bakken Play Increases the Number of Stages in Packer/Sleeve Completions
Authors: Buffington Neil , Kellner Justin , King James G. , David Betsy , Demarchos Andronikos , Shepard Louis
Published: July 2010

The Bakken, one of the last giants to be discovered in North America, extends from Montana through North Dakota and into Saskatchewan and Manitoba provinces in Canada. The USGS, in its latest study published in April 2008 (USGS 2008), estimates that the undiscovered US portion of the Bakken Formation holds 3.65 billion barrels of oil, 1.85 trillion cubic ft of associated gas and 148 million barrels of natural gas liquids. Being classified as an oil play dependent on full well-cycle margin efficiencies to increase profitability, technology will be a main driver in the success of the development of the Bakken.

Two technologies that have been critical to the current success of the Bakken are: horizontal drilling and hydraulic fracturing. Operators typically drill on 640 or 1280 acre spacing. Typical 1280-spaced lateral lengths are over 9,000 ft, at a total vertical depth (TVD) of 9,000 ft (Miller et al., 2008). Once extended reach horizontal drilling was proven reliable, attention was turned to optimizing production from these laterals. This paper will present an enhancement to an existing technology that enabled the operator to vastly increase the effective flow area created by staged hydraulic fracturing. In the process of bringing this technology to market, both the service company and the operator agreed that the true value-adding function was the process that enabled an expediting of the product from concept to implementation.

The development of new technology by service companies is critical for operators to expand their operations, drive operational efficiency, and work profitably in ever harsher environments that are lower on the resource triangle (Fig. 1) (Masters and Grey 1979). Product development is sometimes performed by service companies with requirements gathered from several operators, while at other times service companies will develop products specifically to meet the needs of a single operator. This paper will describe a synthesis of these processes, and the design and testing hurdles encountered, for a project that met the needs of both a single operator and the service company. The product is expected to provide continued benefit throughout the Bakken drilling and completion campaign for this operator, as well as provide a solution for the broader market for the service company. As a result of this collaborative effort, a new product was conceptualized, developed, lab tested, field tested, and taken to market in an accelerated time frame.

Fig. 1 Resource Triangle.
Adding Value to Gas Lift Evaluation With Minilogger Tools
Authors: Friedli J. , Rivas C.
Published: July 2010

Recent market entry of compact, integrated, "minilogger" type tools has created opportunities for improving the quality and quantity of data acquired in conventional BHPT surveys, with significant added value for gas lifted flowing surveys. These memory tools typically comprise a pressure gauge plus a high resolution borehole temperature probe and CCL. The total package is about the same size as a traditional tandem BHP gauge assembly, and may include a small spinner. When running a minilogger in place of BHP gauges, there have been predictable as well as unexpected benefits realized.
New Software for Opex Estimation: Cost Driver Estimation (Code) Tool With Montecarlo Risk Analysis Simulation
Authors: Boccardi A.. , Giubileo A.. , Cadegiani C..
Published: July 2010

CODE tool is a software built by Eni used to calculate both on and off-shore production plants OPEX estimation during the project development and operations phases. The tool from a database used as reference baseline, through specific algorithm give as output the estimation of the all life cost structured coherent with the Activity Based Costing Methodology.

The application is divided into:a database for the technical data and the unit costs subdivided by countries;an environment for plant construction;an environment for the definition of the country coefficients and the project parameters;a section dedicated to the visualization and analysis of the results.

The user defines, through a series of interface dedicated, all the parameters and the configuration of the project, including the type of process, production forecast, fluids, plants, contract strategy, transportation costs and logistics strategy.

The software could be interfaced with other applications for the dynamic management of the operating costs in the production phase, supplying, on the predictive base, the initial input of the data and utilizing the successive data processed as feedback for baseline updating.

At the end, in order to evaluate the uncertainties and to monitor the more sensitive parameters the obtained results have been modeled through a Montecarlo risk analysis simulation.
An Integration Approach for Evaluating Well Deliverability in Ultra Deep Sands
Authors: Xiao Guo , Jingjing Ma , Yiwei Chen , Weixin Liu
Published: July 2010

Deep and ultra deep low-permeability reservoirs are widely distributed in the South China Sea, such as HuiZhou 19–1, 26–3, 9–2 oil field and PanYu 34 gas field. These ultra deep reservoirs generally performed as deep burial depth, low porosity, low permeability, which lead to difficulty in evaluating well deliverability. DST is a fast and valid well test method for deep sands. The DST showed that layer M-31 of well HuiZhou 19–1 had a relatively higher productivity. However, the layer M-32 with the same perforated thickness only produced about 1.6 m3 each day. While the layer M-32 and M-31 has a vertical distance of about 25m and similar porosity and permeability. In order to evaluate well deliverability of layer M-32 and M-31, effect of mineral components and pore structure on DST was analyzed. 13 groups of start-up pressure and 13 groups of stress-sensitive experiments were also carried out. This work indicated kaolin clay in the soil minerals of layer M-32 damaged the formation and had an important impact on well deliverability from DST. In addition, layer M-32 offered an relatively high start-up pressure gradient, which reached the magnetite of 10–1 to 10–2. When effective stress was more than 15 MPa, the porous media would begin to deform seriously. The integrated approach indicated optimized production of the layer M-31 and layer M-32 of well are 2413.1 m3/d and 86.39 m3/d respectively. Numerical simulation also showed that enlarging producing pressure drop, hydraulic fracturing and horizontal wells can further improve well deliverability of deep and ultra deep low-permeability reservoirs. The study also suggested effect of kaolin clay and start-up pressure gradient on DST should be considered correctly.
Optimization of Carbon Dioxide Sequestration and Enhanced Oil Recovery in Oil Reservoir
Authors: Jahangiri Hamid Reza , Zhang Dongxiao
Published: July 2010

Carbon dioxide (CO2) storage into depleted or partially depleted oil reservoirs is an immediate option for reducing CO2 emissions into the atmosphere. This process, if implemented in depleted oil reservoirs, combines environmental benefits of reducing CO2 emissions and economical benefits of maximizing oil recovery. CO2 Enhanced Oil Recovery (EOR) processes, to date, have attempted to minimize the amount of CO2 needed to recover each barrel of oil. For a sequestration process, however, the aim is to maximize the amount of CO2 stored. If CO2 emissions are regulated, CO2-EOR process may therefore be able to earn sequestration credits in addition to oil revenues.

This paper discusses the effects of several injection strategies and injection timing on optimization of oil recovery and CO2 storage capacity for a synthetic, three dimensional, heterogeneous reservoir models. A simulation study was completed using a 3-D compositional simulator “ECLIPSE 300” in order to optimize oil recovery and CO2 storage. The study proceeded through the following steps: 1) comparison of different injection schemes; 2) testing the effect of injection rate on the CO2 storage capacity. The results show that innovative reservoir engineering techniques are required for cooptimizing CO2 storage and oil recovery.
Feasibility Investigation of CO2 Miscible Flooding in South Slattery Minnelusa Reservoir, Wyoming
Authors: Gao P. , Towler B. , Jiang H.
Published: July 2010

A study using experiment and full-field reservoir modeling investigated and optimized the design of a CO2 miscible flooding project for the Minnelusa reservoir of the South Slattery field. The study began with extensive data gathering in the field and building a full-field three-dimensional geologic model. A fullfield simulation model with relatively coarse gridding was subsequently built and used to history match the depletion and waterflood. This history matching model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. The estimation of minimum miscibility pressure was conducted with the slimtube method. A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood. Continuous CO2 miscible injection and alternating were simulated. CO2 WAG injections were simulated mainly to observe the improvement of low sweep efficiency caused by override and unfavorable mobility ratio. Main considered sensitivities included the WAG ratio and slug size. The integrated recovery efficiency comparison of CMI and WAG was used to demonstrate the mobility control of the WAG process.
Effect of Interstitial Water Saturation and Air Flux on Combustion Kinetics of High Pressure Air Injection HPAI
Authors: Barzin Y. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Tabasinejad F.
Published: July 2010

High Pressure Air Injection (HPAI) in deep light oil reservoirs has received notable attention in the last three decades after its successful field application in 1979. Kinetics of the oxidation reactions associated with HPAI are important for understanding the mechanism which control the overall performance of air injection processes; however, they are not yet fully defined. This paper describes the results of an experimental study conducted to characterize some main parameters which impact the reaction kinetics of light oil oxidation/combustion in HPAI.

Vaporization of oil has been recognized as important mechanism controlling the nature of the residual oil that is the source of the fuel for light oil combustion; however, the parameters controlling vapor phase oxidation/combustion have not been included in the studies of oxidation kinetics. Interstitial water saturation plays an important role on phase behavior and heat transfer and consequently the reaction kinetics. However, there is no reported data in literature investigating this factor.

This study aims to shed light on these unknown aspects of light oil air injection (HPAI). Several oxygen and nitrogen injection experiments have been performed on a recombined light oil and also a pure oil component sample in a 45 cm long, high pressure ramped temperature oxidation (HPRTO) reactor. Experiments were run in the presence and absence of interstitial water at two different levels of air and nitrogen injection flux. This paper concentrates on selected tests which highlight the effects of interstitial water, injection flux, and oil type on oxidation/combustion behavior of light oils under HPAI.

An endothermic evaporation front was observed to precede the thermal front in low flux air injection tests. Interstitial water saturation had a major contribution to endothermic heat of vaporization and the tests with no recombined water barely developed a distillation wave. Observations in this study highlight the significant impact of phase behavior on oxidation/combustion behavior of light oils in HPAI.
Evaluation of a Deposit at the PBU L-106 Site, North Slope, Alaska, for a Potential Long-Term Test of Gas Production From Hydrates
Authors: Moridis G. J. , Reagan M. T. , Boyle K. , Zhang K.
Published: July 2010

As part of the effort to investigate the technical feasibility of gas production from hydrate deposits, a long-term field test (lasting 18–24 months) is under consideration in a project led by the U.S. Department of Energy. We evaluate a candidate deposit involving the C-Unit at the PBU-L106 site in North Slope, Alaska. This deposit is stratigraphically bounded by impermeable shale top and bottom boundaries (Class 3), and is characterized by high intrinsic permeabilities, high porosity, high hydrate saturation, and a hydrostatic pressure distribution. The C-unit deposit is composed of two hydrate-bearing strata separated by a 30-ft-thick shale interlayer, and its temperatrure across its boundaries ranges between 5 and 6.5 °C.

We investigate by means of numerical simulation involving very fine grids the production potential of these two deposits using both vertical and horizontal wells. We also explore the sensitivity of production to key parameters such as the hydrate saturation, the formation permeability, and the permeability of the bounding shale layers. Finally, we compare the production performance of the C-Unit at the PBU-L106 site to that of the D-Unit accumulation at the Mount Elbert site, a thinner, single-layer Class 3 deposit on the North Slope of Alaska that is shallower, less-pressurized and colder (2.3 − 2.6 °C). The results indicate that production from horizontal wells may be orders of magnitude larger than that from vertical ones. Additionally, production increases with the formation permeability, and with a decreasing permeability of the boundaries. The effect of the hydrate saturation on production is complex and depends on the time frame of production. Because of higher production, the PBU-L106 deposit appears to have an advantage as a candidate for the long-term test.
A Novel Electrokinetics Method of Oilfield Scale Control In-situ
Authors: Haroun M. , Ghosh B. , Chilingar George V. , Wittle K. , Pamukcu S. , Badawi M. Al
Published: July 2010

Sulfate scaling in the oil well and near wellbore formation is a common phenomena in a waterflood operation where seawater rich in sulfates mixes with formation water rich in Ba, Sr and Ca ions. This gives rise to frequent well intervention for chemical squeeze and well cleaning operation. Apart from production loss, this could lead to a significant addition to production cost in offshore operations. To find a long term solution for this commonly occurring problem, we experimented on a novel idea of using DC current to reduce scaling. The concept of electrokinetic scale remediation in oilfield was conceived during our successful experience with electroremediation of heavy metals in highly-contaminated coastal sediments of Abu Dhabi where di & tri-valent cations were separated from sediments by applying DC current.

In the present study, we focused on barium sulfate, BaSO4 scaling through a series of experiments conducted in a sand-packed glass cell with variable electrode positioning and fluid injection options. DC power was applied at a fixed 2V/cm potential gradient through a constant electrode configuration used in all tests. The injector sites, where 500 ppm Ba and 500 ppm SO4 solutions were injected to the system were used as anode locations, while the production outlet was used as the cathode location. The NaCl concentration of the formation fluid were varied from 0 to 40,000 ppm and the rate of flow was set at 1 ml/min. Results of pressure build up due to the scale deposition were compared with those from the DC electric field system. The results showed that under DC electrical current, scaling rate reduced by up to 60% at the production outlet. Chemical analysis of scale deposits at various points showed high localized concentration distribution throughout but 50% or less deposition near the production well.
Deepwater DST Design, Planning and Operations—Offshore Niger Delta Experience
Authors: Mogbo Obuekwe
Published: July 2010

This paper focuses on the complex design, planning and operational aspects for a case study appraisal deepwater well in the Niger Delta, offshore Nigeria. The objectives of the Drill Stem Test (DST) were to plan and execute safe operations, determine well performance and reservoir properties whilst overcoming the challenges of gas hydrate formation and sand production from an unconsolidated formation.

Exploration activities are high in the emergent West Africa deep offshore region leading to regular execution of DST’s. However the peculiarities of the locality transform the design, planning and operations involved in execution of such deepwater DST’s into complex challenges. The ability to successfully design, plan and engineer the operations of such tests to obtain relevant results becomes crucial because the accurate determination of well performance and evaluation of reservoir properties of the West African complex faulted reservoirs often prove to be game changers in the development decision making process.

The paper begins with a brief discussion of the DST design methodology: simulation of different test scenarios based on prognosed reservoir properties, rate and test sequence definition. The contingent DST design is updated with changes to its data assumptions based on actual well results. Secondly, the planning for the DST project is described including: rig choice, perforation, sand control, downhole completions, tool and equipment choices etc. Furthermore, the operations are described: hydrate inhibition process, equipment layout for DST package, data acquisition and fluid sample acquisition.

This paper contributes a demonstration of how in a studied field case, careful design and innovative planning of the operational aspects of a deepwater DST ensured that targets were delivered so that pressure transient analysis yielded crucial information regarding well productivity, reservoir properties and boundaries.
Fluid Temperature as a Design Parameter in Carbonate Matrix Acidizing
Authors: Kalia Nitika , Glasbergen Gerard
Published: July 2010

One of the methods to stimulate a carbonate formation involves injecting acid into the matrix under fracturing pressure and dissolving near wellbore damage. The reaction of acid with the soluble carbonate matrix results in the formation of dissolution structures that depend on several factors like injection rate, formation mineralogy, reaction chemistry of the acid, temperature conditions, etc. The effect of temperature on carbonate dissolution has been illustrated in the past by conducting laboratory experiments at different temperatures. It has been shown that depending on the reaction kinetics for a given fluid and formation, the effect of temperature on wormhole formation varies. For instance, in hydrochloric (HCl) acid-limestone system, the acid volume required to achieve a given permeability increase or skin decrease has been shown to increase as the temperature is increased. On the contrary, in HCl-dolomite system, the effect of temperature is more complex and depends on the injection rate. A clear understanding of the effect of temperature on different types of formations and injection fluids is still not available.

In this work, a mathematical model is used to investigate the effect of temperature on carbonate matrix acidizing. It is shown that an optimum in temperature occurs in terms of minimum acid volume and optimum injection rate. In particular, fluid temperature has been identified as a design parameter and its importance is illustrated by simulating injection of acid at a temperature different from the formation.

Considerable number of current carbonate reservoirs are high temperature, making it imperative to understand the effect of temperature on acidizing design. The results from this work translate directly into recommendations on using temperature as a design parameter in matrix acidizing for varying formation and fluid conditions.
Oilfield Automation Using Intelligent Well Technology
Authors: Pande Anil , Morrison Mark , Bristow Richard
Published: July 2010

With oilfield exploration and production in increasingly hostile and remote locations, the use of intelligent fields is essential for ensuring enhanced recovery, reduction of operating costs and increased profitability. An intelligent field is essentially a partially or fully automated oilfield, with real-time data flowing from the wells in the field, that enables monitoring and control for immediate operational needs and also for longer term optimization requirements. Basic oilfield automation consists of sensors that send data to monitoring systems, which is then used for immediate control of those operations. Further optimization occurs when the same data is sent onwards via communication links to onshore applications and processes, for more advanced management of the oilfield, such as production optimization, reservoir management etc. In essence, intelligent wells allow remote, centralized management and collaboration for the wells, by domain experts who can leverage all of the intelligence available in the operations environment for their decision making. This is the key to achieve the ultimate goal of recovering optimal hydrocarbons at the lowest cost.

Intelligent wells become the new basis for decision making by oilfield engineers, by using the collected data and information, and by monitoring, visualization, decision making and control. The key to success in this area is answered by questions such as: Does your intelligent well system provide the proper information, and not just data that you need to make good decisions in field management? Does your environment have the necessary technology that can, for example, search for and easily find relevant information, detect complex data patterns and problems and leverage it as usable knowledge to empower decision makers?

This paper covers oilfield automation by considering the different technology disciplines as ‘layers’, that are needed for the intelligent fields, such as sensors and controls, connectivity and data transmission, data access and finally making the data work. The discussion is from a production point of view for high value offshore wells, but the principles can just as well be applied to other scenarios.
Friction Pressure Losses of Surfactant-Based Fluids Flowing in Coiled Tubing
Authors: Kamel A. H. , Shah S. N.
Published: July 2010

In spite of surfactant-based (SB) fluids wide use as friction reducer and/or fracturing fluid in the oil and gas industry, the flow data in large pipe sizes as well as coiled tubing are very scarce. Majority of the available flow data are gathered in small size straight tubing. The present study involves experimental investigation on the flow properties of aqueous surfactant-based (SB) fluids in small and large-scale coiled tubing. The unique viscoelastic properties of SB fluid affect their flow behavior in large pipe sizes. This phenomenon is called as "diameter effect" or "scale-up factor".

The properties of widely used Aromox APA-T, a highly-active surfactant used as a gelling agent in aqueous and brine base fluids, are thoroughly investigated. Rheological measurements are conducted using Bohlin rheometer for SB fluid concentration of 1.5, 2, 3, and 4 vol. %. Flow data are gathered using ½, 1½, 2⅜, and 2⅞-in. OD coiled tubing with various curvature ratios.

The results show that SB fluids exhibit non-Newtonian pseudo-plastic behavior. Elastic and viscous properties of SB fluids are very sensitive to surfactant concentration. Friction losses in coiled tubing are significantly higher than those in straight pipes due to secondary flow effect. Increasing curvature ratio yields higher friction pressure losses. Also, small-scale data correlations using only simple power law model fluid rheological parameters lead to erroneous results when scaled-up to a large pipe sizes.

New technique, based on the modified Deborah number, including fluid elasticity and pipe shear effect, has been developed to correlate data from the small laboratory-scale tubing and large field-scale pipes. Correlation to predict Fanning friction factor of SB fluids in coiled tubing as a function of Deborah number and fluid flow behavior index is presented. Correlation is validated by comparing predictions with the experimental data. It is shown that the new correlation accurately predicts friction factor of SB fluids and thus alleviates the scale-up issue.
Experimental Study to Find Optimum Pressure for Separation of Wellhead Fluids
Authors: Fazaelizadeh M.. , Mirhaj S. A. , Bahari-Moghadam M.. , Bahonar M.. , Chen Z..
Published: July 2010

The oil industry deals with wellhead fluids which are a mixture of hydrocarbons, water and impurities. In a two-phase separator design, the gas and liquid phases of a fluid stream are separated at a specific temperature and pressure. A proper separator design is important, because a separation vessel is normally the initial processing vessel in the surface facilities. Improper design can bottleneck and reduce the capacity of the entire facilities. The optimum separator pressure is defined as the pressure at which the maximum liquid volume is accumulated in the stock tank per volume of the feeded reservoir fluid.

The objective of this study is to find the optimum pressure in a single stage separation for the oil that was sampled from a well head at 300 psia by a "flash equilibrium separator". This type of sampling technique enables to determine gas-oil ratios and shrinkage by a flash liberation or vaporization method. A bottom hole or recombination sample is expanded from above its bobble point pressure into a chamber which is equipped with a back pressure and temperature controller. The volume of gas librated is measured with a gas meter at the atmospheric condition while the liquid volume is measured in the separator chamber. Then the liquid is drained and its gravity is measured.

In this paper, by using the "flash equilibrium separator", "gasometer" and "densimeter" apparatuses, the optimum pressure for an Iranian oil sample is obtained and also the gas-oil ratio, oil formation volume factor and residual oil gravity are depicted all as a function of the separator pressure at the desired temperature.