bluuebunny/crossref_metadata_2025 huggingface dataset:
The Displacement of Viscous Oil by Associative Polymer Solutions
Authors: Buchgraber M. , Clemens T. , Castanier L. M. , Kovscek A. R.
Published: October 2009

About half of world oil production results from waterflooding. The remaining resources, however, are more viscous and less amenable to waterflood as conventional oil reserves are produced. In offshore and Arctic environments improved methods of cold production for viscous oil are needed because the introduction of heat to thin viscous oil appears to be unlikely. Unfavorable mobility ratio and sweep is modified by use of polymer solutions. Of the various EOR polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer solution/oil displacements in a two-dimensional etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed polyacrylamide solutions and newly developed associative polymer solutions with concentrations ranging from 500 ppm to 2500 ppm were tested. The crude oil had a viscosity of 210 cP at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water breakthrough and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width to length ratio of these fingers was quite small and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after water flooding. The associative and conventional polymer solutions improved oil recovery by about the same amount. The associative polymers, however, showed more stable fronts in comparison to conventional polymer solutions.
Producing Heavy Oil by Thermal Progressive Cavity Pump in Steam Stimulation Process
Authors: Zhang Shoujun , Zhong Liguo , Song Fujun , Lang Baoshan , Wu Fei , Luo Enyong
Published: October 2009

As a new potential mean of artificial lift production, production using progressive cavity pump (PCP) has many advantages such as energy saving, lower first investment, and convenient in management. However, it is more challenging to implement this lifting method to thermal production of heavy oil for the temperature limitation of elastomer stator and bonding agent, and hostile temperature vibration in the wellbore environment, as a result, up to date, there is no application of PCP to thermal heavy oil production in Liaohe Oilfield which is the largest heavy oil field in China.

An applicable thermal PCP developed based on extensive testing is introduced in this paper. It involves an applicable thermal fluororubber stator and bonding agent which could operate under high temperature conditions (up to 210°C) enough for the thermal requirement of steam injection, and great temperature vibration condition in the wellbore ranging from 80°C to 210°C. The whole top-drive thermal pumping unit is designed in consideration of thermal wellbore environment in heavy oil production procedure of steam stimulation.

The thermal PCPs have been applied to 5 wells and detailed field testing dynamic is monitored and investigated. Favorable performance of the thermal pumping unit is observed in the rugged production environment (the measured wellbore fluid temperature is up to 165°C) for more than 6 months, and the pump efficiency is about 60%~70%. Compared with the conventional rod pumping lift production, about 20% increase in periodical cumulative oil production and 50% lower horsepower requirements is obtained.

In summary, the developed thermal progressive cavity pump is feasible for heavy oil production in steam stimulation process, which could operate under extensive temperature range, and the upper limitation is up to 210°C.
Simulation of Multiphase Non-Darcy Flow in Porous and Fractured Media
Authors: Wu Yu-Shu , Lai Bitao , Miskimins Jennifer L. , Di Yuan
Published: October 2009

A Buckley and Leverett type analytical solution is derived for non-Darcy displacement of immiscible fluids in porous media, in which non-Darcy flow is described using the general model proposed by Barree and Conway. Recent laboratory studies and analyses have shown that the Barree and Conway model is able to describe the entire range of relationships between rate and potential gradient from low- to high-flow rates through porous media, including those in transitional zones. We also present a general mathematical and numerical model for incorporating the Barree and Conway model to simulate multiphase non-Darcy flow in porous and fractured media, while flow in fractured rock is handled using a general multi-continuum approach. The numerical solution of the proposed multiphase, non-Darcy flow model is based on a discretization scheme using an unstructured grid with regular or irregular meshes for multi-dimensional simulation. The final discretized nonlinear equations are handled fully implicitly with the Newton iteration. As an application example, we use the analytical solution to verify the numerical solution for and to obtain some insight into one-dimensional non-Darcy displacement of two immiscible fluids according to the Barree and Conway model. Overall, this work provides an improved platform for modeling multiphase non-Darcy flow in oil and gas reservoirs, including complex fractured systems such as shale gas reservoirs.
The Application of High-Density Elastic Cements to Solve HPHT Challenges in South Texas: The Success Story
Authors: Wray Barry , Bedford David , Leotaud Lennox , Hunter Bill
Published: October 2009

Well cementing operations in south Texas tend to present a number of challenges to those responsible for constructing oil and gas wells. For instance, the temperatures and pressures at which the cement needs to be placed can be extreme, routinely exceeding bottomhole static temperatures of 300°F and pore pressures requiring fluid densities of 17 lbm/gal or greater to maintain well control. These extreme conditions can present challenges not only during placement of the cement slurry in the wellbore, but also later to the set cement sheath during the life of the well.

To effectively meet these challenges, well operators in south Texas have been using high-density cements that have been mechanically modified so the set cement will be more elastic and resilient. Advanced diagnostic software is used to predict well situations where these cements are required.

Currently, high-density elastic cements (HDEC) have been placed in more than 40 wells in southern Texas and the use of these sealants combined with diagnostic software has become routine.

This paper discusses the challenges presented when cementing high-temperature, high-pressure (HTHP) wells in south Texas, then details the successful best practice life-of-the-well solutions that have been applied by highlighting two representative examples.

The purpose of this paper is to help assist those tasked with the construction of HTHP wells to achieve their objectives safely and reliably and deliver zonal isolation that can be expected to last for the life of the well.
Environmental Considerations of Modern Shale Gas Development
Authors: Arthur J. Daniel , Bohm Brian , Cornue David
Published: October 2009

The Barnett Shale play of the Ft. Worth Basin has sparked considerable investment in the Woodford, Fayetteville, Haynesville, and Marcellus Shales, as well as in other shale plays. Key to developing these unconventional natural gas resources is the management of water and other environmental issues facing the developers active in these plays including water availability, water handling/transport, hydraulic fracturing and management of fracturing fluids, water disposal, urban drilling, NORM, and other environmental considerations. This paper will discuss these environmental considerations and challenges related to modern shale gas development in several major plays within the United States, as well as the potential impacts of the expanding public concern regarding shale gas development, and practices and solutions implemented to facilitate ongoing development.
An Alternative Method of Dealing With Pressure: Friction Reducer for Water Packing of Long Horizontal Open Holes in Low-Fracturing-Gradient Environments
Authors: Baser B. , Shenoy S. , Gadiyar B. , Jain S. , Parlar M.
Published: October 2009

Water packing is the most commonly used gravel packing technique for openhole horizontal completions. With this technique, the packing of a horizontal well occurs through two sequential events, called the a-wave and the β-wave. Because the carrier fluid is diverted into and must travel through the narrow annulus between the screen base-pipe and the wash-pipe all the way to the toe, pressure builds up steadily during the β-wave as the packing proceeds from toe to heel, due to high friction pressures in that annulus. This rise in pressure may result in exceeding the fracturing pressure of the reservoir, which in turn causes a premature screenout and an incomplete gravel pack.

This is a well known problem, which in the past often limited the horizontal well length that can be gravel packed in many deepwater developments, due to narrow operating window. Today, various solutions are available to solve this problem, including mechanical solutions that create a short cut for fluid returns, and the use of light weight gravel which allows pumping at lower rates without having to worry about gravel settling in the work string but still have a a-wave height that will cover the screens.

In this paper, we present an alternative method of dealing with the pressure rise during the β-wave, reducing the friction pressures through addition of a friction reducer to brine carrier fluid. We first detail the laboratory scale experiments used for screening of many additives considered, including laboratory scale friction pressure measurements, compatibility with high density brines, gravel settling, formation and gravel pack damage. We then discuss the results from full scale friction tests conducted in pipe and annular geometries, using the best candidate friction reducer selected based on laboratory tests. The results indicate that a drag reduction of 40 to 50% is attained with an environmentally friendly friction reducer, with retained permeability of about 90%, and with minimal to no impact on gravel settling and thus a-wave height.
A Study on Peer Assessment of Teamwork Projects in Undergraduate Petroleum Engineering Education
Authors: Cinar Yildiray , Bilgin Ayse A.
Published: October 2009

This paper presents an analysis of the peer assessment data collected for assessing teamwork projects assigned in four petroleum engineering courses offered at the University of New South Wales. Term projects were given to 22 groups composing from 4 to 7 students. Each team was asked to search for an open-ended discipline-specific problem, formulate the problem, provide solutions to the problem and present the outcome through a technical report and an oral presentation. An assessment value of 30% of the total was allocated to the projects. The teamwork performance, technical report, and oral presentation were assessed to determine the total marks for the groups. A peer assessment survey was then undertaken with the main aim to derive the individual marks. The peer assessment was based on logistics, leadership, group dynamics, intellectual and research/writing/editing.

The collected data represents a wide range of groups composed of various student profiles which include international and local students, male and female students. The analysis emphasizes the peer assessment as a viable tool for evaluating the individual contributions to a discipline-specific teamwork project. However, the human bias must be adequately adjusted for fair assessments. The study demonstrates that poorly performing students in the groups can be identified by utilising peer assessment. However, this also requires the judgement of the lecturer based on the observation of team members through weekly meetings and the minutes taken during the team meetings. The international students seemed to be more generous than the local peers in the assessment. It was determined that a significant number of students (about 40%) gave the highest marks to peers for all assessment criteria. In four groups out of 22 groups, all team members gave the highest rates to each other for all criteria, which made the peer assessment entirely useless. Three of these four groups were composed of international students only. All these observations underline the necessity to train the students for the importance of the peer assessment.
Coupled Thermo-poro-mechanical Effects on Borehole Stability
Authors: Zhai Zongyu , Zaki Karim S. , Marinello Steve , Abou-Sayed Ahmed
Published: October 2009

A new model and numerical scheme are developed to study the effects of poro-elasticity and thermo-elasticity on borehole stability. The poro-thermo-mechanical model integrates the effects of both thermal and hydraulic diffusion in determining the effects of the drilling fluid and mud weight on the borehole system.

Thermal diffusion into shale formations occurs quicker than hydraulic diffusion, thereby dominating pore pressure changes during early time. The thermal differential can affect shale stability in two ways: The differential-driven thermal diffusion induces additional pore pressure that adds to the poro-elastic stress change near wellbore.The thermal differential directly induces a change in rock stresses.

Previous publications have adequately investigated and addressed the second of the two issues. The current work attempts to model and assess the impact of the first mechanism.

In the model, thermal diffusion is coupled with hydraulic diffusion to obtain the pore pressure distribution reflecting the cumulative impact. The generated poro-elastic and thermo-elastic stresses are obtained by solving equilibrium equations utilizing superposition.

A field case is included in this paper and shown that the thermo-elasticity adversely would affect the borehole stability.
A Comprehensive Study of Sanding Rate From a Gas Field: From Reservoir, Completion, Production, to Surface Facilities
Authors: Han Gang , Shepstone Keith , Harmawan Iwan , Er Ufuk , Jusoh Hasni , Lin Lim Sue , Pringle Dave , Koya Rani , Carney Stephen , Barker Larry , Morita Nobuo , Papamichos Euripides , Cerasi Pierre , Sayers Colin , Heiland Juliane , Bruno Mike , Diessl Julia
Published: October 2009

An offshore gas field has been producing sand for a few years. Sand production has been closely monitored through acoustic flowline devices and a sand collection system installed on the platforms. Observation of sand production has triggered evaluation of whether to install surface desanders or complete future wells with downhole sand control. This evaluation requires a prediction of sanding rate over the reservoir life. The possibility of providing downhole sand control on existing wells was also evaluated in separate studies.

Predicting sanding rate, particularly for gas fields, has been historically challenging, mainly because of the sporadic nature of sand production, inadequate quantification of fundamental physics, and lack of representative lab tests, and reliable field calibration. To tackle these challenges, four studies have been designed and executed, including 1) the development of a reliable log-based rock strength estimate; 2) the prediction of sanding rate over the reservoir life for a conservative well condition; 3) the evaluation of sand particle transport from the reservoir to the surface facilities; and 4) the estimate of potential erosion of platform facilities.

The sanding rate prediction is based on extensive laboratory tests of four carefully selected whole cores, with gas and water flow. It has then been validated by field monitoring data from an acoustic flowline device on each producer and a sand collection system on the platforms. The studies have provided a prediction of future sand production, how much of the produced sand will be seen at the surface (and therefore how much of it will fall into the rathole), how fast various components of the surface facility will erode over the field life, and what will be the optimal completion strategy for sand control should it become necessary. They have provided input to an integrated evaluation of completion design, reservoir management, platform configuration, and field economics.
Production Optimization of Horizontal Wells in a Heavy-Oil Field
Authors: Qinghong Y. , Lizhen G. , Peng Z. , Thomas T. , He G. , Li X. , Tong Y.
Published: October 2009

In this paper we detail the work done in production optimization of a heavy oil field by detailed analysis of the geological, reservoir and production data with the intent to optimize the production performance of the horizontal wells in the field. We study the geological, reservoir and production factors, like extent and thickness of barriers to flow, net thickness cut off, water flow mechanisms in the reservoir, production history, production diagnostics and finally the placement criteria of new horizontal wells in order to optimize the field production.

A combination of geological, reservoir and production factors are considered to study the reservoir flow mechanisms and creation of diagnostic plots to study the well inflow mechanisms. The well inflow findings are substantiated by streamlines which track fluid inflow. The outcomes of the above process provides the engineer a comprehensive set of tools to monitor, diagnose and take appropriate actions for production optimization of the horizontal wells.

Through the work done we were able to identify the reservoir thickness cut off, critical rate, optimum drawdown, length of horizontal wells and well window for optimum production and delaying water coning which compromises optimal production. The water inflow mechanisms were validated by using streamlines for the fluid tracking and hence recommend appropriate remedial actions with greater confidence. The approaches taken towards production optimization were different for the bottom water and edge water reservoirs as is detailed in this study. The paper details techniques for production optimization in heavy oil settings.

It also focuses on the remedial actions to be performed once the reservoir and well inflow mechanisms have been identified.
Whipstock-and-Inflatable Packer Combination Decreases Openhole Sidetracking Costs in Central Arkansas
Authors: Broussard Andre N. , Templeton Garry W. , Travis Deck
Published: October 2009

Traditional openhole sidetracking operations involve time-drilling off of a balanced cement plug or drilling off of a whipstock cemented in place. The use of cement in these operations can be cost prohibitive, considering the cost of mobilizing a cement unit, time spent waiting for cement to set up (with rig and associated rental equipment on standby), and time spent drilling off of the cement plug or cemented whipstock. Water-sensitive formations can further complicate the sidetracking operation that incorporates cement. In addition, the initial attempt to time-drill off of a cement plug is not always successful, and multiple attempts may be required before a successful sidetrack has been achieved. A cement-in-place whipstock, while typically more consistent in achieving a sidetrack, limits the sidetrack depth to the bottom of the original well. This paper introduces the combination of whipstock and inflatable packer technologies, deployed together in one trip, to effectively sidetrack a well at any depth, without the use of cement. The paper discusses conventional openhole sidetracking methods and compares them with the whipstock-inflatable packer combination. The paper includes case histories taken from recovery maximization efforts in the Fayetteville Shale gas play and shows that using openhole whipstocks anchored on inflatable packers saved time and decreased overall sidetracking costs over a 60-well evaluation period. Finally, the paper also discusses lessons learned over the course of the project and limitations of the system.

The applications of this system include a wide range of openhole sidetrack drilling operations such as sidetracking a well obstruction, correcting directional azimuth, and targeting a pay zone uphole from the original depth of the well.

The analysis data for this paper come from daily drilling reports on actual wells in the Fayetteville Shale gas play. Data taken from wells using conventional techniques are compared to data taken from wells using the whipstock-inflatable packer combination. Cost reductions are correlated directly back to these drilling reports.

This paper shows that using the whipstock-inflatable packer combination saves time and money and enables more consistent sidetracking times.
Development and Field Application of a Novel Non-acid Calcium Naphthenate Inhibitor
Authors: Debord Justin , Srivastava Piyush
Published: October 2009

Current state of the art for treating calcium naphthenates requires addition of large doses of acid to the production fluids. Although effective in dissolving deposits, acid treatments result in increased corrosion in production equipment, decreased oil quality and increased transport and HSE costs. Consequently, an opportunity exists for the development of non-acid inhibitors to prevent calcium naphthenate formation without the drawbacks encountered with acid treatment. In this account, we report on the discovery and development of molecules that, when injected into a production stream, prevent the formation of large scale calcium naphthenate deposits. As a result, these molecules allow for treatment of calcium naphthenate deposits without treatment with large acid dosages. The purification scheme for naphthenic acids and a novel screening test method capable of selecting highly active naphthenate inhibitors will be detailed as well as field testing results in which no deposits formed and excellent water quality was obtained.
Analysis of Transient Data During Relative Permeability Measurement Using Steady State Technique
Authors: Fassihi M. R. , Potter Gary
Published: October 2009

There have been numerous papers discussing the advantages and disadvantages of Steady State versus Unsteady State Relative Permeability tests. But, there have been little discussion about the interrelationships between these two procedures. This paper shows how the transient data (pressure drop and saturation changes) during steady state tests can be used to arrive at relative permeability data and, thus, provide coverage for the full saturation domain. The transients occur after injecting at a new water-oil ratio (or gas-oil ratio) begins and before saturations along the core are equilibrated. A numerical simulator was used to model the steady state method. Injection of water and oil was simulated at different water-oil ratios (WOR) in a one-dimensional model. Both the constant injection rate (CIR) and the constant pressure drop (CPD) cases were simulated. The pressure drop and the fluid injection and production data during the transient periods (before stabilization at the next steady state point) were analyzed. These data closely matched the actual relative permeability curves. The new method was further tested by using actual laboratory measured data. The close agreement between the estimated relative permeability data based on transients with those based on steady state suggests the applicability of this new technique to any system. Thus, by using this technique, it should be possible to reduce the time required to conduct a Steady State tests by running fewer WOR (or GOR) cycles.
The Quest to Understand ESP Performance and Reliability at 220°C Ambient and Beyond
Authors: Noonan S. G. , Dowling M. , Klaczek W. , Piers K.
Published: October 2009

ConocoPhillips has been on a quest for a high-volume artificial lift system that will operate reliably in a 250°C (482°F) downhole environment. This paper will describe the testing and results of a high-temperature electric submersible pump (ESP) system in a flow loop built to validate downhole equipment for thermal applications, primarily for steam assisted gravity drainage (SAGD) developments. What makes this test program unique from previous tests is the longer duration (4+ weeks), the range of fluid temperatures (90°C to 245°C [194°F to 473°F]), and the type and volume of data collected. One of the key parameters monitored and documented was the internal motor winding temperature, which has been used to validate and calibrate a simulator for predicting motor performance in thermal environments.
Saving Expensive Offshore Deepwater Rig Time by Modeling Accurate Subsea/Subsea-Floor Temperature Modeling for Cementing Operations
Authors: Tahmourpour Farzad , Quinton Chris
Published: October 2009

Accurate temperature modeling on an offshore deepwater well or potentially any other type of well can result in reduced, nonproductive time (NPT) attributed to waiting on cement (WOC) time. Understanding the downhole temperature behavior and heat recovery during the static time after placement of cement slurry can provide an opportunity to minimize WOC-time for compressive-strength development. Drilling engineers encounter a variety of requirements by regulatory agencies across the globe concerning cementing operations. Although the regulatory-agency guidelines and expectations in many cases are detailed and challenging, the operational requirement and cost-saving prospects by operators go beyond some of these recommended/required expectations. Almost any optimization that can expedite commencement of the drilling operation after a cement job (for example, drilling, completing, moving rig) should improve the cost-effectiveness of the drilling program. Water temperature gradient profiles from sea surface to seabed through shallow formations below the seabed exhibit diverse characteristics in different fields. An accurate bottomhole static temperature (BHST), or the undisturbed bottomhole temperature (BHT) and understanding the bottomhole circulating temperature (BHCT) behavior is a crucial factor to success of deepwater field developments. This paper will discuss how best practices in combination with optimized downhole temperature modeling can potentially reduce the number of hours in WOC-time without introducing any additional risk factors into the cementing/drilling operations. Calculating accurate downhole temperature and pressure profiles, which are also used for pipe-body movement and casing-and tubing-load analysis, assists cementing, drilling, and completion engineers to produce highly effective solutions.
Properties of Tight Gas Sand From Digital Images
Authors: Metz Mike , Briceno Gabriela , Fang Qian , Diaz Elizabeth , Grader Avrami , Dvorkin Jack
Published: October 2009

Basin-centered gas deposits are abundant in North America. Recently, such reservoirs have become attractive exploration and development targets because they contain vast domestic deposits of natural fuel. A key property required to plan and optimize production in these reservoirs is permeability.

The latter is notoriously difficult to measure in a physical laboratory. Extremely low and often disconnected porosity results in small permeability, often in the nano-Darcy domain. This makes the standard steady-state flow approach virtually impossible to implement and calls for such intricate and lengthy techniques as pulse-decay flow measurement. An alternative to a physical measurement is a numerical simulation of fluid flow in a 3D digital pore space accurately imaged by high-resolution CT scanning.

We present an example of this digital technique for two samples from the Williams Fork formation in Colorado Basin from one well drilled by Occidental Petroleum with the total porosity ranging from 0.01 to 0.10.

The porosity of the first sample was about 0.08. It was dominated by fairly large pores connected by narrow conduits. This pore space was successfully imaged in a micro-CT machine with a voxel resolution of 2.2 microns. The simulated permeability was in the 1 to 5 mD range. The formation factor ranged from 600 to 2,000.

The pore space of the second sample was not discernible at the micro-CT resolution. It was imaged in a nano-CT machine with a voxel resolution of 0.065 microns. Disconnected spherical pores of approximately 1 micron in size were discovered. These pores were predominantly located within calcite crystals, presumably due to secondary dissolution of carbonate inclusions.
Planning and Procedures for the Initial Startup of Subsea Production Systems
Authors: Duhon H. J. , Garduno J. L. , Robinson N. A.
Published: October 2009

Initial startup of a subsea development is one of the most challenging periods in the operational life of the facility. Many issues complicate this period. These include: –People issues: a great many people from many teams are required to execute a startup; roles and responsibilities may be unclear and will change over the course of the startup; persons on board (POB) issues limit the number of people who can participate; personnel involved may not be fully trained in the operation of the facility.–This will be the first time much or all of the equipment is used in live hydrocarbon service. Design flaws, commissioning omissions and infant mortalities will rear their heads.–Preserving completion integrity requires low rates and slow bean-ups during initial startup because of high formation skin. Chokes designed for high rates and low pressure drops may not be capable of controlling the well at low rates. Also, topsides systems designed for peak rates may not function well at low flowrates.–Low flowrates and low initial temperatures result in hydrate risk which may challenge the flow assurance strategy.–Completion and stimulation fluids returned during the initial well cleanup are corrosive and are difficult to treat. Specialized water treatment equipment is typically installed temporarily on topsides to treat these fluids.–Solids from the reservoir and from construction debris may cause problems such as plugging small ports in control valves.–Drilling, construction, installation and commissioning activities (SIMOPS) may still be in progress. The exact state of equipment items may be unclear and may change over the course of the startup.–Special procedures are usually written for the initial startup. These will differ in important ways from the normal operating procedures. Risks exist that there may be errors in the startup procedures, that operators may err in implementing the procedures, that equipment designed for normal operating will not function well at the conditions imposed by the startup.–Reservoir Engineers will seek to obtain reservoir information via well tests, especially pressure build-up tests. These tests are sensitive and are easily disrupted by operator actions during the tests.–Some regulatory requirements apply specifically to the startup period.

Careful planning is required to achieve a trouble free startup. This paper describes the key requirements for generating effective startup plans and procedures.
Modernization of the SEC Oil and Gas Reserves Reporting Requirements
Authors: Lee W. John
Published: October 2009

Modernized US Securities and Exchange Commission (SEC) rules for reporting oil and gas reserves are now broadly consistent with the SPE definitions and generally reflect public requests for specific changes in the previous rules. Disclosure requirements based on the revised definitions feature use of annual average prices; wider use of reliable technologies; broader recognition of nontraditional resources, including those from oil sands, shales, and coal; optional disclosure of probable and possible reserves; and replacement of the "certainty" criterion for some reserves by a "reasonably certain" criterion. Official clarification of some of the new terms may be forthcoming; here, I provide my opinion of their intent.
Coupled Reservoir Flow Simulation: Fault Leakage Analysis
Authors: Rodrigues L. G. , Cunha L. B. , Chalaturnyk R. J.
Published: October 2009

Petroleum project costs may increase tremendously if wells need to be shut in or abandoned. A scenario where this possibility exists occurs in a reservoir hanging a major fault that connects the petroleum field to the seafloor. During water injection operations the fluid pressure within the fault may increase to a value that leads to fault slip and hydrocarbon flow through to the seabed. The hydrocarbon leakage can result in severe environmental damage and must be avoided. So, a proper simulation model that enables the evaluation of the maximum injection pressure allowed to impede oil leakage during water injection projects is a necessity.

The focus of this work is an offshore unconsolidated sandstone reservoir field located in Campos Basin, Brazil. This field has used waste water for injection since the beginning of production, and there are strong uncertainties about the limits of pressure injection and reservoir fault properties that are related to the project development.

To achieve the objective of examine uncertainties of flow through a major fault in offshore oil reservoir undergoing waterflooding; a methodology is developed that enables the incorporation of key mechanisms (e.g. effective stress law) and parameters (e.g. volumetric strain) to solve a complex numerical field reservoir simulation problem that includes geomechanical process. The proposed methodology uses an external-iterative-coupled reservoir-geomechanical modeling approach to capture the link between fluid flow and in situ stress.

As a conclusion this study will reveal the effects of dynamic changes of permeability and porosity on reactivation of faults in a real offshore reservoir (Field "A"), and set up a minimum safe water pressure injection level for the field.

The methodology developed in this study is valuable for assessing other oil exploitation project scenarios where limited information and production uncertainties are present. This work is important for reservoir characterization, enhanced oil recovery and production applications such as oil rate leakage through a fault.
Combination of Chemical Diverters and Degradable Fiber Technology Enhances the Success of Stimulation in Complex Carbonate Environments
Authors: Dashti Qasem , Liu Hai , Cirrincione Todd , Al-Saqabi Mishari , Lesko Timothy M. , Majid Azmin A.
Published: October 2009

Due to damage caused by drilling and completion operations, most wells in the Jurassic carbonate reservoirs in North Kuwait require acid stimulation after perforating to either recover or enhance the well productivity. To date, production responses after stimulation treatments have been mixed, depending on the formation, the type of treatment and the volume and the chemistry of stimulation fluids. Additionally post-stimulation production logging surveys in many wells typically have shown poor stimulation efficiency with only a short perforation interval contributing to a majority of the production. Thus, it becomes crucial to develop general engineering guidelines and address treatment diversion issues for future stimulation work.

This paper presents an engineering process for optimizing matrix stimulation and acid fracturing treatments according to laboratory tests and well performance evaluation in more than 20 wells in the deep Jurassic carbonate reservoirs in Kuwait. The paper also introduces a new stimulation technique that combines chemical diversion (viscoelastic surfactant based diverting acids) and degradable fiber technology to enhance leakoff control and diversion capability of the chemical solution into the complex naturally fractured carbonate formations. The technique improves leakoff control into large natural fractures, dominant wormholes and high permeability zones, and results in deeper acid penetration and more effective vertical coverage. The degradable fibers completely decompose with time and temperature after the treatment has been pumped.

Field results have shown significant improvement of post-stimulation production after the general engineering guidelines were implemented. Application of this new stimulation technique has been evaluated through the production surveys and performance before and after the treatment. Initial results on the first well showed an eightfold increase in the productivity index.
Are there Less Costly Ways to Sequester Carbon than CCS?
Authors: Gupta Subodh
Published: October 2009

Given the expected rise in global demand for energy, which in turn is dominated by reliance on fossil fuels, carbon emissions are only expected to increase, raising the CO2 concentration of the atmosphere even further. Efficient use of energy will help but if we have to reduce atmospheric CO2, we are forced to consider methods of carbon sequestration and associated costs. Carbon Capture and Storage (CCS) is the most discussed method of sequestration. However, there are two major issues with this approach of sequestration. Firstly, it is the high direct cost associated with capital and operation of capture, transport and subsurface injection. And secondly, it is the undetermined cost of post-operation liability associated with measurement, monitoring, verification and problem-rectification. Committing to the needed large scale sequestration projects without properly considering alternatives can prove costly at both economic and social levels. There are alternatives to CCS, however. Use of biomass derived fuels such as bio-ethanol has been talked about in literature as one of them. But biofuels are shown to be more expensive for carbon abatement than the base alternative.

Charcoal sequestration (CS), discussed earlier by the author carries with it the benefit of being a pure sequestration (similar to CCS), is less costly both in terms of its direct costs and lacking any post operation liabilities, and above all is reversible, allowing flexibility of policy and operation, avoiding long term or large scale commitments.

In this paper the author outlines how municipal solid waste (MSW) processing into charcoal can be a good way to initiate demo projects for charcoal sequestration approach potentially opening door for employing other larger resources of biomass and shows as such use of MSW has to be a major component of our carbon abatement package of actions. This is for reasons of both cost effectiveness as well as to reduce the landfill methane (a more potent GHG) from entering into atmosphere. The over all discounted cost of a suite of proposed measures including improvement of efficiency, conversion of waste to charcoal for use both as fuel as well as sequestration, increased use of nuclear energy, limited application of CS using larger dead-stock biomass pool, and CCS, is assessed to be in the range of US$7.5trillion in this paper, reducing the equivalent CO2 concentration by 465 ppm (compared to the projected business as usual) by the end of 21st century.

The outlined approach, with its prominent use of MSW, promises not only to mitigate the growing urban waste problem but also to help evaluate this novel method of sequestration and enhance public awareness on the subject. This in turn will help the larger society make an informed choice to embark on a right course of action for atmospheric carbon abatement.
Wellbore Profiling With Broadband Multipole Sonic Tools
Authors: Market Jennifer , Canady Wyatt , Elliott Paul , Hinz David
Published: October 2009

Theoretical papers have been presented considering the depth of investigation of classic sonic tools, largely focusing on the effects of the source-to-receiver spacing in the case of altered zones. Modern sonic tools use multipole sources (monopole, dipole, and/or quadrupole) at a broad range of frequencies and source-to-receiver offsets. This paper briefly reviews the theoretical discussions of the effects of tool geometry and source characteristics, but focuses primarily on the practical aspects of wellbore profiling with modern sonic tools. We concurrently consider the tool geometry, source order, and frequency effects on the depth of investigation and discuss the differences in wireline and logging-while-drilling environments. Multiple field examples are shown in cases of alteration and invasion. We explore the benefits of reporting sonic logs at multiple depths of investigation, which can yield valuable information about shale reactivity, wellbore stability, and geosteering. A summary of how to recognize the effects of variable depth of investigation on common sonic logs presentations completes the report.
A New EOR Method
Authors: Behzadi S. Hamid , Towler Brian F.
Published: October 2009

A new method of enhanced oil recovery has been developed and applied to a sector simulation using some of the data from the South Slattery Field, Minnelusa A reservoir. The new method, termed ASPaM, combines features of CO2 miscible flooding with Alkaline-Surfactant-Polymer (ASP) flooding to produce an enhanced WAG flood. A numerical pre-processor program had to be developed to produce the required mixing zone properties of a CO2 front, which are input to the CMG simulator, STARS. STARS is a chemical flood simulator, but cannot accomodate the solvent model. The preprocessor calculates oil and solvent properties based on the Todd-Longstaff procedure. Sensitivity analysis showed this new method can give a much better recovery in comparison to ASP or CO2 WAG flooding for different depositional environments. ASPaM benefits from high micro and macro sweep efficiencies plus miscible flooding, even for a small ASP slug size. The simulation results revealed the recovery from this scheme is considerably better than ASP and CO2 flooding separately. It showed the recovery can be improved and accelerated by the application of ASPaM, and its performance is a function of the miscibility of the CO2-oil miscible zone and the reduction in IFT at the ASP-oil interface at reservoir conditions. Moreover the water/gas ratio of ASPaM is totally different in scale compared to a typical WAG scheme. A significant acceleration and improvement in recovery is achieved with a 10 % pore volume ASP slug size. This work indicates CO2 flooding and sequestration can be stabilized and enhanced if it combines even with a small ASP slug size. The results so far have been very encouraging.
Distribution of Hydrogen Sulphide in the Buzzard Field
Authors: Beilby P. , Clayton C. , Moffatt B.
Published: October 2009

The Buzzard field, discovered in 2001, is an Upper Jurassic turbidite reservoir lying in the outer Moray Firth of the North Sea. It has an estimated STOIIP in excess of 1 Billion STB.

During the appraisal drilling the fluid properties were found to be generally similar across the field with the exception of the H2S, CO2 and Mercaptan levels. During initial development drilling, using improved measurement techniques, the H2S levels were found to vary more than originally predicted.

Extensive geochemical studies were performed to ascertain the charging mechanism. The results suggested that the H2S was present in the original charge oil, that the charge was very recent, and that the aquifer water was most likely having a significant effect in removing some of the H2S from the oil during migration. It was also thought that there was additional natural scavenging from the rock. These theories were also supported by equation of state modelling and stable isotope analysis.

The H2S data was mapped onto the geo-model and H2S levels were simulated and controlled using tracers in the dynamic model. The results were subsequently used to determine future well locations and to predict and control the field's producing H2S levels. Since the H2S distribution was determined, 10 out of 10 production wells drilled have been successful in targeting sweet oil. This drilling program has allowed the field ramp up and plateau to be unaffected by the more variable H2S distribution. To date the field has now produced more than 155 MMstb of oil with actual H2S levels being relatively close to predictions.

In summary improved H2S sampling and measurement techniques, geochemical modeling, EOS modelling and mapping in conjunction with simulation have provided a robust solution to aid effective field development.
The Piston Tubing Rod Performance Curve: A New and Useful Concept for Sucker-Rod-Pumping Analysis
Authors: Caicedo Sergio , Carma Suhail
Published: October 2009

Engineers have used standard techniques for decades when analyzing sucker rod wells, such as: API 11L standard, wave equation numerical simulation, acoustic logs and dynamometer card acquisition and processing. Each technique has a particular goal and they complement each other. API 11 was developed in the fifties as an easy and hand computation procedure for estimating the production and operational parameters (loads, stresses, torque, etc). Later in the eighties the desktop computers came into the market making the wave equation approach reasonable and popular. The acoustic logs and dynamometer card have been diagnosis tools in the field, which have been boosted by the portable computers. However, none of these tools is able to generate the pump performance curve equivalent to those provided by the electrical submergible pump (ESP) or progressive cavity pump (PCP) manufacturers. Piston pump manufacturers cannot generate that curve at the factory because they only can measure the pump's slippage (leaks in valves and piston walls) but the pump performance also depends on the following parameters: rod and tubing stretching, the rod fundamental frequency, which change in each completion. In the present paper the approach and algorithm to generate the Piston-Tubing-Rod Performance Curve (PTRPC) is shown, which gives a new complementary tool for engineers. Some examples show usefulness of this innovative concept in Sucker Rod Pumping. Finally, the way to introduce the PTRPC in a Nodal Analysis is presented.