bluuebunny/crossref_metadata_2025 huggingface dataset:
Horizontal Fractures in Single and Multilayer Reservoirs
Authors: Larsen Leif
Published: December 2011

Type curves for circular uniform-flux fractures in unbounded single-layer reservoirs were presented in the literature several decades ago. Unfortunately, these results have restricted validity since the simple uniform-flux inner-boundary condition will cease to be physically meaningful when significant boundary effects from the top and bottom of the formation start to affect the data. This is especially important for large fractures in formations of limited thickness. For horizontal fractures it is therefore important to include finite conductivity as part of the fracture model. Solutions addressing these issues are presented in this paper along with examples highlighting effects of different modeling options. The solutions include both compressible and incompressible flow inside the fractures.

The solutions have also been extended to multi-layer reservoirs through a decoupling approach, with both unbounded and bounded circular models used in examples. Solutions for layered reservoirs are important because layering is common with obvious effects on productivity and because layering can create unusual pressure-transient characteristics during buildups if there are shale streaks or other low-permeability flow barriers between layers acting as partially sealing boundaries.

Horizontal fractures are becoming more important due to an increasing number of shallow-depth disposal wells, for instance as part of carbon capture and storage developments. Shallow gas developments with fracturing needed to obtain sufficient productivity are also adding to the importance of these fracture models. Both for producers and disposal wells, layering will be an issue and has to be addressed.
Shape Memory Polymer as a Sand Management Alternative to Gravel Packing
Authors: Carrejo Nick , Horner Don N. , Johnson Mike H.
Published: December 2011

Shape memory polymer foam is currently being deployed in down-hole sand control applications. The shape memory polymer is molded in a cylindrical geometry with a desired outer diameter and inner diameter. The geometric profile is altered to specifications with an inner drainage layer, to satisfy the run in requirements of the tool. Once set down hole, the shape memory polymer will start deploying to the original outer diameter of the original geometric profile. The polymer will continue to deploy and conform to the bore wall. This shape memory polymer has a permeability that is 25 times greater than that of the formation permeability to prevent plugging risk, and ensure that there is negligible to no impedance to production.

Gravel packing is a form of sand management used for decades during the production of oil and gas. This paper compares the sand control characteristics of shape memory polymer foam against conventional gravel packs under similar conditions, loads, and formation sands. We will show how the performance of the shape memory polymer can eliminate the need of gravel packing altogether within a given bottom hole temperature range.
Effects of CO2 Sequestration on the Petrophysical Properties of an Aquifer Rock
Authors: Ofori Albert , Engler Thomas
Published: December 2011

Carbon dioxide capture and sequestration (CCS) into deep geological formations is widely considered as a preferred option for reducing green house gases (GHG) in the atmosphere. The preferred storage location is the saline aquifers due to their exceptional sequestration capacity compared to depleted oil and gas reservoirs. Since CO2 is a relatively reactive substance, injecting it into an aquifer could initiate various chemical reactions with aquifer rock and cap rock. This underscores the need to plan the sequestration process carefully and to investigate possible consequences in terms of rock-fluid reactions that may affect Petrophysical properties.

The results presented here are based on a compositional reservoir simulation study of a prototypical CO2 sequestration project in a deep saline aquifer. The purpose of this study was to try to determine the effects of CO2 sequestration on the Petrophysical properties of an aquifer rock. CO2 was injected for a 10 year period, followed by 1,000 years of natural gradient flow. The impact of several parameters including temperature, vertical to horizontal permeability ratio, and salinity were also studied and the results are presented here.
Accurate Porosity Measurement in Gas Bearing Formations
Authors: Desport Olivier , Copping Kim , Johnson Barry L
Published: December 2011

Porosity is a key reservoir parameter and high accuracy is needed to properly estimate reserves. But even though there is a long history of porosity measurements and various tools from which to derive it, this can still remain a difficult task. None of the logging tools directly measure porosity but instead respond to density, lithology and fluid. Combining different measurements can help to solve for porosity but also brings the complexity of invasion as all the tools do not have the same radial response. This problem is even more complex when dealing with gas formations as the fluid effect on the measurements is very high.

This paper looks at various methods to improve porosity computations via the integration of Nuclear Magnetic Resonance (NMR) and other porosity measurements in South China Sea gas reservoirs.
Production Data Analysis: Unraveling Rock Properties and Completion Parameters
Authors: Jochen Valerie , Malpani Raj , Moncada Katharine , Altman Raphael , Luo Fang , Xu Jian
Published: December 2011

The measurements available to estimate reservoir parameters are numerous, yet most wells are completed in various shales without traditional log measurements. Horizontal wells continue to be drilled, and while the number of stimulation stages pumped per lateral length continues to increase, many questions remain: Is there an increase in production commensurate to the added cost, or will it soon become unsustainable? Would better characterization of the effective surface area after hydraulic fracture stimulation help explain the reservoir potential?

Analysis of production data from fractured shale gas wells is difficult. Operators try to estimate fracture and reservoir properties for a horizontal well with multiple hydraulic fractures by using pressure transient testing, even though in reality it could take 10,000 years for the actual reservoir pressure to be measured. Alternatively, others model the production of fractured shale gas reservoirs from a zone-altered permeability area, which may be quite limited in areal extent but is surrounded by a low-matrix-permeability reservoir to account for the well productivity. Ultimately a simplistic reservoir model for production forecasting uses whatever data is available and our basin experience.

How do we validate these models? Traditionally we look at case studies to find an analogous situation to validate and identify the dominate production drivers. Existing approaches to model shales require years of production data, and even then they cannot uncouple reservoir properties from completion parameters to help optimize flow efficiency. When production is measured on a stage-by-stage basis, and laboratory and log analysis data are presented for reservoir and fluid characterization, solving for the created effective surface area should be straightforward. By better characterizing along the wellbore and by discriminating the contributions of RQ and CQ to the reservoir production, we will be able to better predict long-term well production and better understand the reservoir potential.

This paper discusses the current status of production prediction for shale gas reservoirs and provides a vision of possibilities for better interpretation, i.e these production models must go hand-in-hand with hydraulic fracture models to determine the crucial parameters that drive production, thus fully optimize well and field production.
Using a New Intelligent Well Technology Completions Strategy to Increase Thermal EOR Recoveries–SAGD Field Trial
Authors: Shaw Joel , Bedry Mark
Published: December 2011

A completions strategy has been developed for improving both steam injection and production conformance in a thermal enhanced oil recovery (EOR) project by using intelligent well technology incorporating interval control valves (ICV), well segmentation, and instrumentation. The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair. The development of the completion technology suitable for thermal conditions, initial field trial results and the plans for further development are described. The application modeling shows that, depending on the level of heterogeneity present in the reservoir, a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost-effective intelligent well completion solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive, and variations, including, for example, those involving solvent additives. The initial field deployment in the injector well was primarily to prove the technology, to demonstrate the feasibility of modifying the steam distribution and to learn for future developments. A successful installation and commissioning of the intelligent completion has substantially validated the technology. Lessons learned are highlighted. Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of the steam injection in the well is underway and the results are discussed. The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date.
Utilization of Non-damaging Drilling Fluid Composed of Potassium Formate Brine and Manganese Tetra Oxide to Drill Sandstone Formation in Tight Gas Reservoir
Authors: Bialy M. El , Mohsen M. , Ezell R. G. , Abdulaziz M. Emad , Kompantsev A. , Khakimov A. , Ganizade F. , Ashoor A.
Published: December 2011

An engineered fluid formulation was designed to provide a 114-pcf non-damaging drill-in fluid for the Unayzah A and B sandstone reservoirs. Employment of potassium formate high density brine and manganese tetra oxide weighting agent provided superior drilling properties that delivered reduced formation damage, improved thermal stability, and lower drilling costs.

The use of acid-soluble manganese tetra oxide allowed engineers to increase the density of potassium formate drilling fluids and extend the density window above that offered by calcium carbonate. The reduced particle size (D50= 1 micron) and the spherical shape of the manganese tetra oxide reduced friction and drag. This improved control of equivalent circulating density (ECD) and plastic viscosity (PV) and significantly lowered rheological profiles. These optimal properties were maintained at temperatures exceeding 155°C.

Laboratory testing confirmed high performance features such as:

Excellent hole cleaning characteristics Thin filter cake with low lift-off pressures Low differential sticking potential Low treatment cost during drilling and re-use capability Superior rheological performance compared to high solids content oil-based fluids Improved drilling performance and hydraulic efficiency with the formate base system.

The vertical well in the Unayzah A and B sandstone reservoirs was completed with zero hole problems. The potassium formate/manganese tetra oxide system provided superior performance and stability even with elevated bottomhole temperatures in the tight gas formation. This paper reviews the laboratory design and development as well as the field application of the high performance, brine-based drill-in fluid.
A novel multi-rate dual-porosity model for improved simulation of fractured and multi-porosity reservoirs
Authors: Geiger S. , Dentz M. , Neuweiler I.
Published: December 2011

A major part of the world's remaining oil reserves is located in fractured carbonate reservoirs, which are dual-porosity (fracture-matrix) or multi-porosity (fracture-vug-matrix) in nature. Fractured reservoirs suffer from poor recovery, high water cut, and generally low performance. They are modelled using a dual-porosity approach, which assumes that the high-permeability fractures are mobile and low-permeability matrix is immobile. A single transfer function models the rate at which hydrocarbons migrate from the matrix into the fractures. As shown in many numerical, laboratory, and field experiments, a wide range of transfer rates occurs between the immobile matrix and mobile fractures. These arise, for example, from the different size of matrix blocks (yielding a distribution of shape factors), different porosity types, or the inhomogeneous distribution of saturations in the matrix blocks. Accurate models are hence needed that capture all the transfer rates between immobile matrix and mobile fracture domains, particularly to predict late-time recovery more reliably when the water cut is already high. In this work we propose a novel multi-rate mass transfer model for two-phase flow, which accounts for viscous dominated flow in the fracture domain and capillary flow in the matrix domain. It extends the classical (i.e., single-rate) dual-porosity model in that it allows us to simulate the wide range of transfer rates occurring in naturally fractured multi-porosity rocks. Using numerical simulations of water-flooding in naturally fractured rock masses at the grid-block scale we demonstrate that our multi-rate mass-transfer model matches the observed recovery curves more accurately compared to the classical dual-porosity model. We further discuss how tracer tests can be used to calibrate our multi-rate dual-porosity model before the water-flood commences and how our model could be employed in commercial reservoir simulation workflows.
Challenging Well-Testing Operations in High-Temperature Environments — Worldwide Experiences and Best Practices Learned
Authors: Salguero Alejandro , Almanza Edgar , Haddad Josmar
Published: December 2011

The oilfield industry classifies wells with bottomhole temperatures in excess of 300°F as high-temperature (HT) wellbores. Because they usually can produce large hydrocarbon volumes, all attempts to develop and produce these areas have been tried, although prospects with HT conditions present more challenging conditions. These challenges affect operational planning, equipment applications, engineering job design, and execution, and proper planning is critical to achieving job objectives.

This paper presents lessons learned and equipment applications in HT well testing environments globally, where different reservoir scenarios require modificarions to procedures, equipment configuration, and safety requirements. Each job requires consideration of ambient environmental criteria in addition to the individual operator's testing policies. Therefore, different methods for achieving job goals are needed. The lessons learned will be applicable to current scenarios in many areas and will be discussed to allow the operators to determine proper testing procedures for their HT jobs in similar conditions.

Well tests are performed using different downhole tools and procedures. A summary of these topics will include:

Operational advantages and efficiency gains New technologies to make well testing operations and evaluations more accurate Collection of downhole samples in (pressure, volume, temperature (PVT) conditions to provide the most appropriate data to be considered during future development of prospect.

New technologies are an excellent example of how technical developments and advances in the oil industry (gauges, downhole equipment, samplers, etc.) have been applied to operations in the oilfield to improve the decision-making capabilities in the oil and gas industry as well as increase well-testing evaluation success, even in extreme and challenging environments. These enhancements allow improved economic and operational efficiency as well as better safety conditions, both for the involved personnel and the environment during testing operations.
An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation
Authors: Fan Li , Martin Ron , Thompson John , Atwood Keith , Robinson John , Lindsay Garrett
Published: December 2011

Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries.

Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying "sweet spots" based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases. The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford.

The results of the study identifies "sweet spots" of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale.

Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage.
Single-Well SAGD: Overcoming Permeable Lean Zones and Barriers
Authors: Hocking Grant , Cavender Travis , Person John
Published: December 2011

Performance of conventional steam-assisted gravity drainage (SAGD) with horizontal well pairs is impacted significantly in formations with high-permeability lean zones. These lean zones rapidly halt the vertical growth of the steam chamber and spread the chamber laterally, resulting in water-loss issues and a significant impairment of the system to overcome barriers (i.e., low-permeability horizontal layers). The operating-steam pressure is lowered to reduce the water loss to the lean zone, and this in turn accentuates the impact of any barriers, thus giving rise to high steam-oil ratios (SORs) and lower production rates. A vertical single-well injector/producer was proposed that consists of six vertical propped planes installed at varying azimuths from the bottom to the top of the pay. Steam would be injected at the top of the pay, and liquids would be extracted at the bottom. The well would be operated immediately in SAGD mode (i.e., the continuous injection of steam and the continuous extraction of liquids), resulting in peak production achieved within 30 to 45 days. The system would be very efficient because of the immediate drainage available from the propped vertical planes, and also as a result of the full gravity effect on the drainage height at startup and a favorable steam-pressure gradient. Reservoir simulations show that the single-well system’s performance with high-permeability lean zones within the pay would be virtually unimpaired, both in terms of production rate and SOR. Clearly, the system’s operating pressure must be lower to reduce water loss to the lean zone; but, because of the top-down growth of the steam chamber, the permeable lean zone’s impact would be minimized. The net present value (NPV10) of the single-well SAGD system in 35-m thick Athabasca bitumen pay with a 5-m permeable lean zone was estimated to be greater than 6×NPV10 of conventional SAGD. The single-well SAGD system would be much easier to pressure balance and operate than conventional SAGD, resulting in a more robust system, provided the multi-azimuth, propped vertical planes are constructed continuously throughout the pay height.
The Benefits of Reworking Declining CBM Wells
Authors: Morad Kamal , Tavallali Mohammad
Published: December 2011

There are three distinguishing phases in the production life of a wet CBM well: a period of inclining gas rate due to dominance of relative permeability effects, a period of rate stabilization during which the gas rate peaks followed by the depletion phase during which gas production rate declines.

The declining gas production rate can be attributed to many factors such as: ■Declining reservoir pressure■Loss of productivity due to compaction and permeability loss■Loss of productivity due to fine migration that creates a choke skin near wellbore

While the decline in reservoir pressure is inevitable, the loss of productivity due to the choke skin and permeability loss for a declining CBM well can be remedied or slowed down through a multi-stage hydraulic refracturing. The impact of such fracturing on improving well productivity and boosting the gas production rate is investigated.

Reworking the well through refracturing could help clean up the zone near wellbore, re-activate or improve the coal network of natural fractures; lead to more effective dewatering and even create new contacts between the reservoir and formation. The area near wellbore will benefit from re-invigoration of fracture network and creation of an area of enhanced permeability.

In this study the benefit of completing a new vertical and/or horizontal CBM well with a multi-stage hydraulic fracture is examined. The production of wells with such completions are compared to typical single-stage fracturing and benefits of creating an inner zone of enhanced permeability in short-term and long term are investigated.

A numerical dual-porosity reservoir model is used to generate the CBM gas production forecasts.
Solvent Chamber Development in 3D Physical Model Experiments of Solvent Vapour Extraction Processes SVX With Various Permeabilities and Solvent Vapour Qualities
Authors: Knorr Kelvin D. , Imran Muhammad
Published: December 2011

Solvent vapour extraction (SVX) processes offer an attractive alternative to thermal recovery processes, being less energy intensive; and are more suitable for thinner, partially depleted reservoirs. A typical SVX process uses solvent injection to dilute the heavy oil by reducing its viscosity, allowing it to be mobilized for production. During this process the injection of hydrocarbon solvents results in partial deasphalting of the heavy oil, thus further reducing its viscosity and enhancing the process performance.

This work examined the formation and growth of solvent chambers in laterally and vertically spaced horizontal injector/producer well pairs in porous media with five different permeabilities and three different solvent vapour qualities. Consolidation of the porous media due to asphaltene precipitation was also analyzed. Thermal imaging and model excavation studies were performed to investigate the formation and growth of solvent chambers for seven different experiments conducted on a large 3D physical model apparatus.

The important findings from this study are as follows: During solvent injection, one or more solvent fingers develop between the injector and producer. The dominant solvent finger becomes a conduit that grows into a solvent chamber connected to the injection well in the upper portion of the reservoir, and develops into an oil drainage conduit connected to the production well in the lower portion of the reservoir. Solvent dispersion layers are located on the margins of both the solvent chambers and the oil drainage conduits. The location and development of these non-uniform solvent chambers and oil drainage conduits are unpredictable, and the oil drainage conduits do not grow significantly in diameter once connected to the production wellbore, limiting the wellbore inflow efficiency and conformity. Asphaltene precipitation and migration can aggravate this inflow problem, further reducing SVX process performance.

SVX performance can be improved by increasing the number and diameter of oil drainage connections between the solvent chamber and the production well, and by controlling the oil deasphalting process. This can be done by optimizing injection and production wellbore geometries, and by optimizing solvent injection rates and vapour quality.
Equipment Consideration for Continuous High-Horsepower Fracturing Operations
Authors: Yeung Tony , Deditch Scott , Schultz Darryl , Dick Graham , Eykelbosh Charles
Published: December 2011

In the drive to improve the economics of shale gas plays, producersare drilling more wells per pad and continually developing new techniques to maximize efficiency, reduce setup costs and optimize completion process. Through careful project planning and logistics, simultaneous 24 hour operations can be achieved. As a result, equipment is often required to operate with minimal maintenance time. The typical mobile fracturing equipment used in these operations is being operated similarly to a process plant environment and is expected to operate in excess of 18 hours per day for consecutive months, contrary to its intended design.

These operationsare primarily performed in shale formations employing stimulation treatments involvingabrasive slick waterpumped at high pressureand high flow rate.Also, the increased work cycles often lead to higher than normal erosion and fatigue frequencyinthe pumping equipment and flow lines, in comparison to conventional stimulation methods.

The paradigm shift in these fracturing operations has led to the re-evaluation of current equipment design. With data taken from a successful fracturing campaign in the Horn River Basin of Northeastern BC, this paper will discuss the challenges encountered in thisproject, the design limitation of conventional fracturing equipment and considerationsfor new equipment design which includes fuel delivery, flow line management, and equipment logistics.
Application of Wireline Stress Testing for SAGD Caprock Integrity
Authors: Mishra Vinay K. , Lywood Peter , Ayan Cosan
Published: December 2011

Measuring geomechanical properties of the caprock and shale gas reservoirs for enhanced oil recovery (EOR) or storage reservoirs has become an integral part of asset evaluation services. The steam-assisted gravity drainage (SAGD) process, as well as other EOR and storage applications (gas, nuclear waste, CO2), requires caprock integrity testing. Measuring in-situ stresses is an important input to caprock integrity solutions not only for the technical management of projects but also for environmental reasons.

A Wireline Formation Testing (WFT) tool is one of the commonly used techniques used for direct measurement of the minimum in-situ stress at different depths. The process is commonly called a mini-frac or micro-frac and is typically performed in an openhole wellbore. A suitable tool string includes a straddle packer arrangement, downhole pump, gamma ray sonde for depth correlation, motorized valves, and pressure gauges. To perform a stress test, an interval of the wellbore is isolated by inflating the straddle packer arrangement. The interval is then pressurized by pumping fluid until a tensile fracture is initiated. In an open hole, the fracture initiates and propagates normal to the minimum stress. Multiple injection and fall-off cycles are performed to ensure fracture growth beyond the hoop stress regime. The data is analyzed to determine fracture initiation pressure, fracture propagation, and closure pressure.

This paper describes the process of minimum in-situ stress measurement using a WFT. Lessons learnt over the years and best practices are highlighted along with their importance for proper job planning. Case studies of WFT testing including SAGD caprock stress testing from Canadian fields are presented and discussed.
Recovery Factor and Reserves Estimation in the Bakken Petroleum System (Analysis of the Antelope, Sanish and Parshall fields)
Authors: Dechongkit P. , Prasad M.
Published: December 2011

Recovery factor (RF) is one of the most important parameters for economic justification in the petroleum industry. The RF is calculated from the ratio between expected ultimate recovery (EUR) and original oil-in-place (OOIP). However, many uncertainties exist in OOIP estimations, mainly due to inaccurate information about reservoir drainage area. In unconventional reservoirs, the estimations of drainage area and OOIP are more complicated due to unknown factors such as fracture networks in the system, reservoir pressures, pore volumes, and in situ hydrocarbon properties.

We analyze here a case study of the Bakken Formation where the RF is still unclear and not frequently reported. RF for the Bakken formation from previous studies ranged from 0.7 – 50% (Price, 1984; Bohrer et al., 2008) derived from different approaches. In this paper, we use the material balance equation (MBE) approach to determine the deterministic (single value) and probabilistic (distribution) RF values in the Bakken Formation (the Antelope, Sanish and Parshall fields). We also perform a sensitivity analysis for the input parameters in our MBE approach.From the actual well production data, the EUR can be estimated from decline curve analysis (DCA) with knowledge of abandonment rate data. The DCA technique based on history data is used as forecast model for predicting the EUR and remaining volume. Once the RF and EUR are calculated, the OOIP value can be evaluated as the ratio between EUR and RF.

In the studied fields, RF result of the Parshall Field is highest because the produced gas-oil ratio is lower than the other two fields. From the EUR results, the high EUR area in the Antelope Field is located in the center of the field. For the Sanish and Parshall fields, high EUR areas are located in the east and west side, respectively. In addition, it appears that EUR has a direct relationship to the hydrocarbon pore volume per area (HCPV/area) distribution. For each field, the results of OOIP per well from the ratio between EUR and RF are presented, and these data can be compared with the volumetric OOIP for proper well spacing plan of future projects.
Succesful Application of Metal PCP Rechnology to Maximize Oil Recovery in SAGD Process
Authors: Arystanbay R. , Bae W. , Nguyen Huy X. , Ryou S. , Lee W. , Jang T.
Published: December 2011

Enhanced oil recovery methods (EOR) methods such as Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), steam drive, solvent and electric heating allow production of highly viscous crude oil at elevated operating temperatures (>160°C). The choice of artificial lift technique is critical to overall well performance. Therefore it has been a challenge to find a reliable artificial lift pumping system for heavy oil thermal recovery. Available options such as beam pumps and electrical submersible pumps (ESP), which are well proven in the petroleum industry, are not particularly well suited for thermal production. Progressing Cavity Pumps (PCP), with elastomeric stator, are economic to run and have performed well in heavy oil cold production. Since their elastomers are limited in temperature (<160°C), a metal PCP technology has been developed through numerous research works to meet the high temperature requirement of SAGD and other thermal recovery processes.

This paper describes the successful application of KUDU PCM VulcainTM metal PCP systems for SAGD process in Athabasca reservoir, beginning from 2007. We made analysis on production optimization in SAGD well pairs equipped with the PCM Vulcain™, which consists of a hydroformed metal stator and matching rotor utilizing special metallurgy to resist wear and maximize run life. In particular, the production with metal PCP in these wells reached the value of 200 m3/d at pump intake temperature of 200°C, performing volumetric efficiency of 82%. In general, the field results have demonstrated that the strong resistance of metal PCPs to chemical and mechanical degradation makes them a good alternative for the cold production of heavy and extra heavy oil with relatively high bottomhole temperatures and high aromatic, CO2 or H2S concentrations. This paper can be a guide for special heavy oil hot production PCP technologies to be spread and applied for EOR projects widely in the world.
Innovative Well-Completion Strategy for Challenging Heavy-Oil Wells within Mature Fields Requiring Sand Control in Colombia
Authors: Huimin Ye , Patarroyo Mauricio , Perez Moreno Carlos Alberto , Lopez Nicolas
Published: December 2011

Heavy-oil wells in northern South America fields are becoming increasingly more common; e.g., fields such as the Faja in Venezuela and the Llanos in Colombia are growing exponential in importance. A common thread in all of these wells is the requirement for completions that accommodate challenging environments and sand-management systems that satisfy the production goals for the field and extends the life of the reservoir. Such challenges cannot be easily met with conventional practices or downhole tools; they need to be analyzed outside the box and with a reservoir-centered mentality. A typical example of these conditions is the Moriche field in Colombia that is operated by Mansarovar Energy. When designing the sandface completion, the engineering team from Mansarovar and the selected service company used different simulations to select the sand-control strategy as well as the most appropriate sand screen to address the sand challenges of the reservoir. Different sensitivity studies were implemented using alternative completion methodologies whose results supported the decision made by the teams. This paper presents the methodology used in the selection and design of the completion for the wells in this field and will explain the different scenarios that were analyzed to select the completion methodology. We will also present the results from simulations carried out to understand the behavior of different sandface completion components during the production life of the well and the impact this new innovative approach had on the productivity of the reservoir.
Enhanced Swelling Effect and Viscosity Reduction of Solvents-CO2-Heavy Oil Systems
Authors: Li Huazhou , Zheng Sixu , Yang Daoyong
Published: December 2011

In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with addition of rich solvent C3H8. Experimentally, PVT tests are conducted to measure the saturation pressure, swelling factor and viscosity of the C3H8-heavy oil system and C3H8-CO2-heavy oil system, respectively. It has been found that an increased swelling effect of heavy oil is obtained by adding rich solvent C3H8 into CO2 stream. An enhanced viscosity reduction of the CO2-heavy oil system is also achieved in the presence of rich solvents such as C3H8. Theoretically, two binary interaction parameter (BIP) correlations in Peng-Robinson equation of state (PR-EOS) have been proposed for respectively characterizing CO2-heavy oil systems and C3H8-heavy oil systems by treating each oil sample as a single pseudocomponent with its molecular weight and specific gravity. The BIP correlations together with the PR-EOS can be used to predict the saturation pressures and swelling factors of the C3H8-CO2-heavy oil systems with a good accuracy. Also, in comparison to other mixing rules, the Lobe’s mixing rule is found to be more appropriate for quantifying viscosity reduction of the heavy oil with dissolution of CO2 and/or C3H8.
Steam Injection Experiences in Heavy and Extra-Heavy Oil Fields, Venezuela
Authors: Vega Riveros Gina , Barrios Hugo
Published: December 2011

The exploitation and development of large heavy and extra heavy oil fields in Venezuela represents one of the largest hydrocarbon accumulations in the world. These deposits can be found at the Orinoco Heavy Oil Belt in Eastern Venezuela, the Bolivar Coast Fields in Western Venezuela and Santa Barbara and Pirital Fields in the Northeast of Venezuela. The Orinoco Heavy Oil Belt represents a 90% of the discovered extra-heavy oil in the country.

Enormous deposits of hydrocarbons can be found in "Cerro Negro", "Machete", "Hamaca" and "Zuata" that belong to the Orinoco Heavy Oil Belt. These fields contain extra-heavy crude of 8 to 9 °API, an oil viscosity of 8,500 cp, an original depth of 2,900 ft and a thickness of 217 to 287 ft. The sand depositional environments are originally fluvial or deltaic and laterally discontinuous.

Santa Barbara Field contains heavy oil crude of 16 to 19 °API, an oil viscosity of 510 cp, a depth of 200 to 1,150 ft and sand thickness of 40 to 253 ft. The fields come from delta derived sandstones enviromentals. Bachaquero, Lagunillas and Tia Juana Fields in the Bolivar Coast Field contain heavy crude of 11 to 15 °API, viscosity of 100 to 10,000 cps, depth of 1,000 to 3,000 ft and sand thickness of 50 to 300 ft. The sand consists of non-marine sediments, eventual transgressions and conglomerate sandstones depositional environments.

The fields were studied to extract information about successful application and evaluation of cyclic steam stimulation (CSS). In the Northern part of Tia Juana Field where the viscosity was higher than expected (typically 20,000 cp), a steam assisted gravity drainage (SAGD) Pilot was implemented. Statistical analysis allowed the quantification of the parameters that affect the incremental recovery factor. As a result, it was found that the basic controls are °API, viscosity, depth, thickness and well spacing.

Thermal recovery processes are mainly applied to deposits less than 1,100 m of depth, oil viscosity greater than 50 cp, gravity less than 20 °API and typical well spacing of 2-5 acres. The most common applied method was cyclic steam stimulation (CSS) with a positive incremental of oil-steam ratio, from 1.5 to 6.8. Steam Assisted Gravity Drainage (SAGD) in horizontal wells was applied increasing significantly the recovery efficiency, higher than 50%.
Simulation Study of Thermal Well Test Analysis in Steam Injection Wells
Authors: Ghahfarokhi Ashkan Jahanbani , Jelmert Tom Aage , Kleppe Jon
Published: December 2011

Heavy oil reservoirs constitute a huge proportion of total world oil reserves. Among different thermal recovery methods, steam injection is the most widely used method in this type of reservoirs. Monitoring of swept volume over time is very important for evaluation of a thermal project. Thermal well testing offers an inexpensive method to estimate flow capacity and swept volume in thermal recovery processes. Pressure falloff tests are usually used for this purpose.

Estimation of steam zone properties and swept volume from falloff test data in this study is based on the theory developed by Eggenschwiler et al. (1980), assuming a composite reservoir with two regions of highly contrasting fluid mobilities and the interface as an impermeable boundary. Consequently, the swept zone acts as a closed reservoir for a short duration, during which the pressure response is characterized by pseudo steady state behavior.

The purpose of this work is to investigate the feasibility of thermal well test analysis and effects of different parameters. Pressure falloff testing is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Different gridblock models are designed.

Results of this study show that the swept volume, swept zone permeability and skin factor can be reasonably estimated from pressure falloff tests. The effects of gravity, dip, permeability anisotropy and irregular shapes of swept zones are investigated. It is found that these factors do not affect the estimated results significantly. Results of 3D models show that the estimation of flow capacity and steam swept volume depends on the vertical positions where pressure data are measured (i.e. the location of pressure gauges). This finding should be considered in thermal well test interpretation.
Samaria Neogeno Exploitation Plan: FEL Approach and Pilot Test Implementation
Authors: Arteaga Marcela , Aguilar Alfredo , Czwienzek Fabiola , Salve Javier , Aldana Jose Luis
Published: December 2011

This paper presents the planning and development of a project in Samaria Neogeno field, which is a heavy oil field that is located 17 kilometers from Villahermosa, Mexico. The front-end loading (FEL) method was used to design the development plan of the Samaria Neogeno field and to complete the project. FEL is considered to be an international best practice. The Samaria Neogeno field is currently undergoing a period of substantial development, which has resulted in a potential production increase of 30,000 bbl/day. This project is a result of the collaborative efforts of PEMEX and Halliburton.

In general terms, the FEL method includes three stages: visualization, conceptualization, and design. The primary activities include the identification and characterization of the uncertainty variables, definition of decision variables and scenarios, and a stochastic simulation of each scenario. One scenario represents a specific exploitation plan. By using the stochastic simulation process, the degree of risk is quantified and measured by standard deviation; consequently, each scenario evaluated was associated with its level of risk. The consideration of the standard deviation parameter, in addition to the economic indicators, promotes better decision making.

The development of the Samaria Neogeno project has been through the three FEL stages, and the execution of the steam injection pilot project. In the visualization stage, multiple scenarios were evaluated; the higher value options were designed for cold production in the early years, followed by the incorporation of hot production in the short- and mid-term phases. In the conceptualization stage, the most valuable scenario was selected, which led to the development of a steam injection pilot project. The steam injection pilot project represented the largest contribution of information regarding the reservoir and response with steam injection. The average production per well increased from 240 to 1,170 bbl/day, and 30 to 40 barrels of oil was recovered for each ton of steam injected. After obtaining these results, a mass development plan was created, and this plan will be implemented during the current year.

The successful results at Samaria Neogeno field highlights the added value of the FEL method as an international best practice.
Avert Steam Pipeline and Piping Failure and Steam Leaks in the Field
Authors: Majeed Mohammed. A.
Published: December 2011

Steam piping and pipeline whipping, bowing, buckling and jumping are some of the phenomenon observed in the field due to improper design and inadequate commissioning procedures. As a result, ‘steam flood’, ‘cyclic steam stimulation’ and ‘SAGD’ operations experiences long steaming hold-ups, extended shutdowns, production losses and environmental clean-up

Steam pipelines up to 32" diameter and 30 km length, with 11 - 15 MPa design pressure and 250-340 deg C design temperature for quality of steam from 80 to 100%, are being designed with high strength material and thin wall designs. Although, designs are robust and utilizes proven stress analysis tools, but are often fail to address the common field issues of unequal warming, condensate buildup and severe slugging encountered during the commissioning and at the start of the new steaming cycle. Also, piping connections lack the provision to accommodate requisite thermal growth and/or the unequal thermal growth between steam piping, production piping, well heads, batteries headers, leading to severe steam leaks.

Steam pipeline and piping are designed with anchors and guides to deal with thermal growth in the horizontal plane. When steam is charged at the ambient temperature, the cooling of the steam in long length pipelines and resulting condensate build up cause thermal gradient in the pipe wall. This thermal gradient coupled with transition in the piping and pipeline elevations are mainly responsible for the bowing, jumping and whipping phenomenon. Pressure, temperature and strain gauge instrumentation should be installed at strategic location to closely monitor and execute uniform warming up to avoid whipping, bowing, buckling and jumping of steam piping and pipelines.

Every incident of whipping, bowing, buckling and jumping of steam piping & pipelines requires detailed integrity evaluation of the affected sections, prior to putting back into operation. Detailed assessment of wall thinning, ovality, dents and other mechanical damages are mandatory to comply with thin wall designs. The result in most incidents is complete replacement of the affected sections, requiring prolonged and costly shutdowns and risk to the producing reservoir due to lack of pressure.

This Poster Presentation will highlight the three areas where steam pipeline are vulnerable to leak and breakages. Condensate induced steam hammerCasing growth and stress loading of the wellheads.Expansion loops and pipe anchors and Pipe Guides management.