bluuebunny/crossref_metadata_2025 huggingface dataset:
Basin-Wide Pressure Changes Due to CO2 Storage: California Production as a Reverse Analog
Authors: Jordan Preston
Published: July 2010

Storage of point source generated CO2 (such as from fossil-fueled electricity plants) within geologic strata has been proposed as an alternative to emitting this greenhouse gas to the atmosphere. Large quantities (billions of tonnes) of CO2 would have to be stored for this technology to provide significant climate change mitigation. Storage of such quantities raises concern about basin-wide pressure increases and the consequences for hydrocarbon and water resources as well as land surface configuration.

The history of hydrocarbon production in California offers a reverse analog for basin-scale pressure perturbations due to industrial-scale CO2 storage. Cumulative oil production in the State, with most from the San Joaquin Basin, was 4.5 billion cubic meters (28.3 billion barrels) by the end of 2008. This is a volume equivalent to 3.1 billion tonnes of carbon dioxide (assuming a density of 0.7 tonnes/m3), which is approximately 40 times the average annual CO2 emissions from electricity generation within California from 2000 to 2006.

Oil and gas field pressures at discovery during more than a century of exploration in the San Joaquin Basin in California Oil and Gas District 4 were analyzed for time trends in the first part of a multi-year study. While the data suggest a decrease in pressure across the Basin in this District after 1968, the decrease was not significant at the 5% level. This suggests significant interfield compartmentalization of the San Joaquin reservoirs.

Such compartmentalization would limit the impact of CO2 storage-induced pressure increases beyond the target storage volume. This would come at the cost of less storage capacity. However "refilling" the pore spaces from which oil has been removed, likely commencing with CO2–enhanced oil recovery, would provide California with decades of capacity, although pore collapse has reduced this capacity in some areas.
New Temperature-Activated Travel Joint Minimizes Expansion Issues in Horizontal Thermal Applications
Authors: Schultz Roger , Cavender Travis
Published: July 2010

Thermal recovery methods used in the exploitation of heavy-oil and bitumen reservoirs can create severe expansion problems on liner and production tubular equipment. This is more often the case when using horizontal sandface completion configurations in steam flood, cyclic steam, and steam-assisted gravity drainage (SAGD) applications.

Many single lateral and multi-lateral horizontal heavy-oil wells are produced initially using cold heavy-oil production methodologies where liner expansion is not a concern. However, with proper up-front planning and engineering, these wells could be converted to thermal EOR producers with the addition of thermal expansion devices placed within the liner assembly when initially completed. These expansion devices are engineered to activate with elevated temperatures once the thermal operations begin and do not require mechanical activation or well intervention. Since these devices are deployed with the liner assembly, they must also be capable of handling compression, tension, and torque loading across the liner during the deployment phase.

These devices can be deployed with the slotted liner/sand screen applications or can be used with production or concentric tubing configurations. This paper will present different wellbore configurations used with various thermal recovery methods.
Expandable Completion Liners: A Comparison of Performance With Other Completion Types in the Reg and Teguentour Fields, Algeria
Authors: Mason David , Benaichaoui Farouk , John Huw , Okwelegbe Mark , Moum Terje , Harneshaug Tom , Morgan Quentin , Jones Colin , Neumann Juergen
Published: July 2010

Four expandable completion liners (ECLs) have been run in Algeria in two fields - these are the first ECLs in Algeria, the first worldwide in gas wells and the first worldwide in multilateral wells. This paper is the first detailed benchmark study of ECL performance.

All systems to date have been run in 8 ½″ hole using 5-1/2″ base pipe ECL compliantly expanded, and the installations went well.

It has been possible to compare ECL performance data against a comprehensive surveillance data set for the two fields where data from existing openhole completions allow meaningful comparisons. The other completions consist largely of slotted liners and some barefoot completions. The tested production rates in each of the wells have been high relative to normal field trends; however, the predominant factor in this is the reservoir character. PBU analysis indicates that the second well has reduced Darcy skin, while it is considered unproven in the first well (more data over time is needed). There is, however, consistent evidence for a reduction in rate-dependent proportion of total skin in both wells. This is supported by other studies and a consideration of basic principles.

The reduction in the rate-dependent proportion of skin has given an increase in production rate of 5-20% as compared to the computed rate from a slotted liner. This difference assumes no borehole collapse, with analyses and discussion presented of the effect on well performance should borehole collapse occur.
Rejuvenation of Trinidad’s Oropuche Field
Authors: Sinanan B. , Jagdeo H.
Published: July 2010

Over the last decade mature field management has been of paramount importance for economic sustainability and survival for many oil field operators. In Trinidad and Tobago, mature blocks are occasionally leased or farmed out to private operators by the state when the fields are no longer considered to be feasible investments according to state’s economic benchmarks and or operational capabilities.

The Oropuche farmout is one such field situated onshore, south Trinidad in close proximity to the western coastline. In 2007, API Pipeline Construction Company Limited acquired the acreage in 2007 with the production of approximately 60 bopd from 22 wells. This privately owned company was challenged to increase production from existing producers and increase reserves using modern reservoir management practices. Since then the operator had increased production to approximately 300 bopd, planned an eight well infill drilling program and proposed enhanced oil recovery projects. Significant cost has been incurred thus far and more expenditure is expected as projects are phased in. The operator conducted a geotechnical study as required at inception but has continued to study the field and develop new opportunities.

This paper describes the local processes and techniques used in field optimization, creation of a functional organizational structure, development of new opportunities and formulating a practical, reservoir development plan. This work details the work plan that is being adopted by the operator. The successful approach used at the Oropuche field and proposed in this document can assist many operators whoexperience various challenges associated with developing mature acreage and encouraging sustainable operations.
Molecular Design And Fractal Applications In Enhancing Oil Recovery From Low-Permeability Oil Reservoirs By Gemini Surfactant Flooding
Authors: Wei H. , Liu W. , Wei G. , Yin F. , Liu J.
Published: July 2010

High injection pressure and the imbalance between water injection and oil production are two of the difficulties in developing low permeability oil reservoirs. Injecting gemini surfactants is a promising technique to overcome the difficulties to enhance oil recovery from low permeability oil reservoirs. Gemini surfactants enhance oil recovery by lowering the surface tension between oil and water. Gemini surfactant A and gemini surfactant B have same hydrophilic head group and hydrophobic tail. The two surfactants have equivalent capacity of lowering the surface tension between oil and water. Gemini surfactant A enhanced oil recovery by 4%, gemini surfactant B enhanced oil recovery by more than 10%. Based on the fractal dimensions of molecular fragments, the fractal dimension of the spacer group of gemini surfactant A is different from that of gemini surfactant B. The cores of the gemini surfactants flooding formation are analyzed by the method of box counting dimension. The fractal dimension of the spacer group of a gemini surfactant is in relation to the fractal dimensions of the cores.

Gemini surfactant C is subsequently designed and the fractal dimension of its spacer group is less than gemini surfactant B. Gemini surfactant C enhanced oil recovery by more than 20%.

The fractal dimension of the spacer group of gemini surfactant A is close to 2, and the fractal dimension of the spacer of gemini surfactant B is close to 1.4. The fractal dimensions of the cores range from 1.40 to 1.84. The fractal dimension of the spacer group of a gemini surfactant should be less than the fractal dimension of the microstructure of the reservoirs. The gemini surfactants are absorbed more onto the rock surface as the spacer groups of the gemini surfactants are less complicated than the rock surface.

The fractal analyses of low permeability oil reservoirs indicate the fractal dimensions are less than 2, which means the microstructure of low permeability oil reservoirs are different from medium-high permeability oil reservoirs. The fractal analyses of molecular fragments help design more exact and efficient oilfield chemicals.
Bubble Point Pressure Empirical Correlation
Authors: Moradi B. , Malekzadeh E. , Amani M. , Boukadi F. H. , Kharrat R.
Published: July 2010

Bubble point pressure is an important reservoir fluid property. Ideally, Bubble point pressure is determined experimentally in the laboratory; However, this value is not always available and correlations are consequently used to determine it.

At this work, first the published bubble point pressure are reviewed and then a new correlation is developed to estimate bubble point pressure of crude oils in worldwide range.

This correlation is applicable for crude oils of ºAPI ranging between 6 to 57.

The comparison of this new correlation with other published ones shows that it is much more accurate than the other ones.

The average absolute deviation error (percent) of the new correlation is about 16.96%.
Study and Field Application of Profile Control Agent in High Temperature and High Salinity Reservoir
Authors: Dai C. , You Q. , Zhao L. F. , Xiong W.
Published: July 2010

Polymer gel is not suitable for profile control in high temperature and high salinity reservoir. In order to solve the problem above, a good inorganic profile control agent (Na2O·mSiO2) used in high temperature and high salinity reservoir is studied in this paper. The thermal sensitivity, salt sensitivity of sodium silicate and their influence factors in high temperature and high salinity are investigated. The blocking ability and oil displacement ability of sodium silicate in high temperature and high salinity are also investigated through physical simulation experiments. The results show that sodium silicate in high temperature and high salinity can self-generate white precipitation which can effectively block high permeability zone and or thief zone and expand sweep volume. The precipitation mass is related to modulus, temperature and aging time in high temperature; after meeting brine water, sodium silicate can also generate white precipitation and the precipitation mass is associated with modulus, salinity and temperature. Sand pack experiments indicate that sodium silicate in high temperature and high salinity has good blocking and oil displacement effect, which can further enhance oil recovery. Field application results also confirm that sodium silicate is a good inorganic profile control agent in high temperature and high salinity reservoir.
From Trondheim to Trinidad: Utilizing North Sea Technologies in the South Seas
Authors: Siggerud E. I. , Kjellesvik L. E. , Battie J. E. , McCollin R. D. , Oberkircher J.
Published: July 2010

The Norwegian Sector of the North Sea is renowned for the development and implementation of new technology in order to extract hydrocarbons from the earth. The combination of a cultural affinity for technology, harsh and unforgiving operating environment that stretch the limits of man and technology and high value assets combine to create the "Perfect Storm" for the application of technology. So how do you transfer this methodology to an old onshore field in Trinidad?

Fram Exploration is a company based in Trondheim; Norway that has recently been awarded a lease onshore Trinidad. The Management and staff of Fram have extensive experience in the development and implementation of new technologies in Norway and around the world. This paper will describe the methodologies and technologies that have been developed and how they will be applied to an onshore field in Trinidad. These technologies will include cutting-edge sub-surface mapping and geologic evaluation techniques as well as well construction, drilling and completion capabilities. Also included in the paper will be a description of the collaborative decision making process that will be utilized to plan and execute this field development strategy.
New Improved Oil Recovery from Heavy and Semi-Heavy Oil Reservoirs by Implementing Immiscible Heated WAG Injection
Authors: Gholamzadeh M. A. , Hashemi P. , Dorostkar M. J.
Published: July 2010

Only next to thermal processes used to produce heavy oil, gas injection is the second most common enhanced oil recovery process. To increase the extent of effects of the gas on the heavy and semi-heavy oils in the reservoir by gas injection, the gas is generally injected intermittently with water. This mode of injection is called Water-Alternating- Gas (WAG) method. In recent years, there has been an increasing interest in WAG process both miscible and immiscible.

In this paper, an experimental study of immiscible Heated WAG (Heated Water-Alternating-Heated Gas) injection into a sand pack is presented for the first time. This new method is a combination of WAG and thermal process and can be used to produce heavy and semi-heavy oils from hydrocarbon reservoirs. Oil recovery efficiency resulting from Heated WAG injection was significant in comparison with unheated WAG injection. The original reservoir fluid was dead oil, and core flooding experiments were performed on it using carbon dioxide as the injection gas. In this experimental study, the sand pack was initially saturated with dead oil and irreducible formation water. A number of WAG and Heated WAG cycles with low and constant rate and, below the minimum miscibility pressure for this system were injected into sand pack alternatively.

Results of laboratory tests showed that oil recovery efficiency resulting from the immiscible Heated WAG injection is about 15% more than that of unheated WAG injection. These results also indicate that using heated water and heated CO2 instead of unheated water and CO2 can lead to interfacial tension reduction, oil swelling and viscosity reduction. Therefore, immiscible heated WAG injection can be used as an effective and feasible enhanced oil recovery method in heavy and semi-heavy oil reservoirs with significant improved results.
Prediction of Downhole Flow Regimes in Deviated Horizontal Wells for Production Log Interpretation
Authors: Bahrami Hassan , Hosseinian Armin , Rasouli Vamegh , Siavoshi Jamal , Mirabolghasemi Maryam , Sinanan Burt , Bagherian Behzad
Published: July 2010

Production logging is used to evaluate wells production performance. Interpretation of production log data provides velocity profile and contribution of each zone on total production. In multi-phase flow conditions, production log interpretation can be challenging since producing fluids do not have similar densities and travel with different speed depending on fluids properties and wellbore deviation.

Production log interpretation in multi-phase producing wells requires identifying downhole flow regimes and determining velocity profile for each phase. There are different flow regimes and velocity models available, which are being used in production log interpretation to determine wells flow profile in multi phase flow. However in the case of deviated horizontal intervals, the flow model might fail to provide reliable results for gas and liquids velocities.

This paper represents the use of Computational Fluid Dynamics (CFD) simulation in order to model multi-phase flow in the wellbore and evaluate velocity profile across deviated horizontal intervals. The simulation results when integrated with production log data can help estimating velocity for each phase in different flow rates and for different wellbore trajectories.

The approach can help interpretation of production logging data in horizontal multi-phase producing wells, as it can predict downhole flow regimes and identify the intervals having chance of downhole liquids re-circulation. Production logging data in a gas-oil producing deviated horizontal well with water loading in wellbore was used to verify reliability of the numerical simulation. The approach could help to evaluate the well production performance with less uncertainty.
Modeling of Water Coning Phenomena in a Fractured Reservoir and Design a Simulator
Authors: Moradi B. , Dastkhan Z. , Roozbehani B. , Montazeri G. H.
Published: July 2010

The problem of water production is one of the major technical, environmental, and economical issues associated with oil and gas production. It is the general accepted approach to put the well on production below a critical rate without the risk of coning.

The main goal of this study is to prepare a reservoir numerical simulator with emphasis on water coning. Present work mostly involves numerical simulation of water coning and includes proposed correlations in the literature.

The computer program included four distinct modules to calculate: critical or maximum allowable oil rate, water breakthrough time, well performance after water coning take palaces and water coning simulation. Flow equations of water and oil were discretized and numerically solved for two-dimensional coordinates. The implicit scheme was used to calculate unknown pressures of any grid block. For calculation of water saturation, explicit scheme was used.

Real field data of a well in southwest of Iran was put into the program and critical rate, water breakthrough time, well performance after water coning and water coning simulation of reservoir were determined. We found that the results of correlations are very far from the reality. On the other hand, numerical simulation shows good agreement with real production data. In addition, it was observed that the current production rate of this well would result in rapid water coning.

The critical oil rate for water-free production is important in several categories, including limiting the productive life of the oil and gas wells, separation costs, corrosion of tubular, fines migration, and hydrostatic loading.
Miscible Gas Injection Study in a Naturally Fractured Reservoir: A Case Study
Authors: Moradi B. , Tousinia H.
Published: July 2010

Gas injection is the most widely applied process in enhanced oil recovery (EOR) for light oils. Most of the oil production in the Middle East comes from carbonate reservoirs, the majority of which are highly fractured. Gas injection in fractured reservoirs has been used less than conventional single porosity reservoirs. Three natural phenomena of gas channeling, viscous fingering and gravity over ride jeopardize the final oil recovery in gas injection projects. In fractured reservoir due to higher vertical permeability, and strictly higher rock heterogeneity, these phenomena are more probable and this fact will challenge the feasibility of gas injection projects in fractured reservoirs.

In this work, miscible/immiscible gas injection was studied in a fractured reservoir through compositional simulation. The oil field under study is a fractured oil reservoir located in west of Iran. A homogenous DPSP (Dual Porosity-Single Permeability) synthetic model was generated which investigates the effect of molecular diffusion, displacement velocity, gas/oil fracture capillary pressure, slug size and injection pressure of injectant on final oil recovery of gas injection process. Minimum miscibility pressure (MMP) and Minimum miscibility enrichment (MME) of gas injection was determined using slim tube through compositional simulator.

Three possible scenarios – natural depletion, miscible gas injection and immiscible gas injection were compared. Results indicated that miscible injection yields better recoveries than the other, so miscible gas injection in this reservoir can be a potentially good scenario.
Flow Units: From Conventional to Tight Gas to Shale Gas Reservoirs
Authors: Aguilera Roberto
Published: July 2010

Process or delivery speed represented by the ratio of permeability and porosity is shown to provide a continuum between conventional, tight and shale gas reservoirs. The surprising result, based on core data from various North American basins, leads to distinctive flow units for each type of reservoir.

The approximate boundary between viscous and diffusion dominated flow is estimated with Knudsen number. Viscous flow is present, for example, when the architecture of the rock is dominated by megaports, macroports, mesoports and sometimes microports (port = pore throat). Diffusion flow on the other hand is observed at the nanoport level. Results from this research compare well with the observation that grains and pores are smaller in shales as compared with tight and conventional gas formations.

The process speed concept has been used successfully in conventional reservoirs for several decades. However, the concept presented in this paper for tight gas and shale gas reservoirs, with the support of core data, is new, and permits differentiating between viscous and diffusion dominated flow. This is valuable, for example, in those cases where the formation to be developed is composed of alternating stacked layers of tight sands and shales, or where there are lateral variations due to facies changes.

It is concluded that there is significant potential in the use of process speed as part of the flow unit characterization of unconventional gas reservoirs.
Selection of Three-Phase Relative Permeability Model for Mixed-Wet Reservoirs
Authors: Behzadi S. H. , Alvarado V.
Published: July 2010

The most widely used three-phase relative permeability models are Stonel and Baker. The mixed-wet condition is perhaps the most frequently encountered wetting condition worldwide. Two models for mixed-wet systems have been developed in recent times, Blunt's (2000), which is somewhat complex to use in simulators, and Jerauld's (1997) that is relatively easier to implement. The model incorporates the effect of interfacial tension (IFT) between phase pairs as well as the ability to model mixed wettability and incorporates IFT effects. In this paper Stonel and Jerauld's models are compared.

We illustrate the differences in performance prediction between the two models in three-phase oil relative permeability (kro) for the same two-phase relative permeability data sets. We show how these formulations can be used in commercial simula¬tors. Recovery prediction differences as well as the effect of gas miscibility on oil relative permeability to water (krow) are shown. Results show that three-phase kro values, based on Jerauld's model, can be up to 2 times lower than those predicted by using Stonel and consequently recovery might be overestimated by 21% at immiscible condition, while at 80% miscibility, the underestimation becomes only 0.75% if Stonel model is used. Gas miscibility diminishes krow, resulting in lower recov¬ery. The recovery is overestimated by 13% at 80% miscibility, if the effect of miscibility is only accounted for oil-gas relative permeability. We show the importance of using an adequate three-phase model in mixed-wet system in addition to account¬ing for the effect of gas miscibility on oil-water relative permeability.
Nonisothermal Assessment on the Performance of Polymer Flood in the Reservoir with Elevated Temperature
Authors: Lee Kun Sang
Published: July 2010

Accurate assessment of the potential of a nonisothermal polymer flood process for mobility control requires a model on the viscosities of reservoir fluids as a function of temperature. The temperature dependence of viscosity was included in the reservoir model and an extensive numerical simulation was conducted to examine the effects of temperature-related viscosity model on the reservoir performance during polymer flood in the reservoir with elevated temperature. A three-dimensional numerical model for fluid flow, mass transport, and energy balance is used to analyze the performance of the reservoir operating under polymer flood followed by waterflood. The nonisothermal scheme can be used as a quantitative tool to evaluate the comparative studies of different polymer flooding scenarios with respect to temperature dependence of fluids’ viscosities. Results of cumulative oil recovery and water-oil ratio (WOR) at the production well and injectivity at the injection well are presented for various types of temperature dependencies, reservoir temperature, and oil viscosities.

The simulation scheme with thermal dependence of fluids’ viscosities allows a more quantitative prediction of reservoir performance. Significant improvement in predicted oil recovery and reduction in WOR is obtained for the case of including temperature dependencies of both water and oil because the reduction of oil viscosity is larger than that of brine viscosity. The inclusion of heat loss to over/underburden formations had limited effect on the oil recovery because of relatively small temperature difference under the conditions considered in this study. More rapid reduction of oil viscosity results in the considerable reduction in mobility ratio and significant increase of oil recovery at higher temperature. High oil recovery was obtained with small values of oil viscosity, but the improvement is not proportional to the reduction of oil viscosity.
Internal Pipeline Corrosion Study on the Changes From Oil to Gas Production
Authors: Wang H. V. , Allan K.
Published: July 2010

The switch from oil to gas production will dramatically change the operation conditions in the producing wells, topside facilities, and transportation pipelines. Besides the changes in gas/liquid compositions, operating pressure and temperature, multiphase flow in the pipeline will also shift from a high-liquid load pattern to a low-liquid load pattern. Typically, the demarcation point between the two patterns could be considered as GOR of 1000 SCF/BBL. Forecast of the field studied in the paper indicates that the transition might happen after a few years and GOR will increase gradually with the aging of the wells. The changes will have a great impact on internal pipeline corrosion and corrosion inhibition and thus require a systematical study to identify the keys parameters and strategize a suitable corrosion management plan.

In this paper, the experiences gained from current corrosion monitoring and corrosion inhibition programs were reviewed first. Corrosion scenarios were also analyzed for future operational conditions by conducting both fluid- dynamic analysis and corrosion risk prediction along the pipeline for a wet gas environment. In order to study the impact of flow on the corrosion inhibitor application, laboratory tests were carried out to evaluate the incumbent corrosion inhibitor for future wet gas environment. The lab study focused on testing the partitioning capability of the corrosion inhibitor at different water cuts (10% – 100% water cut) and the localized corrosion risk due to the high shear stress using both rotating cylinder electrode (RCE) apparatus and rotating cage type of autoclave. The study showed that, though the corrosion risk of the system was determined to be relatively low, the option of applying corrosion inhibitor by batch treatment should be ruled out due to the possible breakdown of inhibitor film in a turbulent flow, which is associated with high shear stress and subject to gas bubble impingement. Lab tests also indicated that continuous treatment of 25 to 50 ppm corrosion inhibitor could minimize the localized corrosion risk of carbon steel pipeline in a 150-Pa shear stress flow.
Computer Modeling and Simulation of High Frequency Vibration Recovery Enhancement Technology in Low-Permeability Reservoirs
Authors: Guo X. , Du Z. , Li Z.
Published: July 2010

Comparing to conventional production methods, high frequency vibration recovery has many advantages during development of low permeability reservoirs, such as effectively improving reservoir permeability, deceasing fluid mobility, enhancing single well production, low cost and low pollution. However, at present, researches on high frequency vibration recovery are limited to qualitative interpretation, and quantitative research and theoretical system are lack of completeness, which cause the disability of correctly choosing the optimistic production method and the optimization of the technical parameters. In this paper, by analyzing and integrating principle and theories of reservoir engineering, flow in porous medium, acoustics, rock mechanics and numerical analysis, acoustic pressure relation equation was established and a quantitative description about the porous media reservoir and fluid parameters alteration after high frequency vibration effect were attained. Furthermore, a preliminary mathematical model and computer modeling under high frequency vibration effect in low permeability reservoir were developed. This study was successfully applied to simulation of high frequency vibration recovery in a low permeability reservoir in Western China. The result showed that high frequency vibration recovery could stimulate single well production and improve the development efficiency of low permeability reservoir.
Detecting Shallow Drilling Hazards in Large Boreholes Using LWD Acoustic Measurements
Authors: Prilliman J. , Tang X. , Archer M.
Published: July 2010

Shallow drilling hazards present a significant risk to the health, safety, and environment of upstream oil and gas operations. Shallow marine formations are often near the critical porosity limit, where the sediment is very poorly sorted, mechanically weak and often unconsolidated. As the sediment begins to compact, well-construction challenges are created as formation stresses and fluid pressure changes, usually resulting in the operator having to set extra casing strings near the surface. The United States Department of the Interior, Minerals Management Service (MMS) requires the use of a diverter and a conductor string of casing if there is any possibility of a shallow hazard in the area of a proposed well. Proving shallow hazards do not exist in the area requires resistivity and porosity logs approved by the MMS. This operator requested these logs be run in 22 and 17 ½ in. boreholes using Logging While Drilling (LWD) technology as no wireline logging was planned. In large hole sizes, the porosity log is generally the limiting factor for most wireline and LWD technologies, with nuclear measurements from most vendors designed for hole sizes no bigger than 12 ¼ in. LWD Acoustic measurements in this well provided acceptable determination of porosity in borehole sizes up to 22 inches in extremely slow formations.

The objective of this application was to acquire an LWD acoustic compressional slowness log below the drive pipe. Modeling shows and supports the ability to measure in this demanding environment where the compressional slowness often approaches that of the drilling mud. A 9 ½ in. LWD acoustic device was optimized for shallow data acquisition for the large borehole size and very slow acoustic velocities anticipated. While drilling, real-time LWD logs showed conclusive evidence of the absence of hazards and were immediately accepted by the MMS for the waiver.

This paper validates the feasibility of using LWD logs to gain a conductor waiver from the MMS. Benefits include reduced operating costs associated with a wireline program and the savings involved in removing the conductor string from the casing program. On this multi-well batch drilling project operational savings of about 2.15 million USD were realized.
Horizontal Well Placement Optimization for Heavy Oil Production in Girasol Field
Authors: Cuadros Jaime , Ossa Nicolas , Cuadros Guillermo , Rojas Esteban
Published: July 2010

Girasol, one of the largest heavy oil fields in Colombia, is located in the Middle Magdalena Valley basin. The field is composed of a shallow sequence of sediments of fluvial origin in which sandstone channels contain heavy oil of 11- to 13°-API gravities.

Similar fields in the country are developed using thermal recovery techniques via vertical or deviated wells. As horizontal wells have proved to offer advantages for enhanced oil recovery, from the first stages the Girasol field development plan included the execution of horizontal wells to apply cyclic steam injection techniques.

Four different stacked sandstone reservoirs, located at 1,100-ft to 1,600-ft true vertical depth (TVD) below surface, are the main targets. The project included a series of parallel horizontal wells of 1,200-ft to 2,350-ft lateral extension, with a fixed lateral spacing and vertically placed to drain one reservoir per well. The targets were geological, 10- to 20-ft thickness to maximize production.

Horizontal well placement in this scenario—shallow, thin, and friable formations— is, in general, difficult to achieve with the use of conventional geosteering techniques, as they generally fail to identify unexpected changes in the reservoir geometry, increasing the risk of poor results. This risk was minimized by using deep, directional electromagnetic measurements while drilling, enabling the reservoir geometry mapping in real time, several feet from the borehole.

Results of the use of this technology—combined with continuous inclination measurement near the bit and an advanced geosteering process— include 96% average net pay, minimization of unproductive drilling, rig time savings, and sidetracks avoidance after 24 horizontal wells drilled to date. The strategy used for horizontally placing wells in the Girasol field can be used in similar fields worldwide.
Sand Settling and Locations of High Erosion in Subsea Production System
Authors: Shirazi S. A. , McLaury B. S. , Sow E. , Butter M. , Folefac A. , Hassaballa S. A.
Published: July 2010

When higher than expected sand volumes were produced from Gas Field #1 after a 2nd well group was brought on line it was initially believed that the sand production came from these new wells. Several sand production and erosion studies were initiated to investigate this sand production. Sand transport studies were conducted as part of the investigation. These studies demonstrated that the sand was produced by the 1st well group, rather than the 2nd, but that the sand was not being transported through the main export lines until after the 2nd well group came online and the gas velocities through the flowlines increased. These findings were supported by other observations made in the field following the initial detection of the sand production, while the studies were on going.

Erosion calculations, covering the full range of flow conditions that are expected over the life of the field, were conducted to examine and determine locations of high particle impact rate. The results of these calculations are used to optimize present and future ultrasonic thickness (UT) measurement programs so that critical locations can be targeted with higher localized resolution. Experimental flow studies were also performed to validate the Computational Fluid Dynamics (CFD) erosion calculation model. This CFD model was in turn used to model those parts of the subsea infrastructure that are most prone to erosion under field operating conditions, the Pipeline End Manifold (PLEM). For these flow studies a scaled down version of the PLEM, was built. The CFD results agreed well with the experimental results indicating that the CFD results are accurate in predicting the location of impacts. This was a very important finding because the CFD modeling is used to examine actual pipe geometries within the well and subsea flowline system for various flow and operating conditions during the life of the wells. The results from this work led to more focused and accurate erosion monitoring.
Simultaneous Production of Oil and Gas Reserves From Single Wellbore
Authors: Nagib Mohamed , Ezuka Ifeanyi , Nasr Ghasem G.
Published: July 2010

Maximising oil recovery in thin and ultra-thin (<30ft) oil columns is a challenge as a result of conning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal well when bottom or edge water encroachment or invasion takes place.

The development of the gas resources from these reservoirs is a major challenge as regulators want optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to LNG projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral well in simultaneous oil and gas development; the first (top) horizontal lateral well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second or lower horizontal lateral well leg will be completed, right above the gas-oil contact.

Extensive numerical reservoir flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoir by providing a cost effective technology solution. The numerical simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with large gas cap as compared to conventional wells and also provide opportunity for auto gas lift for low API gravity crude.

This paper presents; i) the use of intelligent multilateral wells to simultaneously produce oil and gas from the same wellbore in the thin oil reservoir and ii) provide information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoir using intelligent well technology including cost effectiveness.
Miscible Gas Injection: A Successful Experience Leading to Proper Reservoir Management Through Simulation Study A Carbonate Case Study
Authors: Sajjadian S. , Sajjadian V.A. A , Roostaeian M. , Ghafoori M. R , Ataabadi V. Mahmoudian
Published: July 2010

Miscible gas displacement is known as one of the most efficient EOR methods throughout the world. The mechanism is seem to be promising in homogeneous sandstones but is quite challenging when it comes to heterogeneous carbonates.

The studied field is among the tight heterogeneous carbonates from southwest of Iran. The reservoir in an undersaturated high pressure oil reservoir with no active aquifer. Due to low permeability of the reservoir, a miscible gas injection was thought to be efficient in increasing the oil recovery, maintaining the reservoir pressure and increasing the production plateau. A full compositional simulation model was built taking into account reservoir heterogeneities. The simulation study includes history matching of the past reservoir performance, optimization of the gas injection well number and location, and optimization of gas injection and oil production rates. After running sensitivity analysis, the reservoir engineers came up with drilling of the 6 crestal gas injection wells.

In Addition, the water injection was thought as an alternative for EOR purpose but it didn't show up well and was given up.

The outcome of this simulation study nominates the miscible gas injection as the most promising method concerning the reservoir management purposes as it increases the recovery from 16% to around 42% through 40 years of production and could maintain the plateau of 120000 bopd up to 19 years from the production start.
Integrated Uncertainty Quantification by Probabilistic Forecasting Approach in the Field Development Project
Authors: Sajjadian S. , Asheghi A. , Roostaeian M. , Ghafoori M. R , Sajjadian V. A , Hashemi A.
Published: July 2010

Development studies examine the importance of geologic, engineering, and economic parameters to formulate and optimize production plans. If there are many factors, these studies are high-priced unless simulation runs are chosen and analyzed efficiently. Reservoir studies require integration of geological properties of the reservoir, drilling and production strategies, and economic parameters. Integration is complex, because parameters such as permeability, drive mechanism, structural framework, and fluid saturation distributions are uncertain. Uncertainty in permeability, for example, could be caused by prediction at unknown locations from inexact seismic data, poorly distributed of precise well data and imprecise seismic data. Therefore the impact of uncertainty levels in key geologic and production parameters such as NTG, permeability, porosity, vertical transmissibility, skin factor must be assessed.

The application of the system on a single, sector carbonate reservoir unit is taken through a development-plannig case study based on Field Development Plan, FDP. Ultimate recoveries, profiles, and economics for the range of possibilities are evaluated.

Uncertainty quantification is attained in the development of a method that can model and quantify uncertainty in reservoir simulation in an efficient and practical way. In this study variety of approaches are investigated to estimate the uncertainty in a recovery prediction. The methodology which is employed in this study uses Monte Carlo simulation approach (probabilistic forecasting) and efficient selective simulation runs with simultaneous, multi variable input modifications. The results indicate that in terms of reserves points of view the main uncertainties are represented by NTG and permeability distribution. This can be attributed to indigenous heterogeneous carbonate reservoir deposition and dissolution. The uncertainity to the OOIP is also affected mainly by the reservoir structural framework; reservoir top depth variations.
Thermodynamic Fluid Characterization in a Compositional Reservoir Model: A Field Gas Injection Study
Authors: Sajjadian S. , Ghafoori M. R. , Roostaeian M. , Hashemi A. , Asheghi A. , Sajjadian V. A.
Published: July 2010

In order to create an integrated simulation model, it is essential to have a fluid characterization based on revision and validation of the available laboratory data. These include PVT studies, production data, RFT logs, etc. In case of EOR process modeling, it is necessary to also consider the special fluid tests (swelling test and displacement measures on cores) which permit the evaluation of the injected gas effect on the original fluid properties in the reservoir, particularly at the saturation pressure.

The thermodynamic study based on the available experimental PVT data, taken from three appraisal wells of a carbonate oil field is presented. The fluid system flowing throughout two reservoir levels is characterized by means of equations of state finalised to a full 3D gas injection reservoir study. The objective is optimizing the field production strategies considering the injection of natural gas.

Overview of all the experimental data shows a good agreement among the tests performed on samples belonging to the same level. In this study two equations of state (three parameters Peng-Robinson equation) have been calibrated for the two levels. The simulated PVT parameters by the tuned EOS for the two levels are in good agreement with the already measured experimental data. In addition, the swelling test simulation shows a fair match within limits of cubic EOS.

The slim tube experiments performed by laboratory to state the miscibility/immiscibility condition of the reservoir oil with respect to the gas extracted at the separators are also simulated. Consequently the sensitivity of the miscibility conditions to possible variations of the composition of the injected gas is investigated.
Quantitative Evaluation of Aquifer Diversion to Surrounding Wells after Multiple Large Polymer Gel Water Shutoff Treatments
Authors: Turner Ben , Nwaozo Jude , Funston Brad
Published: July 2010

From April through August of 2009, seven producing wells in the Spring Creek field in the Bighorn Basin of Wyoming were treated with chromium acetate crosslinked polyacrylamide in an attempt to reduce water production, lower fluid levels and achieve more drawdown, resulting in improved oil production. The wells were chosen because of their high productivity, high water cut, suboptimal operation because of pump limitations, and in some cases, marginal economics.

The volume of the gel treatments, which were pumped through tubing with a packer above the productive formations, ranged from 8000 bbls to 11,500 bbls depending on the theoretical maximum productivity of each well when pumped off. The Spring Creek field produces out of the fractured Tensleep sandstone, and the fractured Phosphoria carbonate. The main drive mechanism is bottom water, but reinjection of produced water contributes to some reservoir sweep.

After the seven wells were aggressively treated and returned to production, water rates were reduced by 72%, unfortunately oil rates were reduced by 56%. Following the treatments, however, the total oil production for the areas surrounding the treated wells had increased. It is believed that the increase in oil production is attributed to the diversion of the drive water to other unswept parts of the reservoir with higher oil saturation. The large size of the treatments and extent of penetration through the fractures played a significant role in accomplishing this diversion.

In similar wells treated with a smaller volume of gel, water reduction was not as significant, oil loss was not as great, and the increase in area oil production and added reserves was not as observable. This paper quantifies the favorable effects and economics of this larger more aggressive gel treatment strategy.
A Tertiary Steam Flood Strategy Case Study for an Extra-Heavy Iranian Oil Reservoir
Authors: Tehran S. T. , Mohebbi A. , Enayati M.
Published: July 2010

Steam injection in naturally fractured formations has been drawing considerable interest for more than three decades. It is believed that the steam heats the rock, which then undergoes a thermally induced wettability reversal. Hot water can then spontaneously imbibe into the water wet rock matrix, resulting in favorable oil recoveries. In this study, the applicability of steam injection in an oil wet undeveloped Iranian extra-heavy oil fractured carbonate reservoir is discussed. A geological model calibrated with results of a handmade model was used to study the optimum operating conditions under continuous steam injection. It was observed that under this operating strategy in which the main oil production mechanism is heat transfer, steam injection rate and existence of layers which are open to flow, injection and production pattern are directly related to success of the process and because of high viscosity of oil at the reservoir temperature its influences on final recovery is negligible. Initial pressure of the undertaken reservoir is 927 psi at 1700 ft depth. The gravity of the oil is 7.24 °API with viscosity of about 2700 cp at reservoir temperature. This field is a highly fractured carbonate reservoir with 3.6 billion barrel estimated oil in place. It was further observed that during 50 years which this reservoir has been undertaken to study under discussed recently found strategy, crude oil production reaches to more than 900 barrels per day.