bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Pore Throat Size and Use of the Waxman-Smits Equation to Determine OOIP in Spindle Field, Colorado
Authors: Kolodzie Stanley
Published: December 2007

This paper describes the development of a method used to define pay and calculate OOIP in the Spindle Field. Traditional methods of calculation do not yield reliable results for pay or OOIP due to the shaly sand nature of the reservoir rock. The Spindle Field contains more than 1,150 wells and covers parts of seven townships in northeast Colorado (Figure 1).

In this study, a minimum pore throat size of 0.5 microns was selected as a pay cut off. Methods were developed to estimate from logs the porosity and permeability data necessary for input into an equation to calculate pore throat size. Water saturations were calculated using a form of the Waxman-Smits equation. Cation exchange capacity values were estimated from the SP log for input into the Waxman-Smits equation. The net pay intervals were combined with the results of the Waxman-Smits equation to give values of hydrocarbon pore thickness (HCPT) in individual wells. The HCPT values of the field wells were spotted on a map and a volumetric analysis made to give an OOIP figure.

Confirmation of the pay definition was made by the correlation between calculated HCPT and ultimate primary recovery of twenty individual wells. Confirmation of the OOIP calculation results was made by the nearness of the OOIP calculated using this method to an OOIP estimate made from ultimate primary recovery of the Amoco wells in the field.
Insert String Technique Reviving Idle Wells
Authors: Sulai A. T. , Hassan Y.
Published: December 2007

Low reservoir pressure is the major contributor to low production in Temana field that cause some of high water cut wells to quit production. The existing gas lift system is not effective due to low liquid level in the tubing resulting in the wells keep on circulating the lift gas. A simple technology called "insert string" was applied to address this problem.

Temana field consist of shallow and intermediate reservoirs, with depths ranging from 1800 ft to 4000 ft. The intermediate reservoirs are mostly solution gas drive and reservoir pressure depleted drastically causing more wells to quit production. The shallow reservoirs are combination of water and solution gas drive dominated by the latter with low reservoir pressure ranging from 600 to 1,100 psig. However when the water cut increases, liquid level in the tubing drops and causing the well to quit production.

The first insert string was installed in April 2002 with the main objective to stabilize production by adding one more gas lift injection point below the last existing gas lift mandrel. Following the success of the first job, several additional insert strings were installed to revive the idle wells. In conclusion, the insert string is a very practical, low risk and low cost technology that effectively improves productivity from low pressure wells and successfully reactivates the idle wells. This paper highlights the successful application of the technology and the lesson learned.
Using Economic and Production Evaluation Methodologies to Expedite Commercialization of Intelligent and Multilateral Wells
Authors: Ramos X. , Anderson A. , Sakowski S. A. , Hogg C.
Published: December 2007

Despite potential and proven benefits, intelligent and multilateral wells have yet to achieve the greater-than-fifty-percent adoption level that would qualify them as truly commercialized technologies. The prevailing perception is that while these technologies hold significant potential to reduce costs in high-end, niche applications, they are too high-tech and high-risk to justify for middle- and low-end applications. The reality is that economic and production benefits exist across all types of applications, but proving it has posed a challenge.

Technology champions cite potential value drivers for intelligent and multilateral wells, including reducing drilling cost, minimizing intervention expense, optimizing production and enhancing recovery. Cost reduction is a tangible benefit that can be easily estimated to justify an installation and easily recorded to measure its success. However, estimating production enhancements and incremental reserves is more demanding and has thus far been underused to evaluate these technologies.

This paper will present a number of cases in which the value of both intelligent and multilateral wells has been estimated using conventional production and reservoir engineering techniques. The paper will explain how nodal analysis and reservoir simulation techniques have been applied to evaluate and compare wellbore and reservoir performance for conventional versus intelligent wells. The authors will also show how economic cases for such advanced completions can be built on the foundation of these analyses.
Improving the Closing Characteristics of Subsurface Safety Valve with Combined FEA and CFD Modeling/Numerical Analysis
Authors: Li L. J. , Zhang H. , Davis G. R. , Kalb F. D. , Hamid S.
Published: December 2007

Surface-Controlled Subsurface Safety Valves (SCSSVs) are designed to automatically shut-in a well below the earth's surface in the event of damage to the wellhead or other key components of a completion string. Flow rates in highly productive gas wells can produce stresses that exceed the design limits of a typical subsurface safety valve during closure in blowout conditions. High-rate uncontrolled flow conditions can act to prevent a SCSSV from closing or can subject the valve to stresses that the valve cannot withstand. Flow tests conducted to verify valve performance under certain flow conditions are often not capable of predicting valve performance when the valves are subjected to flow conditions different from the test conditions. Because the net force on the flapper is a function of the flow parameters, a valve that tests successfully at one set of conditions is not guaranteed to perform successfully in a different set of conditions.

This paper will discuss the use of Finite Element Analysis (FEA) combined with Computational Fluid Dynamics (CFD) to economically and effectively determine 1) if a SCSSV will close under various flow conditions, and 2) whether it will withstand the associated forces generated during the closure. If this method is used, the flow tests could then be used to verify the accuracy and confirm results of the FEA and CFD analyses. After the FEA/CFD models are validated through flow testing, the performance of the valve in response to changes within the flow parameters or safety valve configuration can then be predicted using FEA/CFD models. Actual testing can be performed only to confirm the results of FEA/CFD or may be avoided completely.
Effect of Geologic Parameters on CO2 Storage in Deep Saline Aquifers
Authors: Mo S. , Zweigel P. , Lindeberg E. , Akervoll I.
Published: December 2007

The results of modeling injection into and long-term storage of CO2 in a deep saline aquifer with a commercial black-oil reservoir simulator are presented. Realistic CO2/water pVT properties covering all pressure, temperature and compositional conditions accounted for during the simulations have been used. The pressure and temperature in the aquifer is above the CO2 critical pressure and temperature giving rise to the existence of a two-phase fluid system of CO2 as a fluid and an aqueous phase containing dissolved CO . The impact of CO2 injection rate, reservoir layering, capillary pressure and residual CO2 saturation for water re-entering CO2 filled volumes (hysteresis in fluid saturations) on CO2 distribution and storage in the deposit have been studied. The re-distribution of water occurs after stop of CO2 injection due to gravity segregation of denser CO2 saturated water and CO2-free water.

For upscaling studies a small section of the reservoir model (typically a reservoir grid block) was finely gridded and studied separately for various reservoir parameters and injection rates. The fine model showed that the sweep efficiency of CO2 displacing saline water and both position and quantity of CO2 in each grid block of the reservoir model are sensitive to the CO2 injection rate and the effective vertical permeability. By increasing the viscous to gravity force ratio, the sweep efficiency increases resulting in more CO2 trapped as residual gas. More CO2 is also trapped in the case of increasing CO2-water capillary pressure. Estimating the amount of trapped CO2 from the average CO2 saturation is possible when the sweep efficiency is good (evenly distributed CO2) but may give bad estimates when CO2 only enters part of each large grid block. This shows that to get reliable estimates of the amount of trapped CO2 the distribution of CO2 in each grid block is important and the traditional upscaling methods have to be extended to incorporate the effect of CO2 distribution on trapped gas. Especially the effect of fine-scale layering must be upscaled properly.
Transient Flow in Naturally Fractured Reservoirs and its Application to Devonian Gas Shales
Authors: Kucuk Fikri , Sawyer Walter K.
Published: December 2007

For many years gas has been produced naturally from Devonian shales throughout the Appalachian Basin at rates which made them commercially feasible. In 1975, because of the deteriorating gas supply situation in the United States and increasing demand for energy, the U.S. Department of Energy (DOE) established the Eastern Gas Shales Project (EGSP) as part of the Unconventional Gas Recovery (UGR) program to study and characterize and to develop economically feasible technology for further exploitation of Devonian shale gas reservoirs.

Devonian shale gas reservoirs typically are characterized by a low storage, high flow-capacity natural fracture system fed by a high storage, low flow-capacity rock matrix. In this study analytical solutions are developed to analyze the basic fractured reservoir parameters that control well productivity. These parameters include fracture system porosity and permeability, matrix porosity and permeability, and matrix size.

It is shown that the conventional well test method does not usually work for fractured Devonian shale gas reservoirs. For most cases, the semilog plot of the drawdown and buildup data does not show two parallel straight lines with a vertical separation.

Numerical solutions are also used to include the Klinkenberg effect and desorption in the shale matrix.
Integrated Reservoir Characterization for the Redevelopment of a Highly Complex Field
Authors: Badessich M. F. , Gait M. , Carbone C. , Dzelalija F. , Giampaoli P.
Published: December 2007

This paper is a case study of the redevelopment of a highly complex and heterogeneous reservoir located in the folded belt of Neuquén basin, Argentina. The objective is to describe the integrated reservoir study that was performed; as a consequence, an aggressive drilling campaign was implemented which derived in a boost in production with no substantial interference among wells.

The field was in a mature stage as it came into production in 1984 by primary recovery and oil rate was declining steadily.

Cerro Fortunoso field represents a challenge for optimising the depletion strategy because of its non conventional qualities such as the presence of an under-saturated oil in coexistence with an extensive CO2 gas cap, the heavy oil located in a highly heterogeneous fluvial reservoir with poor petrophysical conditions and flanks dipping more than 60 degrees. Besides good data acquisition for seismic is hindered by surface volcanic rocks and complex geology.

Field operation is intricate because it is placed in a natural reserve; as a result, drilling and production activities are more expensive in order to comply with environmental regulations.

As the reserve to production ratio was exceptionally high compared to other fields in the area, it was suggested that production could be increased but the challenge was how to accomplish this objective in a supposedly fully developed reservoir where the low productivity of the wells had a profound impact on economics.

The multidisciplinary team concluded that both the geological and engineering features contributed to a low recovery factor which could be improved by infill drilling. New technology was used to drill 9 vertical and 16 deviated wells in only two years. The results were so spectacular that it not only arrested decline but also established a new peak of production.

The conclusions show that many fields that are thought to be fully developed, still have a lot of new oil to be produced. Reservoir management plays a major role by improving final recovery and project economics.
An Analytical Study of Transient Flow in Systems with Radial Discontinuities
Authors: Satman Abdurrahman , Mauricio Eggenschwiler , Tang Ray W-K , Ramey H. J.
Published: December 2007

A recent study of pressure falloff for steam injection and air injection in thermal recovery yielded surprising results. It was possible to measure the volume of the gas-filled displaced region with accuracy, and the method did not depend upon regular geometry for the displaced region. This meant it was possible to detect fuel concentration in forward combustion or perhaps vertical heat loss in continuous steam injection by using a pressure transient test. There also appeared to be other potential applications for enhanced oil recovery. An initial paper on this subject was presented at the California Regional Meeting in April 1980.10 This paper is an extension of that study.

The new solution described in this paper is an analytical solution for a circular well with a skin effect and wellbore storage. The well is in a composite system with a circular inner region whose conductivity and diffusivity are different from those in the outer region. There may be either a constant pressure, closed, or infinitely-distant outer boundary. The solution method is Laplace transformation followed by both numerical and analytical inversion. Most graphs and results were obtained by numerical inversion.

Solutions were compared with previously published Bixel and van Poollen results.6 They presented the figures of pD versus tD for different values of the diffusivity ratio and mobility ratio. However, apparently only one value of the radial discontinuity was used in developing the results. In the present study, the dimensionless figures of pD versus tD for various values of radial discontinuity and also for a well with a skin factor and wellbore storage were developed.

Early results of the present work indicated that the system with the radial discontinuity behaved like a closed system prior to the beginning of the semilog straight line of the second region. This paper discusses the evaluation of the dimensionless form of the solution in terms of parameters such as mobility and diffusivity ratios and the magnitude of the radial discountinutiy.
Development of Systematic Hydraulic Fracturing Technology for a Naturally Fractured Reservoir
Authors: Zhao Z. , Liu D. , Liu W. , Chai L. , Zhou H.
Published: December 2007

Reservoir N is a typical low-permeability buried-hill fractured reservoir with oil-bearing area of 3.6Km2, OOIP of 973 × 104t and buried depth of -1700 ~ -2500m.Its oil bearing interval is longer, between 125 ~ 410m.Its average porosity is 5.1% and average permeability is 23.6× 10−3µm2. Due to the insufficient natural energy, its pressure coefficient is 0.98. As the economic yield can't be achieved by conventional technologies, the reservoir must be fractured integrally. Following technologies have been applied in the field. Based on early and proper water injection, supplementing formation energy and maintaining formation pressure, fracturing and waterflooding are combined reasonably to improve waterflooding sweep efficiency and avoid watering out and water channeling at the same time; the concept of optimizing fracturing design for high sand content, large discharge capacity, medium and low proppant concentration and medium and long fractures is established so that artificial fractures can be communicated with natural fractures and a complete interconnected system can be formed by pores, artificial and natural fractures in the reservoir; with the method of perforating short intervals, avoiding perforating long intervals and staged fracturing, the whole oil-bearing interval is divided into 2 to 4 fracturing units which are fractured from bottom to up till all the interval are fractured; silt is used as the fracturing fluid loss additive to reduce excessive fracturing fluid loss and used for propping fractures and connecting major fractures and natural microfractures. Reservoir N has been fractured for 96 times by this method with cumulative oil production of 98.3 × 104t. Field applications indicate that the method of integral fracturing development is also suitable for the low-permeability fractured sandstone reservoirs which are similar to Reservoir N and good development effects have been got.
A TFL Caliper for use in Subsea Flowlines and Wells
Authors: Pierce Aaron E. , Rickey W. P. , Dieckman H. E.
Published: December 2007

A pumpdown caliper1 has been designed, built and successfully field tested and is now commercially available for worldwide use. The tool is self contained and utilizes the features of the standard wireline version of the Kinley caliper.2 It is designed for use in 3 and 4-inch inside diameter (I.D.) tubing and will measure discrepancies in the pipe as small as 0.03-inch. The tool can be used for surveying subsea wells equipped for through flowline (TFL) and for horizontal flowlines on land. Both types of applications have been successfully tested under field conditions.
Evaluating the Magnitude of Time-Lapse Effects Through 4D Core Tests: Lessons From a North Sea Reservoir
Authors: Golfetto F. , Meazza O. , Sturniolo A.
Published: December 2007

Quantifying the expected acoustic changes induced by production is crucial for the success of any 4D reservoir monitoring project.

To this end, 4D core measurements performed by simulating in Laboratory the varying conditions occurred during the life of a field provide the magnitude of these changes. Experience made for a North Sea reservoir shows the significance and validity of such measurements.
"Systems Analysis" Use for the Design and Evaluation of High-Rate Gas Wells
Authors: Crouch E. C. , Pack K. J.
Published: December 2007

The use of "Systems Analysis" curves has proved to be a valuable tool when designing high rate gas completions and evaluating well performance. This paper presents the practical application of "Systems Analysis" when used in gravel pack completion design and shows several case histories of actual performance of high rate gas wells in the Gulf of Mexico.
The Relationship between Clean Fluids & Effective Completions
Authors: Rike James L.
Published: December 2007

The preponderance of evidence shows chat completion effectiveness, and especially well productivity, is directly related to the use of clean completion and workover fluids.

Even small amounts of solids (500 ppm) in completion and workover fluids can be enough co bridge in perforation tunnels, in channels behind pipe, and in gravel packs and in propped fractures. This plugging is responsible for many wells producing at 10-85% of full potential; for multiple squeeze attempts so often necessary to successfully seal cement channels; and for sticking pipe during concentric tubing operations.

It is a widely held myth among industry operations personnel that plugging material is easily removed with reactive materials such as HF acid in the case of clay solids or HCl acid in the case of carbonate solids.

Tests and field experience indicate that significant increases in flow conductivity are obtained not only with clean fluids instead of muds and dirty fluids, but also when larger pressure differentials into the wellbore exist while perforating.
Improved Coarse Grid Generation Using Vorticity
Authors: Mahani H. , Muggeridge A. H.
Published: December 2007

This paper describes the use of vorticity to optimize the generation of coarse simulation grids from finely gridded geological models, thereby reducing (or removing) the need for two phase upscaling. Vorticity has been used in the simulation of flow in porous media since de Josselin de Jong1 first discussed it in 1960. However this is the first time, to our knowledge, that it has been used in the area of upscaling.

Vorticity maps are generated from simulations of single-phase flow in the finely gridded geological model of interest. A coarse simulation grid is then derived which is more refined in areas of high vorticity and coarser in areas of low vorticity. The method is demonstrated for simple, layered and lens heterogeneities as well as Model 1 from the SPE Comparative Study in Upscaling2. Good matches between fine and coarse grid simulations of waterflooding are obtained, compared with using a conventionally generated coarse grid model.
Significant Production Enhancement in Uzen Field, Kazakhstan through Surface and Subsurface Optimization
Authors: Sparke S. J. , Kislyakov P. Y. , Amirtayev M. A.
Published: December 2007

This paper describes the optimisation through production engineering of the rehabilitation of Block 3A in the Uzen Field, Kazakhstan.

The Uzen field is located onshore adjacent to the Caspian Sea and was discovered in 1961 with initially estimated oil in place of 8,400 million barrels (MMBBLS). By the 1970s, the Uzen Field was contributing 320,000 barrels oil per day (bopd) to the Soviet system and was considered to be one of the largest producing assets in the USSR. However, due to both political and economic instability and underinvestment in the 1990s, production levels declined to 52,000 bopd. To restore the oilfield to its former levels of production would require an intensive field wide work programme costing a significant amount of money.

In 1995, the Kazakhstan Government applied for a World Bank loan to fund a pilot rehabilitation project on one area of the field, a premier production unit. This loan utilised a multidisciplinary service team that was equivalent to a small oil company. The programme of work, initiated during the second quarter of 2000, was focused on workovers and surface facilities, production optimisation procedures, the application of new technologies and targeting engineering solutions.

At the conclusion of the consulting contract after 3.5 years of work in November 2003, production from Block 3A had been increased from 8,000 bopd to 16,000 bopd. In conjunction with the rehabilitation project, an extensive training programme was undertaken for all staff in the host field management and field organisation, the knowledge base of which was successfully transferred to the rest of the field.

It has also been demonstrated that these achievements reconciled logistical, cultural and management-style differences through the use of fit for purpose technology and the introduction of effective decision making procedures in conjunction with change management and intensive on-the-job training.
Practical Approach to Volume Requirements for Air and Gas Drilling
Authors: Ikoku Chi U. , Azar J. J. , Williams C. Ray
Published: December 2007

Air, mist, foam, and other variations of aerated fluid drilling are utilized in various areas because of the improved penetration rate when compared to conventional mud drilling. Other proven advantages include immediate and continuous evaluation of cuttings for hydrocarbon shows, low cost, longer bit life, better control in cavernous and lost circulation areas, and minimum damage to liquid sensitive pay zones. The high compressibility of aerated drilling fluids and multiphase flow phenomena encountered when using these fluids have given rise to sophisticated engineering approach to achieve proper downhole cleaning and material transport.

There have been several attempts to calculate the minimum volumetric requirements for air and gas drilling. The results of these studies are valid over limited ranges of drilling rates at best. The reason is that there are so many variables involved in an air or mist drilling situation that one general correlation has not been developed to explain what is happening downhole and predict appropriate air or gas injection rates in the field. The method described in this paper will permit the driller and drilling engineer to determine optimum fluid injection rates in the field. It eliminates the need for complicated flow calculations used to predict volumetric air requirements.
Integrated Workflow for Quantitative Use of Time-Lapse Seismic Data in History Matching: A North Sea Field Case
Authors: Haverl M. C. , Aga M. , Reiso E.
Published: December 2007

This paper shows the implementation of a workflow for quantitative use of time-lapse seismic data in computer-ssisted history matching of simulation models.

The use of time-lapse seismic data alone or combined with production data gives additional valuable information about the reservoir and its behaviour. Several field examples of successful qualitative use of time-lapse seismic data exist. However a quantitative integration in the history-matching loop, considering all different types of scale along with measurement uncertainties, still represents a challenging task.

We present the workflow applied in a real North Sea field case, where production data and inverted seismic data from two surveys are utilized. An implemented petro-elastic model converts from reservoir to seismic parameters. Commercial optimization software is used to minimize the difference between observed and simulated data and to update the reservoir model parameters.

The main focus is to identify, understand and quantify the uncertainties in the data and the model at each step of the workflow. A key to success is tight communication and teamwork between geophysicists and reservoir engineers.

Results show that including information from time-lapse seismic data in the history matching process gives us a better understanding and description of the reservoir performance and an optimized static and dynamic reservoir model.
Identifying Wellbore Damage Components through Discrete Fracture Network (DFN) Models
Authors: Araujo H. , Lacentre P. , Zapata T. , Del Monte A. , Dzelalija F. , Gilman J. , Meng H.-Z. , Kazemi H. , Ozkan E.
Published: December 2007

The wellbore damage components, in a naturally fractured reservoir, were studied by means of a combined interpretation using conventional analysis, and a dual-porosity numerical simulation of a Discrete Fracture Network (DFN) model. The common cause for this additional pressure drop in naturally fractured reservoirs is the skin damage and turbulence effect. The dynamic behavior of the discrete fractures model was first studied by simulating, with the numerical model, the pressure response of the production history measured during a multi-rate test data. Multiple simulation runs provided pressure outputs, comparing them with the observed pressures, until achieving an acceptable match. A detailed calibration of the fracture model properties were done by analyzing the pressure change and derivative of the numerical simulation pressure output results. During the calibration of the fractures properties it was found that extra pressure drop near the wellbore was required. To reproduce such extra pressure drop, the near wellbore cells of the numerical model were calibrated under several conditions. This paper shows how a fine-grid simulation, DFN based model and the conventional well test interpretation methods were combined to evaluate the damage components affecting the fractures intersecting the wellbore.
Planning EOR Projects in Offshore Oil Fields
Authors: Bondor P. L. , Hite J. R. , Avasthi S. M.
Published: December 2007

Enhanced Oil Recovery (EOR) technologies can significantly increase recovery from oil reservoirs.Some of these EOR technologies are currently producing substantial incremental oil, primarily in onshore applications; others have not yet made a commercial impact. The application of these methods is more complex in the offshore environment, as space and weight restrictions, as well as the need for high reliability and the challenging economics of such projects, impose constraints not present in onshore applications.All EOR processes are reservoir- and reservoir fluid-specific; thus it is necessary to identify the appropriate EOR technology for use in a reservoir, design the project to achieve the required economic incremental recovery within the constraints imposed by the offshore environment, and manage the project to meet or exceed expectations.

This paper will focus on the impact of the offshore environment on the planning, design and management of an EOR project.
Spectral Gamma-Ray (KUT) Borehole Logging
Authors: Young John H.
Published: December 2007

Natural gamma-ray borehole logging is a recognized technique for evaluating uranium deposits and providing lithographic data. Spectral gamma-ray (KUT) borehole logging is a refinement of the technique which categorizes gamma-rays, according to their energies, as coming from Potassium (K), uranium (U), and thorium (T). This spectral information enhances the usefulness of the natural gamma-ray log by providing additional information on the composition of the formation producing the gamma-rays.

KUT logging is particularly applicable to evaluation of low-grade uranium deposits, and to cases where thorium anomalies are suspected. The ability to identify potassium and thorium can also aid in the classification of many rock strata.

Calibration of a spectral gamma-ray probe for proper sensitivity to gamma-ray energy is of particular concern in KUT logging. A means of continuously controlling the sensitivity of a KUT probe, using a computer and a manganese-54 reference source, is described.

Evaluation of elemental concentrations of potassium, equivalent uranium, and equivalent thorium, involves applying a stripping matrix of nine factors to the raw count rate data from the probe. Both the raw count rate data and the concentration data can be plotted versus depth. This evaluation procedure and the calibration method which yields the stripping matrix are described. Accuracy of the data produced, and the effect of logging rate on accuracy, are also discussed.
Experimental and Numerical Investigation of Carbon Sequestration in Saline Aquifers
Authors: Izgec O. , Demiral B. , Bertin H. , Akin S.
Published: December 2007

Because of the global warming threat posed by greenhouse gases, mainly by CO2, some strategies were proposed. Along those, disposal and long term storage of greenhouse gases is important for reducing global warming. Aquifers represent the most widely available and the second largest, naturally occurring potential store for CO2. Although there are a number of mathematical modeling studies related to injection of CO2 in deep saline aquifers, experimental studies are limited and most studies focus to sandstone aquifers as opposed to carbonate ones.

Potential CO2 sequestration capacity of a carbonate aquifer formation located in S. East Turkey was evaluated using computerized tomography (CT) monitored experiments. Porosity changes along the core plugs, drilled from Midyat aquifer formation located in south-east Turkey, and the corresponding permeability changes are reported for differing CO2 injection rates, pressures and temperatures with differing salt concentrations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. It was observed that permeability initially increased and decreased for slow injection cases. As the salt concentration decreased the porosity and thus the permeability decrease was less pronounced. Orientation of the core plugs was observed to be influential in rock-fluid-carbon dioxide interactions. For vertically aligned cores high injection rates resulted in an increase then decrease of permeability. On the other hand horizontally aligned cores represented a decrease in permeability due to CaCO3 precipitation. It was observed that CO2 sequestration by solubility trapping is larger compared to mineral trapping. The results are discussed using a finite difference, non-isothermal compositional numerical simulator where solution and dissolution of carbonates via chemical reactions are considered. The calibrated model was then used to analyze field scale injections and to model the CO2 sequestration capacity of a potential carbonate aquifer formation located in S. East Turkey.
Corrosion in High Rate Gas Wells—A Case History
Authors: van Grinsven R. , Jackson L. , Suarez I. , Bouts M.
Published: December 2007

The Reedijk-1 gas well was completed in 1992 with 3 ½" Carbon Steel (CS) tubing and taken into production early 2003 with a capacity of 1.8 mln Nm³/d. Due to the CO2 content, continuous corrosion inhibition was required. However as a result of operational problems it took about 9 months before injection was established.

In August 2004 it was observed that the annulus injection pressure increased slowly towards the tubing head pressure and finally became equal. By closing the flapper valve and releasing some pressure of the tubing, it was assessed that the communication should take place above the subsurface safety valve. A downhole video camera run was carried out and identified the leak 1.8 m below the top of the tubing hanger. The camera also revealed that pipe bodies were still in good shape but the couplings showed severe pitting. Subsequently, straddling off the leaking coupling minimized gas production deferment. The well could normally be produced until it was worked over to 5" Chromium 13 (Cr13) tubing.

From this case history it can be learned that: In high rate gas wells understanding the film persistency of the chemical corrosion inhibitor is important as removal of inhibitor films is a possibility due to the high velocities thereby leaving this part of the tubing unprotected. This is especially the case at subsurface safety valve (SSSV) depth as a result of the restricted diameter.The application of chemical corrosion inhibition in downhole situations may not manage corrosion when pitting corrosion has been initiated.Alternative solutions to corrosion management need to be sought. Improved technologies that enable increased inhibitor availability, improved inhibitor chemistry's demonstrating high persistency at high gas velocities. Application techniques such a batch dumping of corrosion inhibitor into the well with high persistency chemicals are being tried as alternatives.
Experimental and Theoretical Study of Uranium in Situ Solution Mining With H2SO4
Authors: Harloff Gary J. , Riese A. C.
Published: December 2007

Experimental and theoretical studies of solution mining indicate that the macro chemical composition of the produced fluids are governed by solution mineral equilibria. The aqueous composition of these solutions and the mineral mass distruction and creation in the host rock are calculated as a function of pH. The site specific geologic and hydrologie characteristics are accounted for as boundary conditions, thus this technical capability is not site specific. The bulk solution chemistry and the uranium extraction curve for a field site are successfully modeled.

Scaling criteria are developed and a scaled two dimensional field simulator was built and tested to demonstrate a hydrological barrier concept which is applicable to leach and restoration field tests. Tests with Hele-Shaw flow in a transparent porous media were conducted to obtain flow visualization and tracer data. A uranium extraction test was conducted in the field simulator to illustrate and verify new well concepts and to provide data for the computer models of the process.
The Advantages of Conditioning an Orebody With A Chloride Solution Before in Situ Uranium Leaching with A Carbonate Solution
Authors: Tweeton Daryl R. , Guilinger Terry R. , Breland W. Michael , Schechter Robert
Published: December 2007

Laboratory experiments conducted by the University of Texas at Austin as part of a research contract funded by the U.S. Bureau of Mines indicate that conditioning an orebody with a chloride solution prior to carbonate leaching offers two advantages. First, the permeability loss occurring upon the injection of the carbonate solution is reduced. This effect is tentatively attributed to a reduction in precipitation of calcium carbonate. Calcium chloride is soluble, so calcium can be flushed out of the orebody. Second, the great difficulty of complying with current regulations concerning restoration of groundwater quality after leaching with ammonium carbonate may be avoided because the substitution of potassium carbonate for ammonium carbonate may be made economically feasible. Flushing the orebody with potassium chloride before leaching satisfies cation exchange sites with potassium from relatively cheap potassium chloride, thereby reducing the consumption of the more expensive potassium carbonate. Field tests are planned.
Biotechnology Applications to EOR in Talara Off-shore Oil Fields, Northwest Peru
Authors: Maure A. , Saldaña A. A. , Juarez A. R.
Published: December 2007

Seven producer wells (oils between 32-36 °API) from Basal Salina fm. in Providencia and Lobitos areas of Z-2B Block (Talara basin, Northwest Peru) were selected to evaluate a biotechnology approach for Enhanced Oil Recovery.

The MEOR candidates are vertical and high-angle slanted wells. They produce from faulted reservoirs through intermittent gas lift methods under an off-shore operative environment. The oils are paraffinic and hence with positive bio-treatability.

The treated wells exhibited a typical MEOR response in two consecutive stages: 1) Clean-up effects by the removal of organic damage occurring in the near wellbore of the perforated interval, opening non-productive zones bearing oils with a more segregated, pseudoplastic behavior. The typical signature is a high pulse in oil rate but only lasting a short time. 2) Radial-Colonizing response, by generation of light-end solvents (biocracking on N-alkanes present in the oil) which cause a permanent rheological effects by the compositional alteration that occurat deeper colonization radius, in drainage zones with extremely low shear rate values (low fluid velocity).

The MEOR pilot stage in PG-U9 and PG-9 of Providencia and LO16-14 and LO16-24 of Lobitos fields resulted in 3,086 M[3] (19,410 bbls.) and 2,211 M[3] (13,907bbls.) of Incremental Oil respectively. MEOR Increments of36.5% in Providencia and 46.5% in Lobitos were assumed as conservative (non optimized) MEOR performance indexes. Note: Due to operative reasons not directly related to MEOR, the complete inoculation program was concluded in only four of the original seven candidate wells.

The pilot project was considered profitable and economically feasible of further expansion.

Z-2B block possess 430 producers as excellent MEOR prospect and waterflooding schemes as potential targets for biotechnology (MEOR[2]). [Ref. 7 to 14].
New Hydrocarbon Traps in the Acema Area, Eastern Venezuela: An Alternative for a Mature Oil Field
Authors: Azalgara C. , Boada E. , Diaz M. , Bonfanti B. , Blanco R.
Published: December 2007

Proposal

In 1997, during the third Round of Mature Oil Fields bid, PDVSA awarded the Consortium COROIL-Petrobras Energia Venezuela (then Perez Companc de Venezuela) the Acema Block operation. This block, which extends through 300 km2, includes several oil-fields that have produced hydrocarbons from the Oficina Formation (Fm.) for more than fifty years. Currently, most of these reservoirs are depleted.

This work aims to characterize the Oficina Fm. reservoirs under exploitation, and to identify upsides in the Acema Block in order to reverse the declining production tendency. The available data to perform the study comprised: old wire-line logs set from 82 wells and modern wire-line logs set from 9 wells, a standard seismic volume covering 420 km[2], modern VSP's and check-shots surveys, and reservoir production and pressure data.

The methodology included: Creating a petrophysical model. Validating / creating synthetic seismograms. Characterizing the original seismic data. Performing rock-physics analysis. Applying the High-Frequency Imaging reprocessing technique to enhance the original frequency content. Creating the structural and the stratigraphic models. Creating geocelular models of the two most important fields (A and B fields). Assessing the OOIP and the remaining reserves (volumetric and material balance methods) of those fields. Performing economic analysis under different development scenarios.

We have recognized two types of hydrocarbon traps:

Structural-Traps, which consist of extensional anticlines adjacent to normal faults.

Combined Stratigraphic-structural Traps, which comprises the following elements: (a) The strata dip, 4° north. (b) Elongated sandstone bodies whose predominant characteristics are: northwest-southeast trend, net thickness 10-35 feet, effective porosity 12-17 %, width 0.7-2.3 km and length in the order of tens of kilometers. (c) Shale beds that seal those sandstone bodies. (d) A main permeability barrier, which is defined by the southwest border (up-dip direction) of the elongated sand body. (e) Sealing normal fault that serves as lateral permeability barrier that shows the following characteristics: trend approximately orthogonal to the sandstone body elongation and length larger than the width of the sandstone body at their intersection zone.

Both kinds of traps include stacked, relatively small, mostly solution gas-drive reservoirs. Production history indicates that the reservoirs associated to the Combined-Traps are more prolific than those related to the Structural-Traps.

We have defined a highly Prospective Area of 2630 acres located at the south-central part of the Acema Block that shows a Combined-Trap cluster. The estimated reserves of this Prospective Area at least represent 15% of the total reserves for the Acema Block.
Recent In-Situ Oil Recovery-Technologies for Heavy- and Extraheavy-Oil Reserves
Authors: Cunha L. B.
Published: December 2007

The heavy and extra heavy oils in Canada represent an amount of recovery oil resources of about 300 billion barrels. These vast quantities of heavy and extra heavy oil are trapped in shallow, accessible reservoirs, but are difficult to extract. Producers involved in heavy oil recovery face special challenges in producing these high-viscosity crudes.

Conventional heavy oil recovery methods have showed to provide limited oil displacement efficiencies in Canada's heavy and extra heavy oil deposits. To overcome their inherent difficulties several variations of steam, air and solvent injection methods have been proposed. The most interesting ones appeared along with developments in horizontal well technology. These methods combine the concept of oil gravity drainage with the conventional air-steam and solvent-based heavy oil recovery processes and the horizontal well technology. Methods known as cyclic steam stimulation – CSS, steam-assisted gravity drainage – SAGD, solvent vapor extraction – VAPEX, and top-dow combustion, are examples of this class of methods.

This article presents an overview of the recent production technologies for extra heavy oil reserves. Some of the properties of heavy oil are summarized and a review of the drilling/completion and production techniques that help to make heavy-oil reservoirs profitable assets is presented. Both, limitations and potential benefits of these techniques are described.
Detection of Hydrothermal Alteration in A Sedimentary Type Geothermal System Using Well Logs
Authors: Ershaghi Iraj , Ghaemian Shahed , Mathews Mark
Published: December 2007

A study was conducted to examine well log responses in the hydrothermally altered zones of a sedimentary type geothermal reservoir. The logs were run under precooled borehole conditions. In spite of uncertainties about the borehole temperature at the time of logging and lack of calibration data for quantitative estimation, qualitative interpretation of the logs indicate that the zones with extensive hydro-thermal alteration are detectable on conventional logs such as conductivity surveys, S.P., compensated density and neutron logs. These observations confirm the worthiness of wireline logs in geothermal exploration.
How And Why Does Scale Stick—Can the Surface Be Engineered To Decrease Scale Formation and Adhesion?
Authors: Wang Z. , Neville A. , Meredith A. W.
Published: December 2007

In many production fluids encountered in the oil and gas industry, the formation of mineral scales such as BaSO4 and CaCO3 causes major problems with respect to flow assurance. It has recently become apparent that in order to fully understand a scaling system both an appreciation of the bulk precipitation and surface deposition characteristics must be obtained [1]. In surface deposition the important steps are (i). nucleation of crystals, (ii) the growth of these crystals at the surface site and (iii) finally the adhesion of crystals to create a scale layer. In some instances where scaling causes operational problems (e.g in heat exchangers in desalination units) application of ‘non-stick’ materials are considered as a promising method to alleviate scale deposition. To date, there have been few instances where surface modification or surface coatings have been considered seriously for scale control in the oil and gas industry.

In this paper results are reported from experiments to investigate calcium carbonate scale formation and adhesion at solid surfaces. Two aspects relevant to adhesion are considered: 1. the influence of the substrate on the extent of surface scale formation; 2. the critical shear stress required for removal of scale. Four substrates were investigated in the study, UNS S31603 (stainless steel), electrochemically pretreated UNS S31603 and two coatings: DLC (diamond like carbon) and PTFE (polytetrafluoroethylene). Deposition experiments were conducted from supersaturated solutions of calcium carbonate at 50°C. In order to investigate the critical shear stress for removing scale on different substrates, a submerged impinging jet (SIJ). It has been shown that the amount of scale formed at the surface is dependent on surface energy and on physical surface roughness. The surface energy, and in particular the polar component, is an important factor in adhesion – as are the morphology and crystal arrangement in the surface scale deposit.