bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Study: Using CT-Deployed Scale Removal to Enhance Production in Duri Steam Flood, Indonesia
Authors: Ali Syed A. , Irfan Muhamad , Rinaldi Dedi , Malik Badar Zia , Tong Ku Ka , Ferdiansyah Eric
Published: December 2007

Wells in the Duri field often have a heavy scale buildup across the gravel-pack screens and the surface production equipment. This scale, which builds from calcium carbonate (CaCO3) and organic deposits in the wellbore, causes significant production decline and premature screen failures. After conventional attempts to place acid and remove scale were unsuccessful, PT Caltex Pacific Indonesia, the Company, and Schlumberger collaborated to develop a coiled tubing conveyed scale removal and fluids placement technique for gravel-pack screen completions. This paper highlights the scaling history and causes, and the yard testing, candidate recognition process, and field execution of the new technique. Post-treatment results are presented from 39 wells, showing a field production increase of more than 90 percent. The development process included scale-removal tests using numerous CT-conveyed tools. A rotating jetting tool that is optimized by software-aided hydraulics provided the maximum cleaning efficiency. Because the jetting action cleaned the screens physically, the new tool required smaller amounts of reactive fluids (xylene and acid). Safety features included a closed-loop design of the entire test circuit to avoid fluid spillage and enable safer handling and disposal of corrosive fluids.

The scale removal service, which cleans using a combination of chemical and mechanical energy, has been used in 111 wells in the Duri Steam Flood (DSF). Treatment costs are lower because less reactive fluid is needed. The inert 2% potassium chloride (KCl) brine achieves most of the cleaning action, which also optimizes the spent fluid disposal. The design of the treatment fluid also reduces the downtime required for wells to return flow to normal production. The bottom line is production gain in less time.
SWAG Injectivity Behavior Based on Siri Field Data
Authors: Berge Lars Inge , Stensen Jan Åge , Crapez Bénédicte , Quale Eileen A.
Published: December 2007

Injection of water and gas in combination, in most cases injected in an alternating scheme (WAG), is one of the most successful IOR methods applied in the North Sea. Simultaneous water and gas injection (SWAG) has so far gained less experience. Simulations show in general an IOR potential of the same magnitude as WAG. Field limitations may in some cases be in favor of SWAG injection. The main contributions to increased recovery come from improved sweep, oil swelling and reduced residual oil saturation.

SWAG has recently been implemented on the Siri Field on the Danish Continental Shelf and represents the first reported full field application of its kind in the North Sea. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The Siri Field has performed SWAG injection from the production start in 1999.

SWAG injection on Siri and experiences has previously been reported1. Reservoir studies predict field recovery improvements with combined water and gas injection. Injection of a two-phase mixture of water and gas represents some new challenges. One relates to injectivity. Combined water and gas injection may result in lower injectivity than for single-phase injection. Injectivity is therefore important in connection with practical implementation of SWAG. A discussion of injectivity behaviour and interpretation of Siri data will be presented. For the Siri Field, hydraulic fracturing of the injectors proved unavoidable due to unexpected low permeability in the injection zone. Above the fracturing pressure, the injectivity can be strongly dependent on the gas fraction of the injection mixture.
Producer/Injector Ratio: The Key to Understanding Pattern Flow Performance and Optimizing Waterflood Design
Authors: Hansen C. E. , Fanchi J. R.
Published: December 2007

This paper presents new analytical relationships describing pattern waterflooding that have not been reported previously. The relationships fill a significant gap in the existing steady-state flow theory for two-phase, isotropic reservoir systems. The new equations, which include modifications for reservoir heterogeneity and skin effect, represent a general, comprehensive pattern flow theory that unifies previous works while greatly extending the range of applicability to all patterns and mobility ratios. These relationships facilitate understanding that is not provided by existing waterflooding theory of the absolute and relative flow performance of the various patterns in all mobility systems. A rational, analytical approach to waterflood optimization is presented here.
Disproportional Permeability Modification by Alcohol-Containing Polymer Solutions: Laboratory Studies and Field Experiences
Authors: Lakatos I. , Lakatos-Szabó J. , Kosztin B. , Palásthy Gy.
Published: December 2007

Gas production from gas fields and underground gas storage is usually accompanied by substantial water production. The high water production and necessity of on-site water liquidation often deteriorate the recovery efficiency and hamper maintaining an environmentally friendly production. During the past decades intensive R&D activity has been made to develop a viable well treatment method, however on account of the inverse mobility ratio in gas/water system, the conventional water shut-off or profile correction methods could not be used successfully under field conditions. According to some proposals the most promising procedure might be the injection of a high salt-containing polymer solution into the wells utilizing the reversible swelling/shrinking properties of the adsorbed polymer layer. If this mechanism works properly, a disproportional permeability modification is resulted and hence, the water productions is significantly decreased.

In contrast to mentioned technical solution the new idea is to use a "poor" solvent for preparation of the treating solution. The concept is based on the fact that the "solvent power" worsens as the alcohol content in the aqueous phase is increasing. A detailed laboratory study has been made in order to optimize the alcohol type and concentration, and different polymers were used as model to demonstrate the feasibility of the theoretical considerations. Complex rheological measurements served to study the flow properties of treating solutions and to determine the molecular conformation in bulk and adsorbed states. Sophisticated hydrodynamic measurements were carried out to demonstrate the disproportional permeability modification in gas/water systems and in different porous media. Finally, the general procedure was up-scaled to field conditions and the technology was tailored to individual well conditions. In the frame of the pilot test four gas wells operating at the largest Hungarian gas field were treated with alcohol-containing polymer solutions. The pilot tests were supported with sophisticated reservoir engineering supervision and the results were evaluated meticulously by academic and practical experts. According to the available data two treatments proved already positive, one of them showed outstanding performance. At the present time the observations are continued and new treatment project is planned by the operator. The paper outlines the whole innovation process and gives a concise summary of the lessons to learn.
Effect of Capillary Pressure, Salinity, and Aging on Wettability Alteration in Sandstones and Limestones
Authors: Chattopadhyay Sruti , Jain Vivek , Sharma M. M.
Published: December 2007

Oil recovery in petroleum reservoirs is greatly affected by fluid -rock and fluid-fluid interactions. These surface chemical interactions directly control rock wettability, capillary pressure curves and relative permeabilities. Centrifuge coreflow tests (Berea sandstone and Texas Cream limestone) were performed with a range of fluids under different conditions to identify the factors influencing the residual wetting and non-wetting phase saturations and oil recovery. Results of the tests conducted with Prudhoe Bay and Moutray crude oil show that remaining water (Swr) and residual oil saturation vary systematically with Bond number for both sandstone and limestone samples. Differences in the shape of the wetting phase capillary desaturation curves are observed during primary and secondary drainage. This suggests that the distribution of fluids in the rock during secondary drainage is different from primary drainage due to a change in wettability of the core from a water-wet state to mixed-wet state. These trends were not observed with decane. Both limestone and sandstone cores become more susceptible to wettability alteration as the salinity is increased. The wettability index(Aw-Ao, water Amott-oil Amott) decreases from 0.56 (0.3% brine) to 0.2 (20%brine) in a limestone core with Prudhoe Bay crude oil. Aging the samples for 20-30 days with Moutray crude oil shows results in a change in the wettability of the cores. The oil recovery increases by 10-15% to more than 95% in both Berea and limestone cores. These results show that with time the crude oil changes the wettability of the core from strongly water wet to mixed wet, which leads to a higher oil recovery. Experiments with samples of sandstone and limestone aged with Prudhoe Bay crude oil and brine of different salinities also show similar trends.
A New Approach to the Determination of Polymer Concentration in Reservoir Rock Adsorption Tests
Authors: Mezzomo R. F. , Moczydlower P. , Sanmartin A. N. , Araujo C. H. V.
Published: December 2007

An alternative method for measuring polymer concentration in core effluents during dynamic polymer adsorption determination tests in laboratory scale was developed. Laboratory tests were made by injecting polyacrylamide solutions at different concentrations in a water saturated sandstone core. Core effluent was measured for the shear rate necessary to cause a constant and high (70% of full scale) torque on a rotational rheometer. The measured shear rate was converted to concentration values by using a calibration curve. Polymer concentration was also determined by spectrophotometry for comparison.

The curve obtained by the proposed isotorque method showed greater reliability and lower variations than the spectrophotometric method. The isotorque method, besides being simple in terms of laboratory work, is able to give better adsorption values as input for polymer flooding simulations.
Sorbed Polyacrylamides: Selective Permeability Parameters Using Surface Techniques
Authors: Córdova M. , Mogollón J. L. , Molero H. , Navas M.
Published: December 2007

The adsorption of polyacrylamides on siliceous surfaces was studied by X-ray Photoelectron Spectroscopy (XPS), Scanning Electron Microscopy (SEM), Atomic Force Microscopy (AFM) and contact angle.

XPS allows to determine the amount of homopolyacrylamide (PAM) adsorbed directly on mineral surface. The XPS results showed a correlation factor of 0.99 when they were compared to those obtained using the conventional technique of N-Bromination of amides. The experimental work involved in XPS determinations was found to be simple, rapid and suitable for mechanistic studies on non-consolidated rocks and sandstone cores. PAM and hydrophobic modified polyacrylamide (PAMHM) layers adsorbed on Berea discs were compared using SEM. The PAMHM polymer showed higher affinity for clay minerals and it covers the mineral surfaces with a film, largely reducing the surface roughness compared to PAM. AFM studies conducted on muscovite mica showed how the surface coverage increases with concentration of polymer. The AFM results demonstrated that hydrophobic modification of PAM increases significantly mineral coverage and attenuate surface roughness.

The roughness reduction and total Berea surface coverage by PAMHM suggests an enhanced lubrication effect that could make the flow of a nonwetting fluid (oil) easier. PAMHM slighty increases surface water-wet condition as supported by additional contact angle measurements. This behavior could enhance oil recovery by improving oil mobility and reducing water mobility. The combination of these two effects, demonstrated in static adsorption tests, supports the PAMHM potential for selective permeability reduction in siliceous formations.
Petrophysical Characterization of Permian Shallow-Water Dolostone
Authors: Holtz M. H. , Jackson John A. , Jackson Katherine G. , Major R. P.
Published: December 2007

The complex interplay between depositional facies and diagenesis in dolostones presents numerous challenges for calculating petrophysical properties from wireline logs. Complex pore geometries and mineralogies control rock petrophysical properties, and equations for calculating porosities and saturations must therefore be tailored to specific pore geometry-mineralogy combinations. The complex mineralogy of some dolostone reservoirs, moreover, has profound effects on wireline log measurements. If dolostone reservoirs are divided into petrophysical-mineralogical facies of similar depositional and diagenetic textures and, thus, similar pore geometries and mineralogy, empirical equations that apply specifically to that geologically identified petrophysical-mineralogical facies can be developed so that porosity and water saturation can be calculated accurately.

We present some examples from Permian shallow-water dolostone reservoirs of the Permian Basin, southwestern United States, that demonstrate analytical approaches for calculating petrophysical properties in these complex rock types. The four general petrophysical-mineralogical facies that characterize Permian shallow-water dolostone reservoirs are (1) subtidal, muddominated dolostone; (2) subtidal, grain-dominated dolostone; (3) dolomitic and siliciclastic peritidal rocks; and (4) diagenetically altered, subtidal dolostone.
Microbial and Waterflooding of Fractured Carbonate Rocks: An Experimental Approach
Authors: Zekri Abdulrazag Y. , El-Mehaideb Reyadh A.
Published: December 2007

Fractures and fractured zones require special reservoir development plan. They may improve or hider the oil production. Conductive fracture rocks may provide the required permeability to drain an oil saturated low permeability rock matrix. Low sweep efficiency of many oil reservoirs may be the result of channeling of injected water through high permeability zones that normally associated with fracture system in heterogeneous reservoirs. In this case substantial amount of work focused on improving the distribution of injected water in the wellbore through different treatments: using gelling agents, cements, cross-linked polymer and emulsions. Other alternatives such as microbial and surfactant based methods have been proposed. This paper presents the results of research conducted on thermophilic bacteria that were obtained from UAE local environment. Coreflooding experiments were conducted on single fractured cores to show the effectiveness of microbial treatment. Different fracture angel orientations 45°, 90°, and 180° of the axis of the flow were investigated. The effect of matrix permeability on the treatment was also studied. A comparison between water flooding and microbial flooding of fractured systems were investigated. Non-invasive imaging technique such as Scanning Electron Microscopy (SEM) was employed to visualize changes on the surface of the fracture as a result of bacteria flow through the system.
Seismic-Based Gas-Water-Contact, Porosity, and Permeabilities for Condensate Reservoirs: Tested and Corrected by History Matching
Authors: Kasap Ekrem , Lumay Viloria , Xue Fangian J. , Corbett Chip , Nishikiori Nobuo , Tomonori Shibata
Published: December 2007

Seismic attributes are an essential source of information on lateral variation in rock properties. Quantitative use of seismic attributes in predictive models is challenging, because the seismic data are of limited resolution and influenced by rock mechanical properties, porosity, pore fluid type, bed thickness, and dip angle.

An integrated study was conducted to optimize the coupled gas production from Fields A and B, offshore Gulf of Mexico. Field B formation characterization results are discussed here. Structural static models were constructed from depth-converted seismic horizon interpretations. The models were porosity populated by integrating seismic amplitude-based areal porosity heterogeneity with well log and core data using geostatistical techniques. All other necessary petrophysical parameters were correlated to porosity. Static models were then converted to numerical models, which were used to predict historical data.

Field B has Upper, Middle, and Lower sands, which were produced from dual completions. The Upper sand is thick enough to be resolved on the seismic data. The gas-water contact (GWC) was reliably determined and verified by history matching. The matching production data, tubing head pressure (THP), and static reservoir pressure revealed, however, that seismic amplitude overestimates porosity above the GWC, and underestimates it in no-gas aquifer zones. This effect is amplified in permeability because of its exponential relationship to porosity. THPs and well tests were used to correct for permeability.

The Lower sand reservoir quality deteriorates quickly in most parts of the reservoir, and the seismic resolution was less than desired. Here, in addition to pore volume and permeability, the GWC needed corrections to match historical data. From these findings, we concluded that seismic-based areal heterogeneity is a valuable source of data for predictive reservoir models when supported by the dynamic production and well test data.
Inferring Interwell Connectivity From Well-Rate Fluctuations in Waterfloods
Authors: Alejandro Albertoni , Lake Larry W.
Published: December 2007

This paper presents a practical technique to quantify communication between wells in a reservoir using only production and injection rate data. The technique combines a constrained multivariate linear regression analysis with diffusivity filters to provide information about permeability trends and the presence of transmissibility barriers. The method was developed and tested using a numerical simulator and then applied to a waterflooded field in Argentina. The simulation results indicate that the connectivity between wells is described by coefficients that only depend on geology and relative position between wells; they are independent of injection/production rates. The results of this work can be used to improve the performance of an existing waterflood by suggesting how well patterns might be changed or managed. They could also be used to model flow in the reservoir.
Characterization Of Estuary-Shoreface Type Reservoir Using Outcrop Analogue And Modeling Of Flow Using A Nonuniform Coarsened Grid
Authors: Merchan Sergio A. , Srinivasan Sanjay , Meyer Rudi
Published: December 2007

A methodology for constructing an analogue 3D model for clastic reservoirs in an estuary-shoreface depositional environment using outcrop information is discussed. Such analogue models provide valuable information related to reservoir architecture and rock properties that can be used to model sedimentary structures in the subsurface. A new approach for upscaling high-resolution models using nonuniform coarsened grid is introduced. Simulation results for a viscous dominated flow process show that nonuniform grids yield better results compared to uniform grids.
Sensitivity of Reservoir Simulations to Uncertainties in Viscosity
Authors: Hernández J. C. , Vesovic V. , Carter J. N. , Lopez E.
Published: December 2007

The paper examines the sensitivity of reservoir simulations to uncertainties in viscosity. The simulations are performed for three different oils, ranging from light to viscous, for three different geological terrains. In each case, the viscosity has been estimated by a number of currently recommended prediction methods and by recourse to the measured values. The preliminary results indicate that the results of reservoir simulations are sensitive to the fluid viscosity. The sensitivity increases with increase in the absolute viscosity of the oil, increase in heterogeneity of the reservoir and increase in uncertainty in viscosity. The results show, that in the worst case scenario examined (e.g. heavy, viscous oils, η > 6 cp) a ±1% error in viscosity will produce a 1% error in the cumulative production. Overall, the preliminary results indicate that the common assumption in reservoir simulations, that the accuracy of fluid properties has a marginal influence on the reservoir performance, is false. Uncertainties in viscosity can lead to large errors in predicted production rates, thus unduly influencing the economics of reservoir exploitation.
Integrated Production Operation Models With Reservoir Simulation for Optimum Reservoir Management
Authors: Yang Daoyong , Zhang Qi , Gu Yongan
Published: December 2007

There has been an increasing interest in optimum reservoir management to maximize oil production from a reservoir given the present economic and technical limits. However, many reservoir management programs have failed because they do not consider wells, surface facilities and the reservoir as an integrated system. In fact, determination of optimum operation parameters for both producers and injectors is critical to the ultimate oil recovery under the existing reservoir and infrastructure conditions. On the other hand, production operation methods are usually not taken into account in reservoir simulation, which is traditionally used for reservoir management purpose. Also due to practical constraints, test runs are often limited to a few most plausible sets of model parameters, though the global optimum set should be used instead.

This paper presents a systems engineering approach, which integrates production operation models with reservoir simulation to achieve the global optimum parameters for both producers and injectors. More specifically, a reservoir simulator starts with a basic run, which provides a reference case. Then the simulated annealing algorithm is employed to solve multi-dimensional nonlinear global optimization problems. Finally, the optimum reservoir performance is obtained by executing the reservoir simulator with the global optimum parameters. Such integrated approach ensures that the displacement front can advance slowly and steadily at various stages of the field development such that the maximum oil production can be achieved. It is also found that the simulated annealing algorithm is efficient and stable in achieving the global optimum. Furthermore, this systems method is applied fieldwide to a water-alternating-gas (WAG) miscible flooding reservoir. The reservoir performance has been adjusted and controlled in an optimum range over five years. The reservoir pressure remains higher than the minimum miscible pressure (MMP) and distributes uniformly in the whole reservoir, in which appropriate production operation methods are implemented. The bottom-hole flowing pressure, injection pressure, oil rate, injection volume of water and gas, water-cut and gas-oil-ratio (GOR) are kept in a proper range. All these fieldwide data show that the integrated approach to optimum reservoir management presented in this paper can greatly improve the oil production.
Estimation of True Dispersivity in Field Scale Permeable Media
Authors: Mahadevan Jagannathan , Lake Larry W. , Johns Russell T.
Published: December 2007

Simulation studies (Solano et al.1; Stalkup2) show that oil recovery for enriched gas drives depends on the amount of dispersion in reservoir media. But the true value of dispersion, expressed as dispersivity, at the field scale, is unknown. This work investigates three types of dispersion in permeable media to obtain realistic estimates of dispersive mixing at the field scale.

The dispersivity from single-well tracer tests (SWTT), also known as echo dispersivity, is the dispersivity that is unaffected by fluid flow direction. Layering in permeable media tends to increase the observed dispersivity in well-to-well tracer tests, also known as transmission dispersivity, but leaves the echo dispersivity unaffected. A collection of SWTT data is analyzed to estimate echo dispersivity at the SWTT scale. The estimated echo dispersivities closely match a published trend with length scale in dispersivities obtained from groundwater tracer tests. This unexpected result—it was thought that transmission dispersivity should be greater than echo dispersivity—is analyzed with numerical simulation.

A third type of dispersive mixing is local dispersivity, or the mixing observed at a point as tracer flows past it. Numerical simulation results show that the local dispersivity is always less than the transmission dispersivity and greater than the echo dispersivity limits. It is closer to one limit or the other depending on the amount and type of heterogeneity, the autocorrelation structure of the medium's permeability, and the lateral (vertical) permeability. The agreement between the SWTT echo dispersivities and the field trend suggests that the field data are measuring local dispersivities. All dispersivities appear to grow with length.
Recovery of Coalbed Methane by Gas Injection
Authors: Zhu Jichun , Jessen Kristian , Kovscek Anthony R. , Orr Franklin M.
Published: December 2007

Injection of either carbon dioxide (CO2) or nitrogen (N2) can serve as an effective method for enhanced recovery of coalbed methane. In this paper, we provide new analytical solutions for flow of ternary gas mixtures. The adsorption/desorption of the components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas phase behavior is predicted by the Peng-Robinson EOS. Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan Basin of Colorado. In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution that consists of continuous waves and shocks is found. Mixtures of CH4, CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems in which the initial gas has a high CH4 content, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time CBM is recovered.
Cavitation for Effective Well Cleaning
Authors: Bakker Tom W. , Ivannikov Vladimir I.
Published: December 2007

Active cavitation is novel, powerful, coiled tubing or workstring conveyed technology. Cavitation is the process of creating transient vapor filled cavities in a fluid at ambient fluid pressures exceeding the vapour pressure in the cavities. Implosions of such cavities are known to cause damage to ships propellers and pump impellors, however the effects can also be usefully applied for many purposes, including applications in the well construction and well servicing disciplines.

Commonly known cavitation occurs in low-pressure areas when a fluid flows around an obstruction or past the surface of an oscillating body; this type of cavitation is referred to as passive cavitation.

The particular technology described in this paper is referred to as ‘active’ cavitation. This is a method using liquid hammer enhancement to create vapor bubbles at much higher ambient pressures than previously possible. The vapor cavities at low pressure points created at high ambient pressure implode violently and decay into smaller bubbles thus significantly extending the life and extent of the low-pressure zone or ‘cavitation flare’ and enhancing the action of the jetstream flowing from the cavitator. A particular value of cavitation is that it produces a twofold effect, i.e. a combination of suction effects in the decaying cavitation flare and shock wave effects that reach much further away from the cavitation generating tool.

Active cavitation can for instance be employed to improve the hole making process, clean reservoir rock or remove scale and deposits from well completion equipment. Thus, use of cavitators allows intensifying rock fragmentation and bit cleaning. During field trials in Russia it was demonstrated that drill rates can be increased by up to 40% and bit life can be extended by up to 25% compared to the performance of previously applied bits. When using cavitators for fraccing and decolmatation (removal of fine plugging material) production or injection improvement of 1.5 – 3 times are commonly being observed. Cavitation is also very effective in cleaning tubes or plugged screens in water, oil or gas wells because it effects most commonly occurring deposits, including deposits that are insoluble in acid.
Establishing Inflow Performance Relationship (IPR) for Gas Condensate Wells
Authors: Jokhio Sarfraz A. , Tiab Djebbar
Published: December 2007

A new simple method of establishing Inflow Performance Relationship for gas condensate wells is proposed. The proposed method uses transient pressure test data to estimate effective permeability as function of pressure and then uses it to convert production BHFP data into pseudopressure to establish well performance. Requirement of relative permeability as function of saturation thus has been completely eliminated. Effective permeability of either phase can be used to predict the production of second phase. A scheme has also been devised to estimate the effective permeability using well testing mathematical models available in literature.

Also mathematical models of well deliverability loss due to condensate deposition when dew point pressure is reached, and deliverability gain due to condensate mobility when P* is reached have been developed. Pseudopressure curves for both oil and gas phase have been developed for quick conversion of pressure data into pseudopressure. Relative permeability curves if available can also be used, however, the knowledge of saturation has to be known at all the stages of the depletion to be able to use them.

Gas condensate reservoirs are primarily gas reservoirs. As the pressure declines with depletion, reservoir conditions of pressure may go below dew point and liquid begins to buildup. Such reservoirs may go under liquid buildup without showing any trace of liquid production. Sudden well deliverability loss and very high skin factor estimates from pressure tests are strong indicators of liquid buildup. PVT characteristics like phase diagram help identify the problem too. As the critical conditions are reached such reservoirs become two phase in nature.

Finally, a field example is analyzed to show the use of new method developed and a step-by-step procedure is used to establish the well performance. Small operators, Independents, will benefit from this method at the most, since data acquisition like relative permeability curves require the laboratory experiments on cores, an expensive procedure.
Development Modeling of the Saih Nihayda Gas-Condensate Field
Authors: Azhar Al-Kindi , Langedijk Robert
Published: December 2007

As the demand for natural Gas in the Sultanate Of Oman rises both internally through domestic and industrial growth, and externally through the LNG export, the development of more gas fields becomes a necessity. Being centrally located, close to existing central processing plant, and with considerable volume in place, the rich gas-condensate Saih Nihayda field, is seen as the next candidate for development.

A full field model was built for Saih Nihayda to study uncertainties and investigate the optimum development option for the three deep stacked reservoirs. The hydrostatically pressured Barik sandstone being the shallowest and the most complex is a gas-condensate reservoir, whereas the Miqrat and the Amin sandstone are both over-pressured dry gas reservoirs.

This paper details an integrated approach followed in assessing the impact of various uncertainties on development options. It highlights the modelling process from seismic inversion to demand driven forecasting and economic assessment. Special attention was paid to gas-condensate specific phenomena such as condensate impairment.

Beside the high technical demand associated with understanding the physical behaviours of gas-condensate reservoirs, the variability in static and dynamic characteristics of the three Saih Nihayda sandstone reservoirs offers commercially challenging development options.

Comparison studies included commingled reservoir production versus non-commingled and the impact of hydraulic fracturing versus non-fracturing on reduction in total well numbers and acceleration of early condensate. The paper touches on the benefit of variability in characteristics coupled with economical and technical viability on considering exotic development options like dump-flooding and gas recycling.
X-ray Computed Tomography Observation of Methane Hydrate Dissociation
Authors: Tomutsa Liviu , Freifeld Barry , Kneafsey Timothy J. , Stern Laura A.
Published: December 2007

Deposits of naturally occurring methane hydrate have been identified in permafrost and deep oceanic environments with global reserves estimated to be twice the total amount of energy stored in fossil fuels. The fundamental behavior of methane hydrate in natural formations, while poorly understood, is of critical importance if the economic recovery of methane from hydrates is to be accomplished. In this study, computed X-ray tomography (CT) scanning is used to image an advancing dissociation front in a heterogeneous gas hydrate/sand sample at 0.1 MPa. The cylindrical methane hydrate and sand aggregate, 2.54 cm in diameter and 6.3 cm long, was contained in a PVC sample holder that was insulated on all but one end. At the uninsulated end, the dissociated gas was captured and the volume of gas monitored. The sample was initially imaged axially using X-ray CT scanning within the methane hydrate stability zone by keeping the sample temperature at 77°K. Subsequently, as the sample warmed through the methane hydrate dissociation point at 194°K and room pressure, gas was produced and the temperature at the bottom of the sample plug was monitored while CT images were acquired. The experiment showed that CT imaging can resolve the reduction in density (as seen by a reduction in beam attenuation) of the hydrate/sand aggregate due to the dissociation of methane hydrate. In addition, a comparison of CT images with gas flow and temperature measurements reveals that the CT scanner is able to resolve accurately and spatially the advancing dissociation front. Future experiments designed to better understand the thermodynamics of hydrate dissociation are planned to take advantage of the temporal and spatial resolution that the CT scanner provides.
Trucking of Compressed Natural Gas (CNG) from the Naturally Fractured Galt Field in the Gaspe Area of Quebec
Authors: Aguilera R. , Lavoie J. Y.
Published: December 2007

Based on a 427-km seismic survey run in Gaspe in the early 1980's, well Galt # 1 was drilled to a depth of 2500 m in 1983. Several Devonian DSTs indicated the presence of 46-degree API oil in the Indian Cove formation between 993 and 1309 mKB, and gas in the Forillon formation between 2245 and 2353 mKB.

The well was not considered economic at the time and was abandoned using various cement plugs. Subsequent evaluation of the log and DST data indicated that the naturally fractured Forillon limestone had been heavily damaged during drilling operations.

The well was re-entered in September 1993 and following an acid job tested at approximately 1 m3/day of oil from the Indian Cove formation. The well was next drilled out to the Forillon formation in June 1994. It flowed at approximately 6,400 m3/day of gas during the extended flow period; however, gas rates in excess of 56,000 m3/day were recorded during the isochronal test. Due to the lack of pipeline infrastructure, the gas is being trucked to a copper smelter plant operated by Noranda at Murdochville. This replaces the propane previously used at the smelter.

This paper discusses the geology of the area, the log and DST data, the compressed natural gas (CNG) system used for trucking the gas and the economics of the project.
Matching Technical Solutions to the Lifecycle Phase is the Key to Developing a CBM Prospect
Authors: Blauch Matthew E. , Weida Dana , Mullen Mike , McDaniel B. W.
Published: December 2007

The early stages of a coalbed methane (CBM) project development often require more extensive use of currently available technologies than can be economically justified when approached from a conventional oil and gas drilling focus. As a result, key evaluation tools and technologies are either omitted or not considered before significant decisions are made regarding viability of a CBM play. Understanding that the various lifecycle phases will each affect different objectives and decision points is important. Following site acquisition and estimating basic drilling costs, at least five lifecycle phases can be identified: (1) Regional Resource Reconnaissance, (2) Local Asset Evaluation, (3) Early Development, (4) Mature Development; and (5) Declining Production.

A systematic review of current and recently developed enabling technologies is presented in the context of their potential use and applicability. Environmental risk and other constraints that can impact development vary globally, as do economics and production forecasting. New and emerging chemical technologies, as well as hydraulic fracturing refinements, play key roles in various lifecycle phases and decision making to identify successful CBM development projects as early as possible. The paper presents strategies that can reduce development phase failure risk and help predict or rank production potential. Economic constraints usually become more restrictive as the lifecycle moves to Phase 4 and beyond, but key information needed to enter Phase 4 is often overlooked. Examples of this scenario are presented from a global perspective.

Globally, new and existing technologies combined with dynamic gas and electricity markets are changing the nature of CBM development opportunities. More accurate and timely go/no-go information needs to be used in the decision making process. Converting development opportunities to develop-ment successes involves integrating planning and evaluation methods, using targeted development technologies in the proper phase, and managing risk.
Correlations to Determine Retrograde Dew Pressure and C7+ Percentage of Gas Condensate Reservoirs on basis of Production Test Data of Eastern Venezuelan Fields
Authors: Marruffo Ilsis , Maita Jose , Him Jesus , Rojas Gonzalo
Published: December 2007

In this paper are presented new correlations to determine the dew point pressure and C7+ content of gas condensate reservoirs, based on production fields parameters usually available. To develop these correlations it were collected 146 PVT analyses of Venezuela (Anaco) fields: San Joaquin: 42; Santa Rosa: 26; El Roble: 16; Guario: 4; Santa Ana: 3; El Toco: 3; Zapatos: 15; Mata-R: 15; Aguasay: 13; La Ceibita: 5; Carisito: 4.

The PVT results were validated through consistence tests: mathematical recombination and mass balance. After these steps an statistical analysis of the variables was done.

For this, statistical methods were used and they were focused on multiple no linear regressions.

The correlations's accuracy was the following: dew point pressure showed 5.74 % of average error with a correlation coefficient of 0.82 based on 80 PVT's data, the first C7+ content correlation showed 9.59 % of average error with a correlation coefficient of 0.98 based on 81 PVT's data, the second C7+ content correlation showed 7.85 % of average error with a correlation coefficient of 0.99 based on 90 PVT's data.

The new retrograde dew point correlation obtained improves the Nemeth and Kennedy's (10) that forecast dew points with 9.69 % of average error when it is applied on 54 Anaco's PVT analyses which had all the compositional information that it requires; with the new dew point correlation the average error was 5 % for the same data. These new correlations allow to improve the characterization and exploitation plans of gas condensate reservoirs without PVT information.
Why Plot the Equivalent Time Derivative on Shut-in Time Coordinates?
Authors: Anderson David , Jordan Colin Lyle , Mattar Louis
Published: December 2007

The (semilog) derivative of pressure data from oil and gas wells is a widely accepted and highly useful tool for reservoir characterization. For buildup pressure data, this derivative is calculated with respect to equivalent time. It is generally assumed that since this derivative is obtained using equivalent time, it should be plotted on a coordinate axis that uses equivalent time. However, in the presence of boundaries, this style of plotting distorts the shape of the derivative during late-time, to the point where it bears very little resemblance to the original shape of the drawdown derivative. Moreover, the shape of the buildup derivative is strongly affected by the duration of the preceding drawdown.

This paper investigates the shape of the equivalent-time-derivative when plotted against both equivalent time and real time (shut-in time) coordinates. Using computer generated models, it shows that a plot based on real time produces a buildup derivative response that is much closer in shape to the drawdown derivative, thus resulting in more accurate diagnosis of reservoir characteristics. This was true regardless of reservoir type, geometry or producing time. The advantages of using real time as a plotting coordinate are, a more readable diagnostic plot and a more easily recognized shape because of its similarity to the drawdown.

Our research extends the work of Spivey (1999). This study investigated numerous reservoir types including homogeneous with boundaries, composite, fractured and dual porosity, and it also covered a wide practical range of producing times.
Custom Recirculation ESP System in 7-in. Casing Increases Indian Basin Gas Well Production
Authors: Gaddis R. D. , Knight J. W. , Lisenbee J. T.
Published: December 2007

Recirculation electric submersible pump (ESP) systems have been successfully deployed below well perforations to avoid gas interference in the pump and to maximize well drawdown. Most of these units consisted of ESP equipment designed for 5.5-inch well casing and included a patented system of custom-built flat recirculation tubing due to space considerations.

The operator's previous attempts at de-watering potentially high rate gas wells in order to increase overall gas production had consisted of shrouded 4.50-inch outer diameter (OD) motor ESP systems set below the perforations. The motor was re-rated above standard nameplate horsepower due to the hydraulic requirement necessary to lift approximately 4500 bwpd from a depth of ± 7500 ft. true vertical depth. The amount of water production with the shrouded unit, and hence, gas production, was limited because of motor horsepower limitations.

This paper describes the first known applications of a customized "flat-tube" style recirculation ESP unit consisting of equipment designed for 7-inch casing. A benefit of this development was to increase available motor horsepower. Results of these installations range from increased water production, and hence, increased oil and gas production, to increased run times and lower power and equipment lease costs for the operator.

The system represents a successful and significant extension of existing recirculation pump technology. Equipment description and economic and operational benefits are presented for two wells.
Novel Surveillance Helps Operators Track Damage
Authors: Brown Kenneth G. , Sawyer Walter K.
Published: December 2007

As part of an ongoing study sponsored by the Gas Technology Institute, new technology has been developed that provides storage operators with a cost effective method to frequently monitor wellbore damage with reasonable accuracy. Two procedures were developed and tested, the Sawyer-Brown Method (SB Method) and the Minute-Rise Deconvolution Method (MRD Method). These procedures are inexpensive, since no service company personnel or down-hole equipment is required. Consequently, the wells can be tested at much more frequent intervals than is typical of current testing methods.

The theoretical basis of each method is developed. The successful application of the SB Method is demonstrated using conventional deliverability test data and verified using multiple rate pressure transient tests in which bottom hole pressure gauges were used. The theoretical basis of the MRD Method is validated using simulated data. Difficulties encountered in the practical application of the MRD Method are presented and discussed. Areas of additional work are identified and guidelines for the implementation of these methods are presented.
Integrated Multidiscipline Approach Lead To A Recent Success In Naturally Fractured Reservoir - The Macueta Experience.
Authors: Girardi A. , Cohen M. , Kozlowski E.
Published: December 2007

The Macueta is a gas field located in the Acambuco Area, Tarija Basin, Northwest Argentina. This area is owned by the Acambuco Consortium: Pan American Energy (operator, 52%), Shell (22.5%), Repsol-YPF (22.5%), Apco (1.5%) and NorthWest (1.5%). The reservoir is formed by tight naturally fractured quarzitic sandstones of Devonian age (Huamampampa and Icla Formations), trapped in a narrow and elongated anticline within the subandean region.

Since the early 80's, four drilling initiatives, including vertical and horizontal wells, showed moderate to no success at all (AOF = 3 MMscfd- 14 MMscfd).

A new approach, using modern well testing and logging tools, was performed. This approach, including a careful study of the fracture system, in situ stress analysis and fracture production characterization, turned the view and triggered the field development.

The key to success was the identification, through selective zone well testing, of a zone far from the wellbore with high permeability, and its association with better fracture development in the crestal zone of the structure. This finding helped to understand the production mechanism of the reservoir.

This study is supported by acoustic image logs, production logs and well tests taken in Mac.x-1001bis, a former vertical well.

In this well, a succesful drilling reentry operation was executed after planning a 1150 ft long horizontal well trajectory with improved chances of success by maximizing fracture intersection.

The Mac.x-1001bis reentry well tested 36 MMscfd of gas and it has an absolute open flow (AOF) of 144 MMscfd. This increase of productivity, up to 40 times compared with the former wells, proves the convenience of horizontal technology in naturally fractured environments when it is carefully planned and executed.

This well sets a record in the basin for the Icla Fm. and opens new expectations and possibilities for the development of this type of reservoirs.