bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Mini-Falloff Test to Determine Reservoir Parameters and Optimize Fracture Designs in a Tight Gas Field
Authors: Harting T. A. , Cox D. L. , Murillo R. , Young T. L. , Adegbola K. A. , Schupp D.
Published: December 2007

This paper provides examples of using small injection tests on tight gas wells in Jonah field to determine reservoir pressure and transmissibility.

Prior to Mini-Falloff (MFO) test application in Jonah field, reservoir pressure and permeability of each sand body were obtained from log-derived correlations; these correlations in the presence of depletion have been determined to be invalid. The incorrect reservoir pressure and permeability will generally result in wrong fracture geometry and pre-frac rate prediction. The MFO's were designed as small injection tests prior to fracture stimulation to correct these anomalies.

The After Closure Period following the MFO injection and shut-in contain the reservoir pseudo-linear and pseudo-radial flow periods. Analysis of the pseudo-radial flow period provides reservoir transmissibility (kh/μ) and initial reservoir pressure (Pr) in a manner similar to a Horner analysis. These two-reservoir parameters play a crucial role in the optimization of fracture design and rate prediction. For a tight gas sand, the amount of time required to reach pseudo-radial flow was thought to be quite large. However over sixty percent of all the valid tests performed so far reached pseudo-radial flow within a shut-in time of 24hrs.

A total of eighteen MFO tests were performed in the Jonah field Lance formation from April to October 2003. Two of the tests were invalid due to extremely high depletion and surface pressure gauge malfunction. The remaining sixteen valid data sets show various ranges of depletion in twelve sands tested (0.36 - 0.52psi/ft) while the two remaining sands were over-pressured (> 0.7psi/ft). Permeability results in general ranges from 0.004 to 0.08md. The Jonah field log-derived correlations were validated and improved with the MFO results.
Unified Model of Heat Transfer in Gas-Liquid Pipe Flow
Authors: Zhang H. -Q. , Wang Q. , Sarica C. , Brill J. P.
Published: December 2007

A unified model of multiphase heat transfer is developed for different flow patterns of gas-liquid pipe flow at all inclinations from -90° to +90° from horizontal. The required local flow parameters are predicted by use of the unified hydrodynamic model for gas-liquid pipe flow recently developed by Zhang et al.1,2 The model prediction of the pipe inside convective heat transfer coefficients are compared with experimental measurements for a crude oil/natural gas system in horizontal and upward vertical flows, and good agreement is observed.
Integrating Completion and Drilling Knowledge Reduces Trouble Time and Costs on the Pinedale Anticline
Authors: Garcia Joe , Huckabee Paul , Hailey Byron , Foreman Jay
Published: December 2007

The Pinedale Anticline of southwest Wyoming has proven technically challenging to drill and cement. This tight gas reservoir has over 5,000 ft of vertical pay interval in stacked lenticular sands. With pore pressures ranging from normal to over 16.5 lbm/gal, unplanned circulation losses were negatively impacting drilling and cementing operations. In early 2002, desired top of cement was being achieved on only 31% of the production casings. As a result, one of three things would occur: Stimulation treatments would not go to the intended zones, resulting in no production for completion dollars spent. As a result, petrophysical evaluations of entire intervals were being questioned.Costly remediation treatments had to be conducted during completion operations to isolate zones before they could be completed.Production reserves were at risk or deferred because of inadequate annular isolation.

Completion engineers use fracturing applications to enhance well performance while drilling-induced fracturing is a problem to manage. In both disciplines, knowing fracturing and pore pressures is critically important. A process was developed to determine and calibrate pore pressures and minimum horizontal stresses for the design of hydraulic fracturing treatments and production prediction. Fracture extension pressure variation with depth was measured on each well completion. Mechanical rock properties were measured in the laboratory to validate calculations from openhole logs that were used in the fracturing simulator. The data was validated further by post-matching the simulator with fracturing treatment data. The question was asked, "Why not use this frac data to prevent drilling-induced fracturing?"

Because of losses and wellbore stability issues, completion data from offset wells was incorporated into casing and mud programs. Underbalanced drilling techniques were also introduced which in turn created obvious problems for the cement design. Best practices were incorporated, including foam cement on a selected basis. As a result, cement tops are now reaching the desired heights 100% of the time. Even in cases where there has been no circulation when the cement job is started, desired cement tops have been achieved. As a result, costly remediation efforts have been eliminated saving an estimated U.S.$1.3 million/year. All the desired pay intervals are being isolated so that the decision to complete reservoir intervals is based on reservoir quality rather than mechanical issues with the wellbore. Production can now be attributed to given pay intervals with confidence aiding in proper evaluation of entire sections of the reservoir.
Curve Alignment for Well-to-Well Log Correlation
Authors: Zoraster Steven , Paruchuri Ramoj , Darby Steve
Published: December 2007

This paper presents a novel curve alignment program based on dynamic programming applied to well-to-well log correlation. The dynamic time warping (DTW) algorithm for data mining and signal processing is adapted to work on depth sampled well log data. Analytical tools to assist evaluation of curve alignment are provided. Our implementation can be described as automated, interactive, and constrained.

Mathematical optimization - dynamic programming - provides the algorithmic, "automated" part of our solution to the well log correlation problem. "Interactive" means that the process is fast enough to be used interactively, and that it should be used iteratively, supplying visual and quantitative feedback to user identification of markers common to both wells. "Constrained" means that decisions by an educated user such as a geologist or a geophysicist, about depth ranges to which the algorithmic is applied is important, as are decisions about acceptance or rejection of particular results.

The key to success has been display of pick selection mapped from posted depths in a "reference well" at depths on the "target" well, and the provision of interactive features so that the program be guided in the search for good problem solutions.
Application of a Lightweight Cement Slurry for the Naturally Fractured Mesa Verde Formations
Authors: Posey D. B. , Purvis D. L.
Published: December 2007

The Mesa Verde formation is highly naturally fractured and varies in depth from 5500 ft to 6200 ft. Low recoverable reserves make wells in this area marginally economical.

The lower hole is air drilled and cemented back to the intermediate at 3700 feet. Historically, the production casing has been cemented with a 50/50 Poz/H blend mixed at 13.2 ppg. Bond logs were often marginal and fall back was a problem.

This paper reviews the development of a lightweight cement system with the ability to develop high compressive strength to enhance the mechanical seal. This slurry needed to have plating lost circulation material (LCM) to prevent fall back and minimize node buildup due to high fluid loss. Compressive strength, fluid loss and rheological properties for various formulations are presented. The results of over forty jobs are summarized with operation and bond log results reviewed in detail from four typical wells.
A Numerical Model for Simulating Solid Waste Injection in Soft Rock Reservoirs
Authors: Chin L. Y. , Montgomery C. T.
Published: December 2007

This paper describes the development, validation, and application of a numerical model that simulates solids injection operations for soft rock reservoirs. There exist many classical fracturing models that are good tools for evaluating solids injection operations in formations with competent rocks. However, when evaluating solids injection operations in soft rock formations such as unconsolidated sand, these classical fracturing models generally fail to provide reliable evaluations. In this paper, a solids injection model was specifically formulated and developed for solids injection in soft rock formations. The development of the proposed model for soft rock formations is based on the Biot's self-consistent theory, plasticity theory, and fracturing and liquefaction criteria for rock. The predictive capability of the developed model was verified against field data from waste injection wells in soft rock formations. The validated model was used to evaluate solid waste disposal for cases of various injection operation conditions in a soft rock reservoir. Results show that the solids injection model provides an effective tool to assess the maximum injection volume allowed per well, the area of influence of injection, the bottom-hole injection pressure, and the vertical containment of the injected fluids and solids. Simulation results for representative cases are presented. The model can also be useful for quantitatively assist in identifying feasible solids injection mechanisms in soft rock reservoirs.
Determining Formation Resistivity Anisotropy in the Presence of Invasion
Authors: Barber Tom , Anderson Barbara , Abubakar Aria , Broussard Tracy , Chen Kuo-Chaing , Davydycheva Sophia , Druskin Vladimir , Habashy Tarek , Homan Dean , Minerbo Gerald , Rosthal Richard , Schlein Robert , Wang Hanming
Published: December 2007

Resistivity anisotropy in both laminated shale-sand and clean sand formations is well documented. Tools that are sensitive to formation anisotropy are also well documented, and the leading contender for this type of measurement is the transverse induction array. Such an array, whose transmitter generates formation currents in the plane of the borehole axis, has a good sensitivity to the vertical resistivity of the formation, Rv.

Invasion of mud filtrate into permeable formations has long complicated wireline log analysis. Interpretation of anisotropic formations will be no different. In most drilling environments, these formations will be invaded as readily as isotropic formations. Although we expect that invading mud filtrate from water-based mud will reduce the anisotropy, we also expect that invading oil-based mud (OBM) filtrate will increase it. Thus the anisotropic properties of each zone must be determined separately.

A single-spacing induction array (of any orientation) cannot, by itself, separate uninvaded zone properties from those of the invaded zone. Multiple-spacing tools have been used for many years to make this separation. A multiarray triaxial induction tool is in field test, and invasion interpretation algorithms are under development. A fast analytic algorithm corrects shoulder effect on all nine triaxial couplings of each array, allowing Rv and the horizontal resistivity Rh to be determined at several radial depths in the formation. Rigorous 2D and 3D inversions are also used to evaluate beds on the order of 1 m thick in both vertical and deviated wells. Examples in both modeled formations and in actual formations demonstrate the methods.
A New Approach to Improve Cuttings Transport in Horizontal and Inclined Wells
Authors: Yu Mengjiao , Melcher Daniel , Takach Nicholas , Miska Stefan Z. , Ahmed Ramadan
Published: December 2007

With increasing measured depths and horizontal displacements in extended reach (ERD) wells, good hole cleaning remains one of the major concerns in the oil and gas industry. While the methods currently used to increase cuttings transport capacity seek to increase the drag force applied to drilled cuttings, they are unable to significantly increase the cuttings transport capacity in horizontal and inclined wellbores because the gravitational force causes the cuttings to settle to the bottom side of the borehole.

The proposed technology works to counteract the gravitational force while simultaneously increasing the drag force by attaching gas bubbles to drilled cutting particles with chemical surfactants. The gas bubbles will pull the cuttings upward because of their buoyancy in the drilling mud thereby counteracting the gravity force. Furthermore, the gas bubble/cutting aggregation will have a larger surface area than the cutting alone, resulting in an increase in the drag force.

In addition to the theory behind this technology, this paper also focuses on laboratory development. Laboratory experiments were conducted to determine the effects of chemical surfactants, pH, and cutting particle size on the attachment of air bubbles to cutting particles. Two types of chemical surfactants, one to attach air bubbles to cutting particles and another to strengthen the air bubble, were necessary for attachment to occur. The corresponding chemical solution, with a pH range of 9 to 11, resulted in the optimal attachment of air bubbles to drilled cuttings up to 1.4mm in diameter that can be floated to the top of the fluid. Thereafter, experiments were conducted on a laboratory-scale flow loop with a horizontal test section. While conducting the flow loop experiments in the base solution without chemical surfactants, no cuttings were moved along the horizontal section. However, with the use of straight chain chemical surfactants up to 30% of the cuttings were carried completely across the horizontal tube by air bubbles and many other cuttings were carried partially across the horizontal tube. Further experiments showed that the use of certain branched chemical surfactants can greatly increase (about 58% of the cuttings were transported) the strength of attachment between air bubble and drilling cuttings compared to straight chain surfactants. These results show that this technology has the potential to make a "step-wise" improvement of cuttings transport capacity in horizontal and inclined wells.
Integration of Time-Lapse Seismic Data into a Flow Model Study of CO2 Injection into the Weyburn Field
Authors: Yamamoto Hirofumi , Fanchi John R. , Davis Tom L.
Published: December 2007

The Reservoir Characterization Project at the Colorado School of Mines has conducted a time-lapse seismic survey in a section of the Weyburn Field, Saskatchewan, Canada. The section is being subjected to a CO2 injection process that began in October 2000. The seismic monitoring process is of interest for both enhanced oil recovery and geologic carbon sequestration. This paper describes a study that integrated both static and dynamic data in a history matched (calibrated) model of CO2 injection performance. An objective function was used to quantify study results.
A Numerical Assessment of Modern Borehole NMR Interpretation Techniques
Authors: Toumelin Emmanuel , Torres-Verdin Carlos , Sun Boqin , Dunn Keh-Jim
Published: December 2007

Recent developments of two-dimensional (2D) NMR techniques have been advertised as efficient and accurate methods to interpret a variety of petrophysical parameters, including mixed fluid saturation, in-situ oil viscosity, wettability, and pore structure. No quantitative study, however, has been presented to precisely define the domains of application and practical limitations of such methods. We address this issue by introducing a general pore-scale framework to accurately simulate suites of NMR data in complex rock models. This general pore-scale framework is based on the novel combination of three models: (1) NMR random-walk model for multiphase fluid diffusion, T1 and T2 relaxations, (2) thermodynamically-based wettability model, and (3) saturation model based on imbibition history. Two-dimensional NMR inversion was used to interpret synthetic data sets for diverse petrophysical configurations including two-phase saturations with different oil grades, mixed wettability, carbonate pore heterogeneities, or clay-induced internal fields.

It is shown that T2/diffusion (D) maps are more reliable than T1/T2 maps for a variety of applications, including fluid typing without the need of independently determined cut-offs. It is also found that T2/D maps are more reliable than T1/T2 maps for heavy-oil and gas applications, even in the presence of substantial internal fields. A major failure of accurate fluid typing and pore structure estimation with NMR methods could be attributed to mixed-wettability states, which had never before been accurately considered in NMR interpretation studies. For the assessment of wettability, only that of light oil could be reliably interpreted from 2D NMR. No currently available 2D NMR method can be used to correctly diagnose substantial diffusion coupling in carbonate rocks.
Gas Infill Well Selection Using Rapid Inversion Methods
Authors: Gao H. , McVay D. A.
Published: December 2007

It is often difficult to quantify the drilling and recompletion potential in producing gas fields, due to large variability in rock quality, well spacing, and well completion practices, and the large number of wells involved. Given the marginal nature of many of these fields, it is often prohibitively expensive to conduct conventional reservoir characterization and simulation studies to determine infill potential. There is a need for rapid, cost-efficient technology to evaluate infill potential in gas reservoirs, particularly tight gas reservoirs. Some authors have used moving window statistical methods, which are useful screening tools for identifying potential areas or groups of wells for further study.

We present a new simulation-based inversion approach for rapid assessment of infill well potential. Our work differs from typical simulation inversion applications in that, instead of focusing on small-scale, high-resolution problems, we focus on large-scale, coarse-resolution studies consisting of hundreds or, potentially, thousands of wells. In an initial application, the method employs well locations, production data and an approximate reservoir description and, accordingly, is able to identify potential areas or groups of wells for infill development quickly and inexpensively. Prediction accuracy can be increased commensurate with reservoir characterization effort, time and costs. Thus, the method provides a consistent basis for transition from screening studies to conventional reservoir studies.

The proposed approach is demonstrated to be more accurate than moving window statistical methods in synthetic cases, with comparable analysis times and costs. In a blind validation study of a field case with 40 years of production history, the method was able to accurately predict performance for a group of 19 infill wells.
Installing Low-Cost, Low-Pressure Wellhead Compression on Tight Lobo Wilcox Wells in South Texas: A Case History
Authors: Harms L. K.
Published: December 2007

This paper presents a case history of twenty-one low-cost wellhead compressors on tight Lobo Wilcox wells in South Texas. These wells previously produced to area-typical low-pressure gathering systems. Overall the installations showed substantial increases in the gas production rate as well as outstanding composite economics.

However, not all installations were successful and failures are examined for lessons learned to improve future applications.

Production data on the results of each of the installations are provided. The decision model used to select candidate wells from the 1600 producing wells in the field is also described.

Low-cost, low-pressure wellhead compression is presented as a viable artificial lift alternative and in fact the preferred and cheapest alternative in some cases.
Laboratory Investigation of NMR Crude Oils and Mud Filtrates Properties in Ambient and Reservoir Conditions
Authors: Chen Songhua , Zhang Gigi , Kwak Hyung , Edwards Carl M. , Ren Jason , Chen Jiansheng
Published: December 2007

We present laboratory NMR measurements of 445 crude oil samples, four mud filtrates and four base oil samples, and 47 refined oil samples. In addition to measurements at ambient conditions, a subset of the samples were measured at high temperatures and high pressures for the purpose of investigating the temperature, pressure, chemical structure, and oxygen-saturation dependences of the NMR T2 relaxation time. We found that the relaxation time, T2, correlates with specific gravity better than with viscosity, especially for heavy oils. Molecular oxygen dissolved in the oils affects the light oils significantly and if uncorrected, the oxygen-saturated T2 departs significantly from known T2 viscosity and temperature correlations. We propose an approximate method to correct the effect of dissolved oxygen based on experimental investigation of oxygen-free and oxygen-saturated samples. We further studied the pressure dependence of the crude oils, OBMF, and refined oils and found that even for dead oils, T2 depends on pressure and the dependence fits a quadratic expression. Finally, we investigated the chemical structure dependence of the refined oil samples; we found that the viscosity-T2 correlation is different for ring-structured hydrocarbons from linear-chain structured hydrocarbons. On the other hand, alkanes, alkenes, and esters share the same correlation.
Effect of Coiled Tubing Curvature on Friction Pressure Loss of Newtonian and Non-Newtonian Fluids - Experimental and Simulation Study
Authors: Jain Samyak , Singhal Naveen , Shah S. N.
Published: December 2007

Coiled tubing is widely used in the petroleum industry to pump fluids in the well bore at high rates. The friction pressure losses occurring in the tubing at these high rates are an issue of immense concern to the industry. Most of this friction loss can be attributed to the section of the tubing reeled on the spool during the treatment. The dimension of the reel used in the treatment governs the degree of curvature of the tubing and in turn the corresponding pressure drop. These pressure losses apart from increasing the cost of the treatment due to increased energy requirements also reduce the life of the tubular used.

Experimental and simulation study has been undertaken to determine friction pressure loss in 1 1/2 and 2 3/8-in. coiled tubings using water and 35 lb/Mgal guar as test fluids. Computational Fluid Dynamics software FLUENT has been used to generate simulations that have been validated with limited experimentation using a field-scale test setup. Previous experiments used limited flow rates and few curvature ratios due to high field-scale experimentation costs. But using CFD simulations friction pressure loss data have been gathered for a range of curvature ratios and flow rates that are comparable to the ones used in the field.

Results obtained have been used to determine the effect of curvature ratio on friction pressure losses while pumping Newtonian and non-Newtonian fluids in 1 1/2-in. and 2 3/8-in. tubing.
Investigating How Proppant Packs Change Under Stress
Authors: Schubarth Stephen , Milton-Tayler David
Published: December 2007

Proppant conductivity is an important design criterion in hydraulic fracturing treatments. Knowing how different proppants behave under changing stress conditions is important to fracture stimulation success. Conductivity and non-Darcy flow effects has been laboratory measured for all ceramic proppants. Unfortunately, almost all laboratory measurements are performed with an increasing stress and cyclic stress behavior is not observed. Often, in the production of oil and gas wells, shut-in periods occur and pressure in the wellbore and proppant pack increases causing stress to be relieved on the pack. When production begins again, stress is increased on the pack. This is stress cycling and past publications1 have noted that stress cycling can cause a reduction in proppant pack conductivity.

The work presented in this paper chronicles a vast series of crush tests performed on several proppant types and sizes. The crush tests were run using exactly the same starting sieve distribution for each particular proppant tested. After a sample was subjected to stress or multiple stress cycles, it was sieved for a detailed analysis. The change in the sieve distribution was noted and a median particle diameter was calculated along with the standard deviation of the distribution. A relationship was observed between these values and those of conductivity and Beta Factor. From these relationships it can then be possible to estimate the effect that stresses cycling has on conductivity and non-Darcy flow effects.

The papers results can help the fracture design engineer to better understand how conductivity, of the designed proppant pack, will change with time as stress cycling occurs. This understanding can lead to the recovery of more oil and gas through improved stimulation results.
Including Non-Equilibrium Effects in Models for Rapid Multiphase Flow in Wells
Authors: Civan Faruk
Published: December 2007

The modeling of rapid multiphase flow of reservoir fluids in wells and the non-equilibrium partial separation of dissolved gases from the metastable oil and water phases is discussed and reviewed. The effect of non-equilibrium on the deviation of the pressure distribution along the wells from the equilibrium model predictions is delineated.

The multi-phase fluid flow is described by means of the differential mass, momentum, and energy balance equations along the well. The rate of gas transfer from the metastable liquid phases to the gas phase is expressed in terms of the relaxation time determined by the prevailing gas phase volume fraction, and the pressure and temperature conditions. The solution of the set of differential equations is obtained numerically under a typical scenario involving the constant gas, oil, and water production rates at the wellhead. It is demonstrated that the nonequilibrium pressure distribution in the well deviates significantly from the equilibrium results depending on the local relaxation time, which vary along the well.

The present models can be incorporated into the conventional reservoir simulations for accurate description of the effect of the actual multi-phase well-fluid behavior under non-equilibrium flow conditions. The models are applicable with two-phase (oil/gas and water/gas) and three-phase (oil/water/gas) well fluid systems.
Hydrodynamic Conditions of Hydrocarbon Accumulation Exemplified by the Pomorsko and Czerwiensk Oil Fields in the Polish Lowland
Authors: Zawisza Ludwik
Published: December 2007

The hydrodynamic conditions of migration and accumulation of hydrocarbons are exemplified by two oil fields of Polish Lowland.

According to Hubbert, under hydrodynamic conditions a buoyancy force and moving water exert major control over the distribution of water, oil and gas in a reservoir, causing the oil/water and gas/water contact to be tilted.

In this paper, a modified theory is advanced to define more precisely the position of potential oil and gas traps. The theory introduced here is more universal than Hubbert's theory because it accepts not only the groundwater motion (dynamic effect), but also the variability of the oil, gas and water density (static effect) and heterogeneity of reservoir rocks (capillary effect).

According to the presented method, to determine potential sites for hydrodynamic entrapment of hydrocarbon, it is necessary to construct potentiometric maps for groundwater in terms of fresh water, maps of differential energy of oil or gas with respect to groundwater and maps of differential energy of oil or gas caused by capillary forces and then to add them up by superimposition.

The suggested method of determining the positions of potential hydrodynamic petroleum traps is comparatively simple to apply and gives good results in regions of high hydraulic gradients, high variability of salinity and hydrocarbon densities and high variability of porosity and permeability of reservoir rocks.
High-Order Upwind Schemes for Three-Phase Multicomponent Flows, A Preliminary Investigation
Authors: Valenti Gianluca , Jessen Kristian , Mallison Bradley T. , Gerritsen Margot G.
Published: December 2007

We analyze the accuracy of three upwind discretization schemes (first order SPU, second order TVD and third or-der ENO) for the numerical simulation of one-dimensional three-phase multicomponent displacements. The solutions are stepped through time using Runge-Kutta methods with the same accuracy as the spatial discretization.

The schemes are tested on numerically challenging 3- and 11-component water-alternating-gas processes. Through lack of an analytical solution, the results are compared to a convereged high resolution simulation.

The preliminary results show that higher-order schemes lead to much sharper solution profiles and more accurate front propagation speeds than the first order SPU scheme. The schemes allow coarser grids to be used for the same solution accuracy and are therefore also more efficient. These results agree with a previous study for two-phase flows.1
Competitive Adsorption of a Hybrid Surfactant System onto Five Minerals, Berea Sandstone, and Limestone
Authors: Grigg Reid B. , Baojun Bai , Yi Liu
Published: December 2007

This paper presents the adsorption/desorption results for two surfactant systems and for a mixture of the two onto five minerals and two porous media. The systems are composed of Chaser International CD1045™ (CD) and a calcium lignosulfonate (CLS), Lignosite® 100. Two series of experiments were carried out: (1) static adsorption of CLS, CD, and CLS/CD mixtures onto five pure minerals (silica, montmorillonite, kaolinite, dolomite, and calcite); (2) dynamic adsorption of CLS, CD, and CLS/CD mixtures onto core samples of Berea sandstone and Indian limestone. All experiments were performed at 40°C using a 2.0% brine solution with concentrations of 500 mg/l of CD and 5,000 mg/l of CLS.

Static adsorption experiment results showed that: (1) CLS adsorption density onto silica is less then back ground noise (zero); on the other four minerals, adsorption density ranged from 0.5 to 10 mg CLS per g of mineral; (2) CD adsorption density onto the five minerals ranged from 0.4 to 1.2 mg CD per g of mineral; (3) CD adsorption density onto the five minerals decreased by 20 to 7 0% when mixed with CLS.

Dynamic adsorption experiment results showed that: (1) The times required to reach adsorption equilibrium for both CD and CLS were longer for Berea sandstone than for Indiana limestone and for both porous media, were much longer than those for the non-porous minerals; (2) Competitive adsorption generally took several days to reach equilibrium.

Stability and interfacial tension tests on both injected and effluent samples were performed. Results correlated well with the adsorption/desorption tests; for example, foaming capability was lost in some systems due to adsorption.
Combined Effect of Non-Darcy Flow and Formation Damage on Gas Well Performance of Dual-Porosity and Dual-Permeability Reservoirs
Authors: Pereira Tavares Carlos Alberto , Kazemi Hossein , Ozkan Erdal
Published: December 2007

This paper addresses the combined effect of formation damage and non-Darcy flow in naturally fractured reservoirs using simplified analytical solutions and a two-dimensional numerical simulator. Pressure drawdown, buildup, and isochronal tests simulated in this work indicate that, despite high fracture permeability, skin damage may accentuate the non-Darcy flow effect and drastically influence pressure-transient characteristics of low-pressure, naturally fractured reservoirs. In high-pressure reservoirs, this effect is significant only at high rates. Non-Darcy flow does not usually mask the typical pressure-transient characteristics of dual-porosity and dual-permeability reservoirs, but the conventional interpretation of the early time data may lead to erroneous results. If the exponent, n, of the gas performance curve approaches 0.5 while the matrix permeability is low and flow rate is rather high, this indicates predominance of fracture flow. The practical motivations of this study and its extensions to other practical problems, such as condensate reservoirs where the condensate dropout in the wellbore region should increase non-Darcy flow, are also discussed.
Real-time Bayesian Inversion of Hydraulic Fracturing Treatment Efficiency from Tiltmeter Measurements
Authors: Lecampion B. , Jeffrey R. , Detournay E.
Published: December 2007

In this paper, we describe a method to estimate, in real-time, the efficiency of a hydraulic fracture treatment performed in porous reservoir from tiltmeter measurements.

The poroelastic deformation induced by the fracture opening and the fluid leak off is investigated at first. The resolution of fracture dimensions and orientation from tiltmeter measurements is also discussed. A limit, expressed in terms of the distance between the tiltmeters and the fracture, above which only the volume and orientation of the fracture have an effect on the tilt field is recalled. The proposed method of analysis recognizes that, without additional information, only the fracture volume and orientation can be accurately estimated from tiltmeter measurements. The knowledge of the injected volume at time t together with the tilts data allow to estimate the efficiency of the treatment at this time. Furthermore, because the method is computationally efficient, the treatment efficiency and fracture orientation can be obtained in real time (i.e. as the data arrive) throughout a hydraulic fracturing treatment.
Stability Maps for Continuous Gas-Lift Wells: A New Approach to Solving an Old Problem
Authors: Fairuzov Y. V. , Guerrero-Sarabia I. , Calva-Morales C. , Carmona-Díaz R. , Cervantes-Baza T. , Miguel-Hernandez N. , Rojas-Figueroa A.
Published: December 2007

Continuous flow gas-lift wells are susceptible to hydrodynamic instability (heading), which may cause cyclic variations of the wellhead pressure, oil and gas flow rates. Gas-lift instability is a reason of many operational problems, for example, compressor shutdowns caused by pressure and liquid flow rate surges, difficulties in the operation of low pressure separators, and excessive gas consumption. Stability problems in complex multiphase systems can be solved using stability maps. A stability map is a plane (2D) diagram that shows the regions of stable and unstable operation of the system, as well as its operating limits. In this paper theoretical and experimental stability maps for gas-lift wells are presented. Fild test were conducted to investigate the flow stability in a deep offshore gas-lift well. Different gas-lift stability criteria proposed in the literature are compared. Based on this study, recommendations on the selection of gas-lift stability criteria were developed. Examples of gas-lift stability map applications are also given.
Portfolio Management Framework for Multistage Investments
Authors: Chorn L. G.
Published: December 2007

Decision making for multi-stage exploration and development investments requires more analytical capabilities than are available from a Markowitz portfolio approach. The decision evaluation process is complicated by the evolution of project value as new project data is acquired, improved technology becomes available, and market conditions change. Management must also accommodate multiple business objectives including reserve replacement requirements, positive project NPV, increasing or sustaining annual production volumes, and cost of finding and developing. This article describes the application of dynamic programming techniques and the concepts of Markov chains to modeling projects within an investment opportunity portfolio. Using an exploration investment opportunity, we compare the guidance from a Markowitz approach with those from a Markov chain approach. The incremental insights are much greater than the cost of increased project detail required for the analysis.
Don't Be Fooled by Bayes
Authors: Wills Hector A. , Graves Ramona M. , Miskimins Jennifer
Published: December 2007

Often times the Petroleum Industry focuses on calculating the value of information using Bayesian analysis to determine a modified perception about the state of nature as a result of the new information's ability to better describe it. Some of the methods commonly used and widely published in Petroleum Engineering literature and commercial software; use the concepts of conditional probability, information sources, and the state of nature being interpreted. The interrelationships among these concepts are not systematically defined. More over, the conditional probability is freely assigned not considering the bounds that Bayes' Theorem imposes. This paper demonstrates the dependency of the value of information on how and where the conditional probability is assessed. What happens to the calculation when the initial conditional probability changes? Does it make a difference in the decision to be made after receiving the information? Using sensitivity analysis on the conditional probability term we examine published examples and show the deceiving nature of the reported results. The solution to this deception is given.
Capillarity-Induced Flow in Wetting Liquid Films: Implications for the Recovery of Volatile Oils from Fractured Porous Media
Authors: Yiotis A. G. , Boudouvis A. G. , Stubos A. K. , Tsimpanogiannis I. N. , Yortsos Y. C.
Published: December 2007

The recovery of volatile oils from the matrix of fractured porous media can be significantly aided through gas injection. Within certain assumptions, this process operates much like the isothermal drying of porous media. For example, the recovery from the matrix block is controlled by mechanisms involving capillary, viscous and buoyancy forces in the liquid and the liquid-gas interfaces, and mass diffusion and convection in the gas phase. The receding of the liquid phase is followed by the formation of macroscopic liquid films along the pore walls. Films provide hydraulic conductivity between macroscopically isolated liquid clusters and help transfer liquid over significant distances in the porous matrix. In this work, we study the effect of such films.

We propose a mathematical model for the capillarity-driven flow through wetting films in the context of evaporation and drying. A pore-network simulator that accounts for flow through liquid films, viscous flow in the bulk liquid phase of the clusters and mass transfer by diffusion in the gas phase is used. We study the effect of liquid films on phase distribution patterns and rates of recovery. We find that under strong capillarity conditions, the films span across the whole block, enhancing significantly liquid flow from distant clusters and improving recovery rates. An upscaling of the pore-network findings to macroscopic quantities is then presented. We comment on the extension of the method to binary mixtures and gravity effects. Our results show that flow through liquid films is a major transport mechanism in such processes.
Advances in Single-Diameter Well Technology: The Next Step to Cost-Effective Optimization
Authors: Waddell Kevin
Published: December 2007

From inception, solid expandable tubular technology has been touted as a game-changing technology. The logical end result of the technology, a single-diameter well, consists of a casing string with the same diameter at the top of the well as at total depth (TD). However, many drilling operators were reluctant to embrace even the basic solid expandable tubular concept without any track record, coupled with what they saw as the inherent risks.

Now, after five years of commercial installations, solid expandable tubular technology has proven to be a viable and economically feasible alternative to conventional drilling technology. In the majority of these installations, solid expandable tubulars have been deployed as a contingency to save a well when conventional technology failed. While this type of application is appropriate, operators do not reap the full advantage of all the benefits solid expandable tubular technology offers when integrated as part of the well plan.

A crucial step in the acceptance of expandable tubulars as a viable well construction method is to plan the system into the initial well design. In order for the tubulars to be planned into the original well design, operators must understand the compelling economic business cases for the application as well as accept the level of risk. The proven track record has helped mitigate the risk level for many operators, who are now focusing on the value proposition this technology provides. Operators must be comfortable with solid expandable technology in order to make the necessary leap of faith to the single-diameter well.

This paper will present the progress of monobore technology up to the present. It will discuss the stages achieved and those that still must be overcome to make this technology feasible. The paper will demonstrate that with solid expandable tubular and monobore technology, operators in general and deepwater operators in particular, will be able to maximize reservoir potential and lower drilling costs when using this value-added technology.
Modern Concepts in Perforation Inflow Diagnostic (PID) Testing: A Safe, Green, and Cost-Effective Technique for Evaluating Pre-Frac Reservoir Parameters
Authors: Hawkes Robert V. , Hategan Florin
Published: December 2007

Conventional completions and testing methods of low permeability gas reservoirs involve the cost and logistics of balanced and underbalanced perforating, next day stimulation treatment, surface production equipment, and the need for flaring during clean-up operations. In Canada, due to government regulations, operators will conduct the buildup test immediately after one or two day of clean-up operation. This practice has resulted in post-frac welltest analysis being masked by fracture fluid still present in the proppant pack and formation, resulting in misleading estimates of reservoir and fracture parameters important for production forecasting and completion evaluation.

Perforation Inflow Diagnostic, referred as PID testing, is a modern testing technique designed to deliver in a cost-effective manner valuable reservoir information such as: reservoir pressure, formation flow capacity, unstimulated gas inflow rate potential and near wellbore damage conditions prior to the fracture treatment. The advantages of PID testing are numerous: capability of accurate measurement of very low gas rates in low permeability (tight) gas wells (often reported as too small to measure), provides a safe testing environment, ensures secrecy and it defines itself as a green well testing procedure since it does not require flaring or venting of natural gas. PID testing is simply the surface and/or subsurface monitoring of the pressure response following extreme underbalanced perforating conditions, using electronic pressure recorders capable of high sampling rate. Unlike conventional testing procedures, the surface valve is closed during the entire test period and the formation fluids are produced into the closed chamber (casing and/or tubing volume). The measured pressures are converted to corresponding gas rates, based on the well-established closed chamber theory. PID testing therefore allows the collection of pressure and rate data required to derive the in-situ matrix permeability, wellbore skin and reservoir pressure.
Well-Completion Techniques and Methodologies for Maintaining Underbalanced Conditions Throughout Initial and Subsequent Well Interventions
Authors: Cavender Travis W. , Restarick Henry L.
Published: December 2007

Underbalanced drilling (UBD) is undoubtedly one of the "hottest" topics in the oilfield today. Although not a new concept, UBD has just recently come of age, as the benefits it offers to the oil and gas industry have been noted only within the last few years. Underbalanced drilling offers many notable advantages, which include: Reducing formation damageIncreasing the rate of penetration (ROP) and bit life.Allowing the reservoir to be tested and evaluated while drilling.Reducing the number of trips into the holeMinimizing differential sticking of pipeLimiting lost circulationFacilitating early production while drillingAccessing depleted or low-pressure reservoirsSelecting TD from inflow performance.

The benefits of the above are obvious; therefore, they will not be discussed in depth in this paper.

While UBD technology has come a long way since the early wells that were brought in via gushers that rose above the wooden derricks, underbalanced drilling can only supply part of the solution – once drilling procedures are concluded, and the completion phase begins; the primary operational drivers change. Rather than focusing on such activities as drilling performance and formation evaluation while drilling, the completion drivers target the reduction of fluid loss and the elimination of formation damage. Thus, attaining a total solution requires that underbalanced conditions not only are maintained during the completion and for the life of the well, but also throughout any future well interventions. Unfortunately, the advances in underbalanced completion technology have lagged behind those seen in underbalanced drilling.

This paper will explore the strategies, techniques and tool systems required 1) to maintain an underbalanced condition throughout the initial well completion phase and during all future remedial operations, and 2), to create a cost-effective solution that will enhance and accelerate maximum reservoir drainage.

To this end, if underbalanced technology is approached as a production enhancement technique that starts at the initial stage of drilling the well and continues throughout the life of the well, the end result will be that the value of the reservoir will be increased, and will be collected within in a shorter period of time.
Design, Interpretation, and Assessment of Short-Term Pressure-Transient Tests
Authors: Soliman M. Y. , Azari M. , Ansah J. , Kabir C. S.
Published: December 2007

In order to meet most test objectives, conventional transient well testing usually requires long flow and shut-in periods. However, the current industry drivers demand short, cost-effective, and environmentally friendly test procedures, especially in exploration wells. This is particularly true in deepwater and arctic environments where conventional tests may be prohibitively expensive or logistically not feasible.

While various short-term tests, test procedures, and interpretation methods are available for conducting successful short-term tests, clarity is lacking for specific applications of these methods. Some of these tests include surge testing, closed-chamber testing, slug testing, underbalanced perforating and testing, and back-surge perforation cleaning. This paper provides comprehensive evaluation of general closed-chamber tests, including general surge tests, and their comparison with special tests such as, FasTest,™ Impulse™ test, and slug tests. For each of these techniques, the review will examine: Test design, testing procedureTheoretical background of each of these techniquesMethod of data analysis including comparison based on both theoretical and practical considerations to determine the expected reliability, accuracy, and ease of analysis.

A large portion of the paper will be devoted to field examples. Several actual case studies are analyzed using the various techniques, and results are tabulated and presented. The analyses of several of these examples will be presented in significantly more detail to compare techniques available to analyze the well-testing data obtained from surge testing, closed-chamber DST, slug testing of oil wells, underbalanced perforating and testing, and back-surge perforation cleaning.