bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Oil Recovery from Carbonate Reservoirs by Chemical Stimulation
Authors: Xie X. , Weiss W. W. , Tong Z. , Morrow N. R.
Published: December 2007

Oil reserves from shallow-shelf carbonate reservoirs account for 22% of the original oil in place (OOIP) of the entire U.S. oil resource. Many of these reservoirs are naturally fractured. A pressure pulsing technique is often used in fractured fields to improve oil recovery. In some situations, imbibition of water can be promoted by chemical stimulation to alter the reservoir wettability towards water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Class II shallow shelf carbonate reservoirs typically produce less than 10% OOIP during primary recovery and respond poorly to water injection.

In this work, promotion of imbibition was determined for a cationic surfactant, cocoalkyltrimethyl ammonium chloride, and a nonionic surfactant, an ethoxylated alcohol. Cores from three dolomitic Class II reservoirs, Cottonwood Creek, Dagger Draw, and Lustre, were used in the laboratory tests. After preparing core samples using the corresponding reservoir crude oil and brine, spontaneous expulsion of oil was measured in glass imbibition cells at elevated temperature for over 50 core samples. When reservoir brine was used as the imbibition fluid, oil recovery was in the range of 0 - 35% OOIP. After imbibition of reservoir brine had ceased, the cores were transferred into surfactant solutions at or somewhat above the critical micelle concentration to test for enhanced recovery by further imbibition. Typically, immersion in the surfactant solution resulted in additional recovery of 5 to 10% OOIP. The increased recovery is mainly ascribed to increased water wetness. The effect of acidization prior to surfactant treatment was also tested and found to be detrimental to oil recovery.
Theoretical Development of the Brooks-Corey Capillary Pressure Model from Fractal Modeling of Porous Media
Authors: Li Kewen
Published: December 2007

The capillary pressure model proposed empirically by Brooks and Corey has been used widely for several decades. However it is not clear why the Brooks-Corey capillary pressure model works so well. In this study, it has been found that the empirical Brooks-Corey capillary pressure model can be derived theoretically from fractal modeling of porous media. Also found was the correlation between the pore size distribution index in the Brooks-Corey capillary pressure model and the fractal dimension. The pore size distribution index increases with the decrease in fractal dimension of the porous media. Capillary pressure curves of different types of rock samples were measured using a mercury intrusion technique. The values of pore size distribution index and fractal dimension were calculated. The relationship between the two parameters obtained from the experimental data was consistent with the relationship derived theoretically. This implies that the fractal dimension of porous media may be inferred directly using the Brooks-Corey capillary pressure model instead of the fractal model. The theoretical development in this study demonstrates that the Brooks-Corey capillary pressure model, once considered as empirical, has a solid theoretical base. This may be why the Brooks-Corey capillary pressure model works satisfactorily in many cases.
Pre-Darcy Flow: A Missing Piece of the Improved Oil Recovery Puzzle?
Authors: Longmuir Gavin
Published: December 2007

Does Darcy’s Law apply at the very low fluid velocities typical for petroleum reservoirs? There is a body of experimental evidence, primarily from non-petroleum disciplines, demonstrating departures from Darcy’s Law at low fluid velocities – Pre-Darcy flow. If Pre-Darcy behavior occurs in oil & gas reservoirs, there could be substantial currently-unrecognized opportunities for increasing the economic recovery of hydrocarbons.
The Use of Turbodrills in Coiled Tubing Applications
Authors: Beaton Tim , Seale Rocky
Published: December 2007

Proposal

Coiled tubing (CT) has evolved in recent years to include more complex applications in drilling and remedial work. As wellbores have extended deeper, the challenges of intervening with CT have increased. For years the limitation in CT work was the coiled tubing itself. However, with advancements in metallurgy and manufacturing processes, the applications where CT can be utilized have expanded to include deeper, hotter, and more complex wellbores. The challenges of performing this work have now been directed at providing reliable equipment.

One of the main challenges in these more hostile environments is temperature. At elevated temperatures, work performed with motors becomes very erratic and unreliable. To perform this work, alternate methods have to be analyzed. One solution is the use of downhole turbines or turbodrills. Turbodrills have been used in the drilling industry for decades. It is only recently, however, that the benefits derived by turbodrills have been applied to CT for drilling and workover operations. With the remedial work CT is now required to perform, turbodrills are a natural fit as they address the issues which limit motor performance. This paper analyzes the applications and developments in turbodrills with analysis of recent runs on CT.
A New Generation Chemical Flooding Simulator
Authors: John A. , Han C. , Delshad M. , Pope G. A. , Sepehrnoori K.
Published: December 2007

Compositional reservoir simulators that are based on equation of state (EOS) formulations typically do not handle the modeling of aqeuous phase behavior and those that are designed for modeling chemical processes typically assume simplified hydrocarbon phase behavior. There is a need to have a single reservoir simulator capable of combining both approaches to benefit from the advantages of both aqueous and hydrocarbons models. Developing and implementing fully implicit procedures for modeling both hydrocarbon and aqueous phase behavior simultaneously is a complex process. An approach to integrate a surfactant phase behavior model into an existing fully implicit, parallel, equation of state compositional simulator is presented in this paper. Physical property models describing the flow and transport of surfactant and polymer species have been implemented. These properties include surfactant phase behavior, interfacial tension, capillary desaturation, viscosity, adsorption, and relative permeability as a function of trapping number. Polymer properties include viscosity, permeability reduction, inaccessible pore volume, and adsorption. The simulation results were validated by comparison with analytical solutions and results from the explicit chemical flooding simulator, UTCHEM. Test runs were performed with high-resolution models in a parallel environment with results indicating a good scalability of the simulator.
Analytical Theory for Three-Phase Partially Miscible Flow in Ternary Systems
Authors: LaForce Tara , Johns Russell T.
Published: December 2007

Three-phase flow often occurs in reservoirs, particularly during secondary or tertiary oil recovery. There is significant mutual solubility of components in the phases for near miscible gas floods or chemical floods. Unfortunately there is insufficient understanding of how three partially miscible phases can affect flow. Furthermore, there are currently no benchmark analytical solutions available to validate numerical simulations for this complex flow regime.

In this research, compositional solution routes are developed by the method of characteristics (MOC) for one-dimensional, dispersion-free flow where up to three partially miscible flowing phases may be present. The method is applied to a water/alcohol/oil system that exhibits a large three-phase region in laboratory experiments. Unique solutions are found based on continuity arguments, shock-jump conditions, entropy constraints, and velocity constraints. The analytical solutions are compared to fine-grid finite-difference simulations to verify that they converge to the same dispersion-free limit.

The results show that within the three-phase region one phase is below its residual saturation so that only two phases are flowing. As miscibility is approached, cumulative oil recovery initially declines because of the development of constant states in the solution, which cause the leading shock to speed up. We show that multi-contact miscibility is developed along the boundary of the three-phase region where all shocks and waves flow at a dimensionless velocity of one. Last, we show that injectivity (or inverse flow resistance) changes by a factor of two over the range of injection compositions considered for the specific relative permeabilities used.
Fast History Matching of Finite-Difference Models Using Streamline-Derived Sensitivities
Authors: Cheng Hao , Kharghoria Arun , He Zhong , Datta-Gupta Akhil
Published: December 2007

We propose a novel approach to history matching finite-difference models that combines the advantage of the streamline models with the versatility of finite-difference simulation. Current streamline models are limited in their ability to incorporate complex physical processes and cross-streamline mechanisms in a computationally efficient manner. A unique feature of streamline models is their ability to efficiently compute the sensitivity of the production data with respect to reservoir parameters using a single flow simulation. These sensitivities define the relationship between changes in production response because of small changes in reservoir parameters and thus, form the basis for many history matching algorithms. In our approach, we utilize the streamline-derived sensitivities to facilitate history matching during finite-difference simulation. First, the velocity field from the finite-difference model is used to compute streamline trajectories, time of flight and parameter sensitivities. The sensitivities are then utilized in an inversion algorithm to update the reservoir model during finite-difference simulation.

The use of finite-difference model allows us to account for detailed process physics and compressibility effects. Although the streamline-derived sensitivities are only approximate, they do not seem to noticeably impact the quality of the match or efficiency of the approach. For history matching, we use ‘a generalized travel-time inversion’ that is shown to be extremely robust because of its quasi-linear properties and converges in only a few iterations. The approach is very fast and avoids much of the subjective judgments and time-consuming trial-and-errors associated with manual history matching. We demonstrate the power and utility of our approach using a synthetic example and two field examples. The first one is from a CO2 pilot area in the Goldsmith San Andreas Unit, a dolomite formation in west Texas with over 20 years of waterflood production history. The second example is from a giant middle-eastern reservoir and involves history matching a multimillion cell geologic model with 16 injectors and 70 producers. The final model preserved all of the prior geologic constraints while matching 30 years of production history.
Enhanced Oil Recovery by In-Situ Combustion Process in Santhal Field of Cambay Basin, Mehsana, Gujarat, India – A Case Study
Authors: Chattopadhyay S. K. , Ram Binay , Bhattacharya R. N. , Das T. K.
Published: December 2007

Proposal

In-Situ Combustion Process has been implemented in Santhal field in commercial scale for the last 6 years for enhancing the recovery of heavy oil. The process monitoring is the key factor for ensuring the effectiveness of the method. This paper describes the field practices of ignition well preparation, sampling and analysis strategy of produced fluids coupled with well head pressure, temperature for effective monitoring. The effectiveness of the process is evident from the enhancement of net oil production from the field.
Preformed Particle Gel for Conformance Control: Transport Mechanism Through Porous Media
Authors: Bai Baojun , Liu Yuzhang , Coste J-P , Li Liangxiong
Published: December 2007

Preformed particle gel (PG) has been successfully synthesized and applied to control excess water production in some mature water-flooded oilfields in China. Investigations show that PG is strength- and size-controlled, environment-friendly, stable over long periods of time, and very likely capable of overcoming some drawbacks inherent in gel treatments based on in-situ gelling. Its thermostabilization is not sensitive to reservoirs minerals and formation water salinity. To support its future applications, this paper describes experiments that investigate the mechanisms for PG propagation through porous media.

Visual observations in etched-glass micro-models demonstrate that PG propagation exhibits six patterns of behavior: direct pass, adsorption and retention, deform and pass, snap-off and pass, shrink and pass, and trap. Which pattern is dominant is related to the diameter ratio of swollen PG and pore throat, PG strength and the driving force.

In macroscopic scale, PG propagation through porous media can be described by three patterns: pass, broken and pass, and plug. Which kind of pattern is dominant can be determined by pressure change with time at different tap, particle size of effluent and residual resistance factor at different segment of a core.

Measurements from core-flooding and micro-model experiments show that a swollen PG particle can pass through a pore throat whose diameter is smaller than its diameter due to the elasticity and deformability of swollen PG. PG strength is a principle parameter to determine the diameter ratio of a PG particle and a pore throat that PG can pass through a porous medium.

A PG particle can move through a porous medium only if a driving pressure gradient is higher than a threshold pressure gradient. The threshold pressure depends on PG strength, the diameter ratio of particle and average pore size.

Further work will investigate the potential for PG to improve oil recovery and the optimization method to design PG treatments.
Simulation of a Sector Model of the Heavy Oil Thermal Recovery
Authors: Eremenko E. , Kochanova S. , Kourenko M. , Perevozchikov S.
Published: December 2007

In Russia, development of fields with difficult-to-recover oil reserves, especially heavy-oil fields, becomes a high-priority task. Heavy-oil fields requiring thermal stimulation are of that class. Many of such fields have deep reservoirs (occurring deeper then 1000 m). This paper describes the study of a sector of one of such fields. It is one of the biggest heavy-oil fields in Russia and is being developed during last 20 years. About 900 wells are running. The in-situ oil viscosity is 150 cP. In the oilfield’s life, many thermal technologies have been used in different sectors of the field (including combinations of huff-and-puff, cycling process, continuous injection of hot water or steam). The field sector with 71 wells was chosen to resolve the problem of current OIP distribution and to evaluate the efficiency of the applied technology. The development uses cycling thermal injection(hot water or steam injection followed up by cold water injection) in the sector. Dynamic simulation was performed., the model was matched to the production history of the last 20 years. An appropriate technology for further development of the sector was selected.
Formation Damage in Gas Sandstone Formations by High-temperature Borate Gels Due to Long Term Shut-in Periods
Authors: Siddiqui M. A. , Nasr-El-Din H. A. , Al-Anazi M. S. , Bartko K. M.
Published: December 2007

Description of the Paper: The U-A reservoir unit is an eolian deposition where the primary facies are dune deposits. These sands are composed of quartz grains with feldspars. These grains are large in diameters and coated with illite clays, which made the formation sand friable. These sands require sand control and one of the techniques applied is to frac-pack the wells. The usual practice is to clean up the well as soon as possible to minimize formation damage. This process can take up to seven days, which results in frac fluid being le ft in the formation. This paper examines the effect of shut-in times following hydraulic fracturing treatments on the return permeability of the reservoir core.

Lab studies included conducting coreflood experiments using reservoir cores and typical treatment fluids. The study was performed at bottomhole conditions (300°F) using cores with air permeabilities ranging from 25 mD to 28D. Polymer and breaker concentrations in the fracturing fluid were identical to those used in the field. Core plugs were tested by both methods: injecting and circulating the fracturing gel, and soaking it under pressure for up to seven days. Tests were performed in the absence and presence of a breaker, unencapsulated sodium bromate.

Application: Guar gum and its derivatives are commonly used to prepare hydraulic fracturing fluids. During fracturing treatments, the polymer invades the formation and leaves a gel residue in the fracture and formation, which impairs well deliverability. Several factors like polymer loading, formation temperature, shut-in time and clean-up process contribute to the treatment outcome. A common belief (misconception) has been that long shut-in periods after fracturing a gas well will further reduce the permeability, and the impairment of delivery becomes severe. To avoid the resulting damage of the well, the treatment fluids are recovered while the rig on location, which costs rig time. This concept has led us to study the impact of shut-in time on the retained permeability of reservoir cores.

Results, Observations, Conclusions: Experimental results reveal that 25% reduction in the permeability of reservoir cores occurs at a polymer loading of 45 lb/1,000 gals. A lower polymer loading of 35 lb/1000 gals caused less damage to the permeability. Most of the damage occurred during the first few hours of interaction of the gel with the core plug. Longer shut-in times did not cause additional damage. This study resulted in a significant cost savings by avoiding the need to flowback the well with the rig on location.

Technical Contributions: Guar gum polymer used in hydraulic fracturing treatment can cause damage up to 25%. The damage occurred once the fracturing gel invades the formation. Longer shut-in times don’t cause additional damage up to seven days. The degree of damage depends on the breaker concentration.
The Perfect Permeability Transform Using Logs and Cores
Authors: Haro Carlos F.
Published: December 2007

A systematic method is proposed to better understand the relation between permeability, porosity, saturation, and clay content, to get representative permeability distributions as part of reservoir characterization.

This method utilizes the combination of a well-recognized permeability-porosity relationship and the Archie equation, as a predictive link between cores and well logs. This approach mathematically bonds the hydraulic (dynamic) and geometric (static) properties of the rocks. Permeability and rock types from well logs are obtained by careful theoretical and practical selection of parameters. The methodology converts a multidimensional correlation problem into sets of smaller correlations.

The procedure leads to a system of simultaneous equations, where the slope of one of the linear equations constitutes an exact calibration parameter between permeability and saturation. The equations allow a sequential transformation process from permeability-saturation, to permeability-porosity, and rock type-depth coordinates. The equations are solved for rock types, using reference grids constructed in all three coordinate systems. A calibration/diagnostic crossplot (slope-rock type) enables to find permeability, assess the integrity of the model, identify outliers, and perform consistency checks at different depths.

The practical implementation consists of transform tables, and correlations. Results can be extended to shaly sections, transition zones, and swept intervals. Some examples are presented using data from diverse reservoir classes.

Advantages:

Calculates permeability honoring and integrating conventional core analysis, capillary pressure, and logs Requires log curves generally available in every well Quantitative in uncored sections Follows a deterministic method, so results can be easily extrapolated to uncored wells. No black box approach Based on well-documented engineering and geological theory (flow zones, rock fabric, pore geometry). Formulation permits a connection to the geology through rock fabrics, for interwell extrapolation.

Previous models lack a good nexus between cores and well logs. Neural networks, fuzzy logic, multiple regression, or a combination of statistical methods establish this connection, usually with difficulty and not very effectively. The creation of an effective direct link and accuracy are some of the strengths of the proposed procedure.
An Improved Prediction of Coiled-Tubing Lockup Length
Authors: Adnan Sarmad , Chen Y. C.
Published: December 2007

In both deviated and vertical wells, coiled tubing takes a helical shape. The conventional approach to describing coiled tubing constrained inside a wellbore relies upon the relationship between the axial force and the helical pitch. However, in the field and in experiments, it is hard to measure accurately the helical pitch for very long tubing. Instead, the tubing operators collect data on the force and shortening of coiled tubing in the axial direction of wells. This paper transforms the classical expression for coiled-tubing deformation into an alternative form that relates the axial force to the axial shortening of the tubing. The new model is consistent with experimental data from several previous studies. Moreover, through this new model, a simple technique is developed to predict the lockup length of the coiled tubing resulting from friction. This leads to an improved prediction of lockup length for coiled tubing, allowing more accurate modeling of downhole depth.
Coiled Tubing in Sour Environments - Theory and Practice
Authors: Crabtree A. R. , Gavin W.
Published: December 2007

Carbon steel Coiled Tubing strings have been used in sour wellbore environments for many years. The use of Coiled Tubing in sour service has increased by job number, job complexity, pipe size and the stresses to which the pipe is subjected. A number of papers have been written on the steel chemistry and low cycle fatigue behaviour. These have been based on both theoretical and laboratory work. Great progress has been made in understanding the chemical and physical interaction of Coiled Tubing and hydrogen sulfide but little information is available from "real world" situations where the pipe has been worked in a variety of job types (acidising, gas lifting, drilling, etc) and where a large number of other factors may come into play (injector damage, well stimulation chemicals, sour inhibitor application techniques, erosion of inhibitors, CO2, high chloride water production, etc).

This paper will discuss the application of a Coiled Tubing technical specification (based on theoretical and laboratory work) in the operational world. Comparisons will be made between theoretical expectation and practical observation for 70 and 80 grade Coiled Tubing with regard to low cycle fatigue, pipe life and damage in sour environments.
Utilizing Innovative Flexible Sealant Technology in Rigless Plug and Abandonment
Authors: Barclay Ian S. , Johnson Carl R. , Staal Timo W. , Choudhary Suresh , Al-Hamandani Abdulhameed
Published: December 2007

This paper presents Petroleum Development of Oman's (PDO's) rigless plug and abandonment (P&A) technologies and practices resulting from a corporate goal to find a costeffective means to abandon its oil wells. PDO is abandoning aging wells and must balance environmental and financial objectives. Technically sound abandonment practices are essential for long-term environmental protection. Many operators are revising procedures to ensure that depleted reservoirs remain permanently sealed. During a 60-well pilot project in Oman, PDO optimized its practices by employing new cementing and plugging technologies to minimize the cost of abandonment while ensuring long-term environmental protection from once-prolific oil wells.

PDO used a new expanding, flexible sealant system on the P&A project, conveying the flexible sealant with a coiled tubing (CT) unit. The new sealant has improved elastic and expansion properties to meet PDO's requirement for a longterm mechanical durability and zonal isolation. The presence of expanding material leads to an optimum configuration to prevent loss of zonal isolation resulting from changes in downhole conditions over time. The presence of flexible and expanding materials increases the elasticity and decreases compressibility and permeability of the set cement while retaining good compressive strength.

Use of a CT unit eliminated the need for a rig, which reduced the time and cost of operations. The novel flexible sealant system provided the long-term isolation necessary to meet environmental standards. This paper presents case histories on the use of this new flexible, expanding sealant and its influence on the P&A project.
Case Histories of Wellbore Cleanouts Using Near-Neutral Derusting Solution
Authors: Berry S. L. , Boles J. L.
Published: December 2007

Deposition of iron oxidation products, pipe dope and hydrocarbons on the metallic surfaces associated with wells can become significant. Whether the iron compounds come from the producing environment, from mill scale on a new tubing string, or from exposure to the elements during storage of a work string, their presence creates the potential for formation damage if they are dislodged and carried into the reservoir with treating fluids. Acid stimulation treatments, frac packs and gravel packs are reservoir interventions where this transportation of deposits could occur. Traditionally, an acid pickle treatment is performed prior to such treatments to remove the potential contaminants.

Acid pickling, while being effective, presents significant problems with safety, the environment and disposal of acidic fluids that return to the surface only partially spent. An alternative solution has been found using a near-neutral pH fluid to remove iron oxidation products and provide passivation of treated metallic surfaces. The safer acid level of this fluid provides a solution to both the downhole problems and the surface health, safety and environmental issues. Extensive laboratory testing has established the effectiveness of the fluid to removes not only iron oxidation products but also pipe dope and hydrocarbon deposits when used in conjunction with an environmentally friendly solvent. Performance is equal to traditional acidic fluids. Testing also demonstrated that metallic surfaces retained passivity.

This new fluid has now been used in several hundred wells in both the United States and South America. This paper will outline the laboratory results defining its capabilities compared to traditional hydrochloric acid systems. Case histories of usage in the United States and South America for the pre-treatment of downhole tubulars to remove contaminants are presented. The special case history of application to remove oxidation scale in a subsea fuel gas line system off the coast of Brazil is also discussed.
Drag Reduction by Particle Addition in Gas Flows
Authors: Kaminsky Robert D. , Robinson Chris M. , Talley Larry D.
Published: December 2007

The impact of spherical, flake, and fiber microparticle addition on frictional pressure loss in turbulent gas flows was experimentally investigated. Pressures up to 6.6 MPa (955 psig) were studied. Drag reduction (i.e., reduced frictional pressure loss) was clearly observed only at high dosages of >0.01 gsolid/cm3gas,actual. A "lubrication" effect though was evident at lower dosages where relatively minor drag increases occurred despite significant solid loadings. No trends in drag reduction were observed based on Reynolds number or pressure. Larger particles tended to increase frictional losses, especially at moderate dosages.
Interpreting Transient Tests in High-Permeability, Gas-Condensate Reservoirs
Authors: Kabir C. S. , Landa J. L.
Published: December 2007

In gas-condensate reservoirs, interpretation of static and dynamic skin is fraught with uncertainties when analysis is attempted with simple analytic tools. Problems compound when two-phase flow occurs owing to large drawdowns with flowing pressures dipping below the dewpoint pressure. Under this circumstance, static and dynamic skin values are difficult to separate using a single-phase analog.

This paper deals with issues surrounding transient-test interpretation when no discernible condensate bank forms in the well vicinity owing to low drawdown in high-kh reservoirs and low-condensate yields. In particular, we explore why skin values obtained by a single-phase analog cannot be mapped directly onto a two-phase numeric model.

Some of the key findings suggest that both components of skin are significantly lower when evaluated with a numeric model as opposed to its analytic counterpart. In gas-condensate systems, we recommend the use of a numeric model because of its superior ability to handle physics of flow. This is particularly so when long-term performance evaluation is sought.
Simplified Wellbore Flow Modeling in Gas-Condensate Systems
Authors: Kabir C. S. , Hasan A. R.
Published: December 2007

Predicting long-term reservoir performance with realistic wellbore models is fraught with uncertainty owing to the complexity of two-phase flow. That is because even a calibrated two-phase flow model departs from its expected performance trend when changes in flow conditions occur. These inevitable changes include gas/liquid ratio, wellhead pressure, and flowline pressure with time, among others. Influx of water further exacerbates the prediction problem.

This study explores the possibility of using simplified approaches to computing bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates, gravity of producing fluids, and tubular dimensions. BHP computations on three independent data sets comprising 167 gas-condensate well tests suggest that the no-slip homogeneous model applies quite well. Statistical results show that the homogeneous model compares quite favorably with mechanistic two-phase flow models. However, the main advantage of the simplified model is that its recalibration with field data is not required because the gas/oil ratio increases with time, thereby making the model more robust.

Most field datasets suggest random error in BHP calculations; uncertainty in rate measurements appears to be the most probable cause. High-GLR systems can tolerate large errors in rate measurements, but low-GLR wells demand greater accuracy.
Two-Phase Flow Upscaling for Flow in Thin Beds and Implications for Data Acquisition
Authors: Kasap E.
Published: December 2007

Producing from less prolific reservoirs is becoming more feasible because technology is becoming less costly and more robust in detecting and characterizing thinly bedded formations. Some of these reservoirs contain beds having thicknesses on the scale of several inches. Without upscaling, numerical models for field studies with grid block thicknesses on the order of thin-bed dimensions cannot be run. Even with 1% laminations in a medium-sized reservoir, more than two billion grid blocks are required to describe the reservoir heterogeneity. Developing representative multiphase flow parameters such as relative permeability, capillary pressure, and gravity functions for grids used in a field study poses upscaling challenges.

In this study, a sample thin-bed dataset was used to develop proper upscaling techniques for single-phase and multiphase flow conditions to be used in a field study. A near-wellbore simulation model was built, with which fine-scale numerical simulations were conducted and pseudofunctions as apparent relative permeabilities were generated for a sample thinly bedded formation. Several boundary conditions such as near-wellbore radial flow, linear flow, aquifer full-face connection, and aquifer line connection were studied. Back-calculated pseudofunctions were put into representative coarse-scale models to test if they reproduce the original flow responses. Analytical pseudofunctions were also calculated and compared with the numerical pseudofunctions.

From the results of this study we concluded that the back-calculated pseudofunctions from numerical simulations would reproduce fine-scale results for relatively continuous thin beds. Analytical pseudofunctions could robustly reproduce the fine-scale results with significantly less development effort compared to that needed to develop numerical pseudofunctions; however, analytical pseudofunctions can only be applied in simple depositional systems with simple boundary conditions.
Assessing Borehole-Position Uncertainty From Real-Time Measurements in an Earth Model
Authors: Prange Michael D. , Tilke Peter G. , Kaufman Peter S.
Published: December 2007

There has been much interest in improving uncertainty estimates of borehole position. Such estimates are useful in estimating the probability of intersecting a reservoir target, in estimating the probability of colliding with an adjacent borehole, and in avoiding high-risk zones. We describe here a new geometrical model for borehole-position uncertainty that encompasses both systematic and random errors in the borehole-position survey. Furthermore we present a new technology that refines the borehole-uncertainty estimate in real time during the drilling of the well through the use of logging-while-drilling (LWD) measurements (e.g., measurements of formation depth, dip, and azimuth from image logs). This technology uses a Bayesian formulation to update the uncertainty of both the borehole trajectory and the earth model to be consistent with these measurements. The final uncertainty model couples borehole uncertainty with earth-model uncertainty. We use a geosteering field example to demonstrate how both earth-model and borehole-trajectory uncertainties are reduced through this use of real-time measurements.
Cleanup of Water Blocks in Depleted Low-Permeability Reservoirs
Authors: Parekh Bimal , Sharma Mukul M.
Published: December 2007

Poor gas inflow performance is observed in some depleted, low permeability, reservoirs after completion and workover operations. The use of aqueous treatment fluids often results in a 'water block' due to poor recovery of the fluids that have leaked-off. This curtails well deliverability due to reduced relative permeability to gas/oil in the invaded region.

This study analyzes the effect of various factors governing the cleanup of water blocks in fractured and unfractured wells for both gas and oil reservoirs. The effects of drawdown, capillary pressure, relative permeability, and heterogeneity as well as the influence of fracture geometry on well deliverability following some well operations, such as fracturing, have been examined by detailed simulations.

Drawdown, fracture length and shapes of relative permeability curves strongly affect the recovery in productivity. On the other hand, end point relative permeabilities and horizontal well length have an insignificant impact on cleanup. Higher vertical permeabilities favor early recovery of well productivity in 'high perm' layers and delay cleanup of water blocks in 'low perm' layers.

The results suggest the need to lower capillary pressure by reducing interfacial tension and/or altering wettability of the rock surface from strongly water-wet to intermediate-wet. With the correct selection of treatment fluids, proper design of fracture geometry and optimum drawdown applied it is possible to cleanup water blocks more rapidly in depleted low-permeability reservoirs.
Petrozuata - An Application of Multiphase Metering Technology
Authors: Bortolin Luigi , Mehdizadeh Parviz , Stobie Gordon
Published: December 2007

The application of Multiphase Meters (MPM) over the past decade or so has, in the main, been in deployment of meters in small quantities (i.e. ones and twos) and there are few applications where MPM's have been deployed in bulk. Petrozuata in Venezuela is such an operation where 37 MPM's were deployed and have been in use for over 5 years.

This paper describes the facility and the operations where MPM's have been selected, tested and implemented. The paper also describes the difficulties experienced and the operational results from the extensive use of such measurement techniques.
A New Method for Injectivity Impairment Characterization From Well and Coreflood Data
Authors: da Silva M. , Bedrikovetsky P. , Van den Broek W. M. G. T. , Siqueira A. , Serra A. L.
Published: December 2007

The injector impairment due to suspended particles during waterflood project happens in two stages: firstly particles penetrate into a reservoir and are captured by the rock (deep bed filtration); at the second stage, after the reservoir inlet is plugged by particles, the particles build up a filter cake. Prediction of injectivity decline is based on mathematical modelling of deep bed filtration and filter cake formation. The model parameters are determined from either laboratory tests or field data.

The model parameters for deep bed filtration – the filtration and formation damage coefficients – can be determined from laboratory pressure measurements using so-called 3-point pressure method. The method for determination of the critical porosity fraction, which is necessary for calculation of the time of transition from deep bed filtration to filter cake buildup, is not available in the literature.

In the current paper, the 3-point pressure method was used for determination of the critical porosity fraction. The data from 18 laboratory tests were treated, and the correlation between the formation damage coefficient and the critical porosity fraction was obtained. This correlation allows determining of the deep bed filtration and filter cake buildup parameters from either routine coreflood test or well injectivity history.
Proppant Distribution and Flowback in Off-Balance Hydraulic Fractures
Authors: Daneshy A. Ali
Published: December 2007

The vast majority of industrial hydraulic fractures propagate in off-balance mode, where the fracture is not in a single plane, includes many shear fractures and branches, and is shorter and narrower than computed by existing models. Proppant transport, deposition and flowback in these fractures are also substantially different than for single fractures. Presence of shear fractures leads to formation of many randomly distributed tight proppant packs. Many of these are inherently unstable and serve as sources for proppant flowback. But they are also the source for fracture conductivity. Gravity causes formation of proppant beds. These are usually formed at the lower extremities of the fracture. Branches generally trap the proppant and are unlikely sources for flowback. They also add little to productive capacity of the fracture. And, some of the proppant in the fracture is loosely scattered inside it and is free to move when sufficient drag is exerted by fluid flow.

The paper places special emphasis on proppant flowback and shows that the three requirements for its occurrence are motion initiation, motion maintenance and infinite conductivity along the return path. Gravity plays a very important role in this process, as does well completion. Tendency for equilibrium between reservoir fluid velocity and deposited proppant results in gradual decrease and eventually stoppage of proppant return at any given flow rate. This equilibrium can be disrupted by sudden increases in flow rate which then triggers instability and proppant flowback.

Case histories from actual treatments illustrate and re-enforce the findings of the paper.
Well Orientation Effect on Borehole Stability
Authors: Morita Nobuo
Published: December 2007

Using laboratory and field borehole stability data, an empirical correlation of borehole size and stress gradient effects is derived. Using the correlation, the well orientation effect on borehole stability is numerically studied. The study shows that the borehole stability is controlled, under the normal condition, by the largest in-situ stress in the radial borehole direction so that the borehole orientation effect for a horizontal well is not significant if two horizontal stresses are less than the vertical overburden pressure, however, if one horizontal stress is greater than the vertical stress, the orientation significantly affects the borehole stability.
Depth Control: Reconciliation of LWD and Wireline Depths, Standard Practice and an Alternative Simple but Effective Method
Authors: Wilson H. , Lofts J. C. , Page G. C. , Brooks A. G. , Walder D.
Published: December 2007

Depth is one of the most important formation evaluation measurements, but it is also one of the most difficult to define accurately. LWD measurements, which rely on driller's depth, are becoming more prolific and widely used. Wireline measurements, with their independent determination of depth, are still commonplace, while the use of both wireline and LWD measurements together is still largely unavoidable in a full data acquisition program. Reconciliation of depth, including survey error when converting to TVD's, is still one of the key problems faced when evaluating and fully interpreting these data sets.

This paper reviews the current common practices applied to correction and correlation of depth. Generally, these practices are intended to correct all other measured depths to a single definitive depth reference. The extent to which the intended goal is achieved is assessed. The paper also describes an alternative approach which accepts all depths as valid, but assigns uncertainties to each. A real well is used to compare the outcomes for each approach. One conclusion is that correction of drill pipe depths for stretch effects is desirable, and a simple but effective correction method is described.
Command Skills for Drilling and Completion Teams: Managing the Unexpected
Authors: Crichton Margaret T. , Henderson William G. , Thorogood John L.
Published: December 2007

Many drilling and completion teams plan extensively in the office for the operations ahead. Most engineers now accept that successful implementation of the planned operations, especially the transition from planning to operations, needs effective skills such as leadership, communication and teamwork. What it takes to manage unexpected events successfully, especially under pressures such as time (i.e. cost), uncertainty and difficult inter-personal relationships, has until now been less well understood. Analyses have been carried out of how unexpected events are managed in domains such as rail transport, energy production, and the police, prison, and fire services. These analyses have identified that human errors in managing the event have at times actually worsened the situation. In these domains training for effective command skills (decision making, situation assessment, communication, leadership, teamwork) is recognized as essential. Yet in the drilling and completions environment these skills are seldom identified as important, even for routine operations, and formal training is provided only rarely. Experience in dealing with unexpected events is recognized as a good teacher, but learning by trial and error can ‘send in terrific bills’ in terms of stress effects on decision makers and teams. This paper presents findings of a recent research project commissioned and funded by BP Exploration. The research identified the basic social and cognitive skills necessary for effective functioning in Drilling & Completion teams, and especially the command skills for managing unexpected events under pressure of time, risk and uncertainty. The project also developed a toolkit for team performance assessment and potential training interventions applicable not only to routine operations but also to managing unexpected events under pressure.
On Accurate Tracing of Streamlines
Authors: Matringe S. F. , Gerritsen M. G.
Published: December 2007

Because of their efficiency, streamline methods are increasingly used for, amongst others, flow based upscaling, history matching, optimal well placement, and also compositional simulation, for which they show great potential. The accuracy of the streamline solutions depends on several factors including the quality of the pressure solve, the numerical scheme used to propagate solution components along streamlines, the mappings between streamlines and pressure grid, and naturally, the quality of the streamline tracing algorithm.

Using the homogeneous quarter five spot pattern, for which the exact streamline pattern is known analytically, we show that the errors in streamline location, computed arc length and time of flight can be significant, and can negatively affect the simulation results. The tracing errors are caused by the inaccuracy of the fluxes at the edges of the gridblocks, the choice of streamline launching pattern, and the order of flux interpolation used to compute the velocity field. We have investigated the use of the Mixed Hybrid Finite Element method for solving the pressure field that is known to provide more accurate fluxes, and discuss when this method leads to improved tracing results over the traditional finite difference method. We also show that a judicious choice of launch locations leads to lower tracing errors, and present two new methods to improve streamline tracing within grid cells. The first is an Adaptive-Mesh-Refinement-inspired tracing method that provides more accurate tracing where needed. The second method is a higher order variation on Pollock's tracing that uses a second order interpolation of the velocity field. The method is based on the theory of mixed finite element methods and is therefore easily extendable to any type of grids. Both methods proposed are flux conservative and efficient.
Diagnosis of Horizontal Injectors with Distributed Temperature Sensors
Authors: Bui T. D. , Jalali Y.
Published: December 2007

We present an interpretation methodology for analysis of temperature profiles obtained in horizontal injectors with fiber optic distributed temperature sensors. We consider injection as a non-isothermal process, due to the contrast in the temperature of injected fluid and reservoir fluid. We examine the particular case of water injection in an oil-bearing reservoir and analyze a field case with a notable temperature contrast downhole (222 °F reservoir, 100 °F water). We examine the behavior of the wellbore temperature profile during injection, shut-in, and post-shut-in periods, for both short-term and long-term injection (days to months). We present a methodology for estimation of the injectivity profile along the length of the well during short-term injection, and discuss issues associated with interpretation of long-term data. The proposed methodology can be applied to injection testing of producing wells.