bluuebunny/crossref_metadata_2025 huggingface dataset:
A Study of Water Coning Control in Oil Wells by Injected or Natural FLow Barriers Using Scaled Physical Model and Numerical Simulator
Authors: Siddiqi Sarmad S , Wojtanowicz Andrew K.
Published: December 2007

A scaled physical model (radial sand pack) and a numerical simulator were used in this study to investigate the time-dependent development and dynamic shape of the water-oil interface around the well producing from a bottom-water-drive reservoir. The water cone development was then related to the monitored changes in oil production water-cut. Also observed was the effect of well completions (single or dual-with the bottom water drainage) on water coning in three different reservoir settings. The first was a homogeneous reservoir and was studied as a base case. The second scenario was an impermeable barrier injected around the well bore at the oil water contact (OWC). In the third setting natural heterogeneity was created comprising a low-permeability layer at OWC across the whole drainage area.

The study revealed that in the homogenous reservoir, using dual completion, it was possible to decrease water-cut in the oil production by draining water from the bottom completion and producing oil from the top completion. It was also established that the radial sand pack could be used to demonstrate visually the dynamic change in OWC with time.

The study showed that placing a man-made impermeable barrier around the well bore would not stop the water cone from forming. Water would simply flow around the barrier. Moreover if such natural barriers exist around the well, using dual completions for water control would not be effective.

It was also found out that the presence of a continuous low permeability layer across the reservoir would merely delay the development of water problem without eliminating it. Water breakthrough will be postponed and the water-cut will be reduced. It was also observed that the low permeability layer affects the shape of the cone in such a way as to increase the size of the base and make the tip of the cone narrow.

With increasing use of "smart completions" and injected barriers to control water coning, this study visually illustrates the limitations of these technologies. The results could help in selecting methods for specific reservoir conditions.
Improving Stochastic Evaluations Using Objective Data Analysis and Expert Interviewing Techniques
Authors: Hawkins J. T. , Coopersmith E. M. , Cunningham P. C.
Published: December 2007

Probabilistic treatment of parameters in economic analysis has become widespread in the petroleum industry. Methods consist of either Monte Carlo simulation or approximations of full stochastic distributions for use with decision tree analysis of varying complexity. Unfortunately, however, although many agree that proper quantification of uncertainties is critical for stochastic evaluation of project economics, post audits indicate the description of key variables to be suboptimal.

Studies across multiple industries confirm that it is more common for actual parameters used in project economics to fall outside of their predicted ranges, than inside. Many suggest this to be due to both motivational and cognitive biases – repeatedly resulting in commonly stated ranges, which are too narrow.

The authors contend that narrow, or sub optimal, variable ranges often result from a lack of use, or misuse, of available data and methodology to counteract inherent bias. In exploration prospect and play valuation, where lack of direct data is an issue, analogous data may be used, but may not be well understood, or well thought through as to how well it represents the prospects and plays the practitioner is attempting to describe. In fact, in the absence of data, many use distributions not commonly found in nature.

Hence, it is the goal of this paper to present a heuristic overview of subsurface parameter distributions for commonly used properties in stochastic economic analysis, and describe an expert interviewing methodology to improve variable descriptions. The authors propose that it is the combination of both relevant objective data and quantification of subjective uncertainty that will improve variable descriptions.

This paper presents the results of a survey of some of the exploration/production areas in North America, along with the distributions encountered and properties of those distributions, from empirical data. Examples are from the Gulf of Mexico (GOM), Permian Basin, and the Western Canadian Sedimentary Basin, with a view to gain insight into the distributions and trends of the properties of key subsurface variables.

In addition, this paper presents the probability method to achieve better descriptions of variables. The authors suggest that although several subjective uncertainty assessment methods exist, the probability method is preferred due to its ability to counteract biases. This paper describes the steps of the probability method for range variable assessment, and explains the tools and rationale for each step.
Sums and Products of Distributions: Rules of Thumb and Applications
Authors: Murtha James A.
Published: December 2007

When n probability distributions are added, the Central Limit Theorem provides estimates of the mean and standard deviation of the result. One useful consequence is that the relative uncertainty as measured by the coefficient of variation – the ratio of standard deviation to mean-shrinks by a factor of roughly n. What can be said about the mean and standard deviation of a product of distributions? Both sum and product formulas abound in the oil and gas business. While Monte Carlo simulation generates the appropriate output distribution, some rules of thumb are useful in advance.
Decision-Making Process for a Deepwater Production System Considering Environmental, Technological and Financial Risks
Authors: Castro G. T. , Morooka C. K. , Bordalo S. N.
Published: December 2007

The development of petroleum production systems has become more and more sophisticated due to the complexity of deepwater oilfields, requiring cost effective and environment friendly systems.

Petroleum companies generally employ methods of decision that consider the economic indicators solely, the net present value and the internal rate of return, among others. However, other non-economic aspects must also be analyzed during the evaluation of an E&P enterprise.

The present work presents a model for decision-making that takes into account the main goals of a company, through the use of the theory of utility functions and multiple attributes.

Besides introducing the mathematical theory behind the proposed model, this work illustrates its application via a current example: a deepwater field with a production potential of 100.000 barrels per day, where the facilities alternatives are a Semisubmersible Platform (SS), a Floating Production System and Offloading (FPSO) and a Tension Leg Platform (TLP).

The case study was framed in terms of the technical risks of the project. The selection of the best option considered the financial risk, the environmental risk, the safety risk and the technological risk.

The results suggest that the best alternative is not always the one exhibiting the best economic indicators.
Advanced Openhole Completions Utilizing a Simplified Zone Isolation System
Authors: Coronado Martin P. , Bjørkesett Halvard , Jiral Dennis G. , Førdedal Harald
Published: December 2007

As openhole completions become increasingly more complex, the need to create annular zone isolation within the borehole becomes critical for effective production or injection. Intelligent completions using gravel packs and stand-alone screens across the payzone are becoming a reality, with positive zone isolation a necessity. Historically, creating zone isolation within openhole completions has required a relatively complicated process, utilizing External Casing Packers (ECPs) that must be inflated during the completion installation. As long-term applications require cement inflation to minimize adverse effects on the packer, the installation process is further complicated, especially in highly deviated and horizontal wellbores.

Utilizing the latest packer construction and materials technology, a non-inflatable openhole packer system has been developed which simplifies the installation operation and creates a positive annular seal, even in non-circular wellbores, while reducing overall risk to the operator. Composite material fabrication allows the mechanical packing element of the packer to expand and seal in irregular-shaped holes (washouts), which have proven difficult to effectively seal using conventional technology. The packer has been designed with a hydrostatic pressure driven setting mechanism, allowing one-trip installations utilizing a shifting tool run on the bottom of the inner workstring. Used in conjunction with other emerging technologies, this new zonal isolation system is compatible with horizontal gravel packing operations, allowing the packers to be expanded against the borehole wall after the gravel pack is displaced.

This paper will describe the collaborative effort between a key North Sea operator and major service company in developing a simplified and reliable method to create openhole zone isolation. The packer and system design process will be reviewed along with a discussion of the verification-testing program used to validate the design. A summary of actual field applications employing this new system will also be presented, along with technical and operational comparisons to traditional isolation methods.
Integrating Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale
Authors: Fisher M. K. , Wright C. A. , Davidson B. M. , Goodwin A. K. , Fielder E. O. , Buckler W. S. , Steinsberger N. P.
Published: December 2007

A large hydraulic fracture diagnostic project was undertaken in the summer of 2001, which integrated fracture diagnostic technologies including tiltmeter (surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett Shale of North Texas. The detailed fracture mapping results allowed construction of a calibrated 3-D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed.

The Barnett Shale has seen a rebirth of drilling and refracturing activity in recent years due to the success of waterfrac or "light sand" fracturing treatments. This extremely low permeability reservoir benefits from fracture treatments that establish long and wide fracture fairways, which result in connecting very large surface areas of the formation with an extremely complex fracture network.

Understanding the created fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area with its non-classical fracture networks. Integrated fracture diagnostics have led to the identification of new fracturing techniques as well as additional refrac and infill drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface and downhole tilt fracture mapping allowed characterization of the created fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior.
Running Two BHP Gauges to Determine Fracture Growth and Entry Pressure: A Case Study in Canada
Authors: Rueda J. I. , Gu H. , Vandenborn C. , Thompson D.
Published: December 2007

Hydraulic fractures are sometimes designed to start in an upper pay zone and grow into a lower pay zone(s) to avoid generation of multiple fractures during the treatment or to prevent sand production. For such treatments, there is no published methodology to confirm if the fracture actually grows into the lower pay zones. Another issue that engineers must address is that the measured pressure in the wellbore always includes the entry pressure (perforation, microannulus and/or tortuosity), complicating pressure interpretation and making fracture diagnosis difficult.

This paper discusses how running two non-communicating bottomhole pressure (BHP) gauges for a fracture treatment gives reliable and useful information about height growth, and entry pressure. Moreover, the proposed configuration of BHP gauges gives a continuous, direct fracture pressure measurement without being affected by any entry pressure; i.e., the pressure immediately inside the fracture is measured. We will present a field case where such a configuration was used to confirm that the fracture originated in the upper pay zone and grew through a 7-ft thick shale to connect a lower pay zone. Two gauges were run as follows: one memory gauge below a bridge plug to monitor the lower perforated pay zone, and one surface readout gauge (real time) within the frac string to monitor the bottomhole pressure of the upper perforated zone being treated. For this case we confirmed that the fracture did indeed grow into the lower pay zone during both the minifrac and the main treatment. We were also able to measure exactly how much entry pressure was present during both the minifrac and the main treatment. In addition, conflicting pressure behaviors from the two gauges were observed during a sequence of injections and shut-ins and are explained later in the paper. The explanation leads to the conclusion that a conventional BHP measurement may yield pressure behavior that is misleading for pressure diagnostics.
Towards Zero Fluid Loss Oil Based Muds
Authors: Aston M. , Mihalik P. , Tunbridge J. , Clarke S.
Published: December 2007

Fluid loss control is an important property of drilling muds which impacts the drilling operation in a number of ways including the prevention of differential sticking and formation damage avoidance. This study reviews the mechanisms of fluid loss control in oil muds. The main focus is an experimental study which probes the function of common additives such as barite and clays, dispersed liquid (the emulsion phase), and materials such as asphalts, gilsonites and polymers. HTHP fluid loss measurements and diagnostic techniques such as particle size measurement, SEM, and neutron scattering were performed to elucidate the mechanisms.

It is shown that there are three critical mud components required to achieve extremely low fluid loss: fine clay, the emulsion droplets, and partially-soluble additives such as gilsonites or certain polymers. By optimising the mix, HTHP fluid loss values as low as 0.1ml/30 min at 120°C have been achieved. The gilsonites, asphalts and polymers do not necessarily function as deformable particles in oil muds - they partially dissolve and appear to act at the nanometre scale. Filter cake permeabilities are shown to be similar to that of a shale, hence the problem of obtaining zero fluid loss reduces to that of preventing fluid flow through shales but without the benefit of capillary pressure effects.
Application of Injection Tests for Reservoir Appraisals: A Conceptual Study
Authors: Gan Ronald Gunawan , Yeh Nai-Shyong , Bennett Curtis O.
Published: December 2007

This paper presents a conceptual study to evaluate the effectiveness of injection tests for the collection of dynamic reservoir data during project appraisals. A 2-D xy numerical model was built using representative field data to simulate the process and pressure response during injection and falloff tests for various boundary conditions. Various injection cases were studied: water injection into oil and gas condensate reservoirs, nitrogen injection into oil reservoirs, and nitrogen injection into dry gas, lean retrograde gas condensate, and heavy retrograde gas condensate reservoirs. For the case of nitrogen injection, we used a compositional option to model the phase interactions during the tests. Simulated pressure responses were analyzed using single-phase analytical solutions provided by a commercial well testing software package.

We found that a composite reservoir model provided by well testing software package can be used to analyze the injection and falloff tests data. Permeability and distance to the boundary can be estimated for most of mobility ratios. Permeability found during the injection test is the effective permeability to the injected fluid. For the falloff test, it is possible to obtain the effective permeability of reservoir fluid. Type of boundaries can be detected and the distance from the well to the boundaries can be estimated by using effective system compressibility. The ability of boundary detection and mobility calculations are heavily dependent upon the optimal injected volume, and therefore, rely on proper well test design. For test design, the optimum injection volume is very important since it affects the time required to have radial flow in the uninvaded zone (‘reservoir zone’) which is necessary for the interpretation of reservoir boundary. Mobility ratio affects the length of transition zone and also the interpretation of reservoir boundary. Therefore, test design using a reservoir simulator is critical for determining the injection volume and the phase interactions if any, and understanding the pressure response. In addition to the above results, we utilize the material balance approach to calculate the compartment volume thus enhance the interpretation of injection and falloff tests.

The results of this study provide a new and comprehensive overview of the practical application of the injection and falloff tests for the collection of dynamic reservoir data during project appraisal–with zero flaring.
The Health, Safety, and Environmental Benefits of Real-Time Operations
Authors: Knode Tom , Disatell Joel
Published: December 2007

Traditionally, well-construction projects have required ongoing wellsite involvement of various personnel such as individuals representing the operator, contractor, and third party. The movement of people represents exposure to risk related to both travel and onsite operations. Conventional risk-mitigation methods currently include journey management, hazard analysis, and various other administrative controls.

With the advent of real-time operations, a new opportunity to help reduce these risks has been introduced. Individuals who, in the past, were required to be on site can now access critical information, provide technical support, make decisions, and implement corrective actions while removed from the location. This improves manpower utilization and reduces cycle time, which can result in decreased exposure to all project personnel.

Real-time operations enable all parties to gather and analyze data and take immediate corrective action without being onsite, significantly reducing the risk factors associated with a well-construction project.
Impact of Drilling Activities: Seabed Recolonization. A French experiment.
Authors: Blanchet D. , Camps R. , Dalmazzone C. , Dutrieux E. , Durrieu J. , His E. , Le Minter P. , Senia J. , Galgani F.
Published: December 2007

Due to large constraints on environmental regulations, discharge of drilled cuttings at sea has to be controlled. It is thus necessary to have basic information to contribute to the selection of drilling fluids respectful of the environment. The present study was intended to appreciate under real conditions the impact of cuttings, the capacity of regeneration of the ecosystem and the processes of recolonization. In a first phase, standardized (OSPAR) and experimental toxicity tests, aerobic and anaerobic degradation measurements and lixiviation tests were performed on various types of muds and cuttings (containing diesel oil, two different paraffinic cuts, and glycol). The results of the study demonstrated that:

OSPAR tests show a low toxicity of cuttings. Those containing diesel oil are more toxic The experimental toxicity test using mollusc's larvae is very sensitive The presence of a toxic fraction other than the hydrocarbons in muds has been demonstrated, in particular in muds containing diesel oil The decomposition of hydrocarbons in aerobic conditions is fast (40 days approximately) and slower on the cuttings because of accessibility to hydrocarbons There is no anaerobic degradation after two months on basic oils (diesel oil and paraffinic base oil).

In a second phase, the most suitable measurements were taken within the framework of an in situ experiment at a discharge site in Congo (Africa). Together with this experiment, a complete analysis of benthos was performed after 8 years of deposits. The preliminary results demonstrated:

The zone of extension of the toxicity and the modifications of the benthos is less than a few hundred meters around the discharge site Original fauna is replaced by a more specific fauna

In the more general context of the environmental constraints in the oil industry, our work demonstrated the containment of the impacted zones, the absence of significant risks of modification of the adjacent ecosystems and the possible application to other discharge sites.
The Design, Response, and Field Test Results of a New Slim Hole LWD Multiple Frequency Resistivity Propagation Tool
Authors: Mack S. G. , Wisler M. , Wu J. Q.
Published: December 2007

A new slim hole LWD propagation resistivity tool has been developed that exceeds current commercial specifications for pressure, measurement accuracy, and depth of investigation. The MFR* (Multi-Frequency Resistivity Tool) is designed to operate in borehole pressures of up to 30,000 psi and flow rates of 400 gpm without sustaining damage to the tool or electronics. The MFR operates at both 2 MHz and 400 kHz at antenna-receiver spacings of 20, 30, and 46 inches. All antenna arrays are fully compensated and integrated into the drill collar1 to increase reliability and simplify maintenance. Digital Signal Processors (DSP's) are used to measure phase and attenuation at each transmitter-receiver pair, resulting in 48 absolute measurements. These 48 measurements are combined to produce 12 fully compensated resistivity measurements at unique radial distances from the borehole. The fully compensated antenna design and DSP electronics result in both phase and attenuation accuracy specifications of +/−.25 mmhos and +/−.5 mmhos respectively. The 400 kHz attenuation measurement made at the 46 inch antenna-receiver spacing has a diameter of investigation (DOI) of 197 inches at 20 ohm-m, which is deeper than what is currently available in the industry today. Making resistivity measurements accurately, deeper, and at varying radial distances from the borehole enhance existing applications such as geosteering and inversion modeling.

Field test results acquired while drilling show the response characteristics of the tool in a horizontal well drilled with salt mud and a vertical well drilled with oil based mud (OBM).
Application Of Study Of Bit Selection, Bit Weight And Rotary Speed Practices In Offshore Dubai Drilling Operations
Authors: Myers G.M. , Nordquist E.A.
Published: December 2007

Data on all offshore wells drilled by Dubai Petroleum Company were analyzed for comparison of the Petroleum Company were analyzed for comparison of the effectiveness of different bit types, weights on the bit, and rotary speeds in penetration of the various formations and depth intervals common to this Middle East area. This program was initiated in an attempt to improve penetration rates and reduce per well drilling times. Based on this study, an optimum bit selection, bit weight and rotary speed program was incorporated into drilling plans for subsequent wells drilled in the area. Initiation of this program resulted in a significant improvement in penetration rates, in spite of the fact that some adverse conditions existed, such as formations which have been pressure depleted by production, and drilling pressure depleted by production, and drilling angle holes.

Introduction

An in-depth study of readily available drilling records was used by Dubai Petroleum Company engineers to improve all facets of development drilling. The areas of drilling technology that were critically examined were:–Bit Selection–Mud Practices–Completion Techniques–Bit Energy Levels–Cementing Practices–Directional Techniques

While each of these studies contributed to the improvement of drilling efficiency, this paper will concern itself with the bit selection and bit energy studies. This restriction was made for the following reasons:–Application of the findings of the bit selection and energy studies had the most dramatic effect on efficiency.–Effects of mud properties on drilling efficiency are too subjective to have universal application.–Directional techniques must be studied on afield by field basis. These findings are valid only for the DPC area of operation.–Completion practices are so varied that the present time and motion studies apply only to the DPC situation.

The findings of this study effort were successfully applied in the field. The bit selection energy study was mainly responsible for cutting average drilling time below 20" casing from 26.85 to 21.26 days per well. Application of the entire study reduced overall average drilling and completion time from 54.9 to 46.9 days per well. Average total cost per foot was cut by 5.6% despite a 11.5% increase in per foot was cut by 5.6% despite a 11.5% increase in daily costs and a slightly increased average well depth.

Methods used in the bit selection - energy studies will be detailed at some length. This is not done to advocate that the method used by DPC is the only or even the best one, but rather to show at least one means to attack the problem. Results are shown for the same reason, to demonstrate one way to display the effects of bit selection and bit energy on drilling efficiency.
Improved Reservoir Modeling With Time-Lapse Seismic in a Gulf of Mexico Gas Condensate Reservoir
Authors: Waggoner J. R. , Cominelli A. , Seymour R. H.
Published: December 2007

Time-lapse 3D, or 4D, seismic has been tried in several fields to date, with some good case studies published to demonstrate the utility of the 4D seismic information. While another 4D case study would be useful, this paper describes 2 novel aspects of a recent application in the Gulf of Mexico. First, the target reservoir contains a gas condensate fluid under primary depletion, so pressure, rather than saturation, changes create the observed 4D acoustic response. Further, the primary impact of the pressure change is to the fluid composition as the initially dense gas phase lightens as condensate drops out below the dew point. The result was a 3.6% change in acoustic impedance predicted in the feasibility study.

Second, the 4D seismic result was used to constrain an optimized history matching procedure along with the production data. After describing the seismic history matching method used, the paper will discuss the changes to the reservoir model that resulted. For comparison, some results using a production data only history matching procedure are also presented. While the neither set of history matching results should be considered unique, they do give some insight into the structure of the reservoir that should be considered for optimal reservoir management, and provide an indication of the impact of 4D information in history matching.
Improved Filtercake Cleanup Practices for Horizontal Well Completions in Unconsolidated Sands: Correlation Models for Filter-Cake Removal
Authors: Burnett David , Gutierres Fernando , Serrano Gerardo
Published: December 2007

Improved well productivity from high performance horizontal wells depends upon efficient drilling and completion practices in the formation sand. This study presents empirical models for estimating the breakthrough time and regained permeability for selected nondamaging drill-in fluids (DIFs). The models provide a clear indication of formation damage and proper cleanup treatments for a range of reservoir conditions analyzed in this study. We determined values of breakthrough time and regained permeability for common polymer-carbonate and sized-salt/saturated brine DIFs for a range of reservoir properties including temperature, drill solids content, and percent of acid in the cleanup treatment. These DIFs form tight, thin filtercakes that control fluid leakoff and afford more complete wellbore cleanup properties than standard drilling muds. But determining the appropriate cleanup technique is often difficult.

Work began by creating a large database of 101 tests with 8 independent variables including (1) type of drill-in fluid, (2) temperature, (3) screen type, (4) presence of gravel pack, (5) formation type, (6) type of drill solids, (7) concentration of drill solids, and (8) cleanup treatments.

In measuring the regained permeability, we used a linear-flow cell apparatus. In measuring the breakthrough time that particular cleaning procedures take to flow across the filter cake, we used a ceramic disc cell apparatus.

We analyzed the importance of each variable. After that, we identified the independent variables we were taking into account during this research. Those variables were (1) temperature, (2) drill solids content, and (3) cleanup (concentration of hydrochloric acid in the cleanup treatment). Then we generated a matrix for each set of experiments that allowed us to organize and measure the conditions we were looking for, regained permeability and breakthrough time.

We used statistical software to select properties, formation, and diagnostics of the models and to develop relationships among the properties of the DIF's. We developed four new empirical models for estimating the breakthrough time and regained permeability in polymer carbonate and sized salt. High correlations resulted with R2 values between 0.851 and 0.986 corroborated by close values of adjusted R-square and low P-values give validity to the correlations found. This technique gives a broad overview of the formation damage as well as the proper cleanup treatment for similar conditions presented in the field.

Well audits of horizontal wells drilled and completed using advanced technology. Cleanup methods have closely matched predicted values of well PI.
Reservoir Characterization During Underbalanced Drilling: Methodology, Accuracy, and Necessary Data
Authors: Vefring Erlend H. , Nygaard Gerhard , Fjelde Kjell Kåre , Lorentzen Rolf Johan , Nævdal Geir , Merlo Antonino
Published: December 2007

In this paper a novel methodology for reservoir characterization during underbalanced drilling is presented. In this methodology we are using a transient wellflow model coupled to a transient reservoir model, and use estimation techniques to estimate reservoir properties. Our focus is to estimate the permeability and reservoir pressure along the well, using measured data usually available while drilling. The measured data are outlet rates, pump pressure and downhole pressure. The liquid injection and gas injection rates are used as input to the model.

Our finding is that estimating permeability and reservoir pressure simultaneously is a difficult estimation problem, and may lead to large uncertainties in the estimates. If we assume that the reservoir pressure is known, however, reliable estimates of the permeability is obtained. A methodology for uncertainty analysis is also presented and can be used to evaluate necessary measurements for proper reservoir characterization.
Effects of Formation Damage and High-Velocity Flow on the Productivity of Perforated Horizontal Wells
Authors: Tang Yula , Yildiz Turhan , Ozkan Erdal , Kelkar Mohan
Published: December 2007

A comprehensive semi-analytical model is built to investigate the effects of drilling/perforating damage and high-velocity flow on the performance of perforated horizontal wells. In our previous papers1,2, we presented a semi-analytical model for completed horizontal wells by coupling the 3D reservoir flow model and the wellbore-hydraulics model and discussed the pseudo-skin approach for clean perforated completion. In this paper, the additional pressure drop due to formation damage and high-velocity flow are addressed and incorporated into the previous semi-analytical model. The reservoir model considers the 3D convergent flow into individual perforations, flow through the damaged zone around the wellbore and the crushed zone around the perforation tunnels as well as the additional pressure drop due to non-Darcy flow in near wellbore region. Both oil and gas wells are discussed.

The expressions for additional pressure losses due to perforating damage, drilling damage and high-velocity flow can be used to optimize perforating parameters and to decompose the total skin into its components (perforation pseudoskin, damage skin, and non-Darcy skin).
Productivity Changes in Reservoirs with Stress-Dependent Permeability
Authors: Raghavan R. , Chin L. Y.
Published: December 2007

The goal of this paper is to present correlations to permit engineers to evaluate productivity losses in reservoirs with stress-dependent permeability (stress-sensitive reservoirs). The correlations developed in this study are intended to be used in determining production forecasts. For stress-sensitive reservoirs, the reduction in permeability caused by change in the stress state during production, if any, may significantly reduce expected productivity. It is the purpose of this paper to address methods to ascertain changes in productivity as a result of stress-dependent permeability. A rigorous mathematical model that couples geo-mechanical and fluid-flow aspects is used to correlate productivity reductions with time. The reduction in productivity index (PI) is expressed as a function of operating variables such as overburden stress, mechanical properties, wellbore pressure, drainage area etc. The expressions developed in this study may be directly incorporated (after tuning) in simulators to properly account for changes in productivity.
Three-Phase Displacement Theory: An Improved Description of Relative Permeabilities
Authors: Juanes Ruben , Patzek Tad W.
Published: December 2007

A quantitative understanding of three-phase flow in porous media is required to address many diverse processes in the subsurface, e.g., improved oil recovery, CO2 sequestration, and aquifer clean-up. In turn, all predictive models of three-phase flow originate from interpretations of onedimensional laboratory experiments; when these interpretations are flawed, so are the models. In this paper we revisit the foundations of displacement theory in three-phase flow and provide the most general conditions for any relative permeability model to be physical anywhere in the saturation triangle. In doing so, we put to rest a controversy that has persisted in petroleum literature for the better part of the last six decades.

When capillarity is ignored, the system of conservation laws describing incompressible immiscible flow should be strictly hyperbolic. This natural property of the system fails for most relative permeability models used today. We identify necessary conditions that relative permeabilities must obey to preserve strict hyperbolicity. These conditions are in agreement with experimental observations and pore-scale physics.

We also present the most general analytical solution to the Riemann problem (constant initial and injected states) for three-phase flow, and describe the characteristic waves that may arise, concluding that only 9 combinations of rarefactions, shocks and rarefaction-shocks are possible. Some of these wave combinations have been overlooked by many because of the associated conceptual and mathematical difficulties.

The analytical developments presented here will be useful in the planning and interpretation of three-phase displacement experiments, in the formulation of consistent relative permeability models, and in the implementation of streamtube simulators.
Prediction of wettability variation and its impact on waterflooding using pore-to reservoir-scale simulation
Authors: Jackson Matthew D. , Valvatne Per H. , Blunt Martin J.
Published: December 2007

We describe a pore-to reservoir-scale investigation of wettability variation and its impact on waterflooding. Our aim is to demonstrate that network models incorporating realistic pore-space geometry and physics may be used as a tool to predict wettability variations and their impact on flow.

We successfully predict experimental data for water-wet and mixed-wet media using a three-dimensional pore-scale model of a Berea sandstone. We then focus upon the effect of variations in initial water saturation associated with capillary rise above the oil-water contact (OWC). This may lead to wettability variations with height, because the number of pore-walls which may be rendered oil-wet during primary drainage increases as the oil saturation increases.

We investigate the validity of empirical hysteresis models in which scanning curves are used to connect bounding waterflood and drainage curves for a given initial water saturation. If the wettability varies with initial water saturation, we demonstrate that the bounding waterflood curve, which is measured from the lowest water saturation (and hence the most oil-wet conditions), does not yield the correct scanning curves at higher water saturations.

We use network model derived relative permeabilities in a conventional field-scale simulation of waterflooding a typical North-Sea reservoir. If the wettability varies with height above the OWC, we demonstrate that the displacement efficiency is high. This is because the water relative permeability curves are generally low (characteristic of water-wet media), yet the residual oil saturation is also generally low (characteristic of oil-wet media). Assuming that the reservoir is uniformly water-wet or oil-wet, or using empirical hysteresis models, leads to an underestimate of recovery.

Using a physically-based pore-scale approach predicts behavior at both the core and field scales that is qualitatively different from that predicted by conventional relative permeability models. This work suggests that where there is a wettability trend in a reservoir, the relative permeabilities can have a first order impact on recovery predictions.
Drill Cuttings Injection: A Review of Major Operations and Technical Issues
Authors: Keck Richard G.
Published: December 2007

Since its first use about 15 years ago, drill cuttings injection has grown to become a routine operation performed around the world. This rapid development is due to increasingly stringent environmental regulations and improved costs compared to alternative disposal options. The regulations for overboard discharge of cuttings started with limitations on oil-based muds and has now expanded to include synthetic muds as well. The economics of injection operations have improved as the industry has gained experience with the technology, with added benefits from the economies of scale offered by large capacity injection facilities.

The two critical engineering questions that must be answered for injection applications are: (1) where does the waste go and (2) how much can we safely inject into a well? These questions require integration of a variety of environmental, technical and economic factors that are important for each particular injection operation. The geometry of hydraulic fractures created during solids injection is one of the key issues in most operations. This coupling between solids injection and fracturing is the focus of this paper.
Extending Foam Technology from Improved Oil Recovery to Environmental Remediation
Authors: Mamun C. K. , Rong J. G. , Kam S. I. , Liljestrand H. M. , Rossen W. R.
Published: December 2007

In the petroleum industry, foams are used for improved oil recovery, reducing gas breakthrough to productions wells, and diverting acid in well-stimulation treatments. A substantial body of research on foam for these applications is extended here to the high-permeabilities and low pressures of environmental remediation, through both laboratory experiments and computer simulations based on the laboratory results.

New data confirm that the two steady-state flow regimes identified by Alvarez et al. for petroleum applications exist under conditions relevant to groundwater remediation. The low-quality regime is strongly shear-thinning, in agreement with Alvarez et al. The high-quality regime is more sensitive to surfactant concentration than the low-quality regime, while the low-quality regime is more sensitive to permeability. Therefore, diversion between layers differing in permeability would be more effective in the high-permeability regime, while the low-quality regime has advantages for injectivity and liquid diversion.

A foam simulator can be fitted to these steady-state foam data. Simulations indicate that foam can propagate without gravity segregation over long distances at an overall average pressure gradient of well under 1 psi/ft. Moreover, a simple correlation for gravity segregation developed for petroleum applications works well for aquifers overlain by a vadose zone, as long as the assumptions of that correlation (Newtonian rheology, incompressible flow) are satisfied.

Local steady state would not be achieved in the field if pressure gradient were insufficient for foam generation, however. New results indicate that at moderate ∇p foam may exist in an unstable regime between strong and coarse foam.
High Resolution Downhole Measurements of Porosity and Fluid Saturation While Core Drilling
Authors: Bonnecaze Roger T. , Sharma Mukul M. , Butler Jason E. , Arboleda Gustavo
Published: December 2007

A new method is presented for making high resolution, downhole measurements of porosity and fluid saturations while coring drilling. The method relies on a bank of sensors located in the inner core barrel directly above the drill bit. The sensors allow measurements to be made as the core enters the core barrel and passes by the sensor array. The well-defined cylindrical geometry allows us to construct a cross sectional image of the core at high-resolution (cm scale). The core can then be retrieved to the surface or disaggregated and circulated out as cuttings.

Experimental results are reported for an array of 32 equally spaced electrodes around a cylinder. The electrodes were fired in the opposite protocol, where current is injected across opposite electrodes and measurements of potential differences were made between all other adjacent pairs. The data were then numerically inverted to obtain electrical impedence images (tomograms) of several cross-sections of the core. Results are presented for an oil-saturated 4-inch diameter core from Prudhoe Bay, Alaska. To test the validity of the electrical tomograms, the core was also X-ray CT scanned at high resolution to obtain accurate maps of porosity and oil saturations. A comparison of oil saturations from the electrical tomograms with the CT images shows good agreement.

The possible application of other types of sensors and how they may be used in conjunction with electrical measurements is also discussed. Our results show that it may be possible to make measurements of porosity and fluid saturations down-hole, directly behind the bit, using the proposed method.
Optimization of Nonconventional Well Type, Location and Trajectory
Authors: Yeten Burak , Durlofsky Louis J. , Aziz Khalid
Published: December 2007

The determination of the optimal type, location and trajectory of a nonconventional well is very challenging. The problem is more complicated than other well optimization problems because of the wide variety of possible well types (i.e., number, location and orientation of laterals) that must be considered. In this paper, a general methodology for the optimization of nonconventional wells is presented. The optimization procedure entails a Genetic Algorithm applied in conjunction with several acceleration routines that include an artificial neural network, a hill climber, and a near-well upscaling technique. The overall methodology is then applied to a number of problems involving different reservoir types and fluid systems. It is shown that the objective function (cumulative oil produced or net present value of the project) is always increased relative to its value in the first generation of the optimization, in some cases by 30% or more. The optimal well type is found to vary depending on the reservoir model and objective function. The effects of reservoir uncertainty are also included in some of the optimizations. It is shown that the optimal type of well can differ depending on whether single or multiple realizations of the reservoir geology are considered.
A Model for Analysis of Injection-Well Thermal Fractures
Authors: Slevinsky B. A.
Published: December 2007

The performance of water injection wells in deep, warm reservoirs is usually dominated by thermally enhanced fracturing of the formation. Modern pressure and rate monitoring data for these injection wells allows the fracturing performance of the wells to be observed on a continuous basis. A simple analytical model for thermal fracture growth has been developed, by coupling equations for fracture growth and fluid leak-off from the fracture. The empirical equation form allows the observed data to be analyzed to determine the timing and extent of fracture growth, and degree of fracture face plugging. As well, the equation form has lead to development of a fracturing index, which can be used as a surveillance tool to determine the state of fracture growth in an injection well.

Once calibrated for a field or area, the model can be used to predict continued extension of fractures with time and injection. An example of analysis of an offshore injection well illustrates application of the model to real-time surveillance. The model has also been used to design new injection wells including the attached thermal fractures, aiding production engineering well equipment design, and reservoir simulation to evaluate well placement for optimum performance. The approach is new, pragmatic, and does not require coupled geo-mechanical and thermal simulation models.

SPE Paper 20741 states: "A solution for fracture growth in terms of detailed fracture-volume balance (as is often applied to hydraulic stimulation) is not a natural or feasible approach."

The method outlined in this paper shows that it is not only feasible, but leads to development of an empirical equation form which allows improved understanding of well performance and ability to forecast future behaviour.
Deep Water Real Options Valuation: Waiting for Technology
Authors: Rutherford Steven R.
Published: December 2007

This paper describes a real options valuation of a deepwater development opportunity in case history format. When valued using today's development costs, the project is economically challenging. However, new subsea development technologies that are expected to become available over the next 5 to 10 years should dramatically enhance the economics of the project. The main economic impact of these technologies is through enhanced production rates and increased peak production plateaus though reduced CAPEX benefits may accrue as well.

The real options valuation employs a "compound sequential option" approach implemented using a Dynamic Decision Tree technique. The first component of the compound option corresponds to the exploration phase of the project. During this phase, exploration and delineation drilling is undertaken to resolve the uncertainty associated with the size of the reserves. At the end of the exploration phase the development team has two alternatives to choose from. The project can be developed using conventional technology, if economically viable, or an option to wait and develop using new technologies can be exercised. The wait for new technology option is the second component of the compound option. During the waiting phase uncertainty concerning the enhanced productivity derived from the new technologies is resolved. The flexibility associated with these development alternatives significantly increases value when compared to a conventional NPV analysis of the project. The results presented in this paper are directly applicable to other deepwater valuations and similar types of valuations involving anticipated new technology developments.