bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Correlation of Acid-Fracture Conductivity Subject to Closure Stress
Authors: Deng J.. , Mou Jianye , Hill A.D.. D. , Zhu D..
Published: April 2012

The conductivity of an acid-etched fracture depends strongly on void spaces and channels along the fracture resulting from uneven acid etching of the fracture walls. In this study, we modeled deformation of the rough fracture surfaces acidized in heterogeneous formations based on synthetic permeability distributions and developed a new correlation to calculate the acid-etched fracture conductivity.

In our previous work, we modeled the dissolution of the fracture surfaces in formations having small-scale heterogeneities in permeability. The characterization of the correlated permeability fields of rock includes the average permeability, normalized correlation lengths in both horizontal and vertical directions, and normalized standard deviation. These statistical parameters have a significant influence on the fracture-etching profiles obtained from the model. Beginning with this fracture-width distribution, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. The elastic properties of the rock, such as Young's modulus and Poisson's ratio, have effects on the size of the spaces remaining open after fracture closure. After the model yields the width profile under closure stress, the overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system.

In this paper, we introduce our models and investigate the effects of permeability and mineralogy distributions and rock elastic properties on the overall conductivity of an acid-etched fracture. A new acid-fracture conductivity correlation is developed on the basis of many numerical experiments.
The Guard Electrode Logging System
Authors: Owen John E. , Greer Walton J.
Published: April 2012

The guard electrode system measures the resistivity of formations by employing a thin disk of current which is caused to flow perpendicular to the bore hole. The control of this current disk is obtained in a brute force manner through the use of relatively long equipotential electrodes above and below the measuring electrode.

The log obtained from the system is free of "lag," "plateau," "shadow," "reflection" and other distortions evident on conventional logs. The proportionate contributions of the hole size and invaded zone resistivity to the apparent resistivity reading are reduced when the mud and filtrate resistivities are lower. Thus, the guard system favors the use of conductive muds.

The mathematical development of the theory is given in an appendix. Equations are derived to evaluate the effects of mud resistivity, hole size, invaded zone resistivity and depth, and the true formation resistivity.

Sample logs from several provinces are reproduced and compared with conventional electric logs to illustrate the much greater detailed lithology that can be presented by the guard electrode system.

Introduction

With increased ability of those in the petroleum industry to analyze formation characteristics from electrical resistivity data, there has become apparent the need for more precise measures of that parameter.

The measurement of the resistivity of a homogeneous and isotropic material can be made simply when the body of the material is infinite in all dimensions and the measuring electrodes can be placed within the body. In such a case, the current leaving an electrode follows a spherical distribution and the mathematical expression for the potential level at any distance from that electrode can readily be derived.

If it is considered that the active electrodes are within a bore hole filled with mud of a resistivity different from that of the formation, the current does not flow in a spherical pattern near the current source or sink, and the calculations of potential levels become more difficult. The additional consideration of a section of formation invaded by mud filtrates, and thus having resistivity different from either that of the mud, the adjacent formations or of the undisturbed formation, makes the mathematical problem extremely complex. Should the vertical dimensions of the formations be considered as finite, the problem becomes so complex as to preclude reasonable solution. Yet, even these considerations have not described adequately the conditions encountered in a large proportion of the wells to be studied.
Radial Filtration of Drilling Mud
Authors: Prokop C.L.
Published: April 2012

A laboratory investigation has been made of the effects of mud hydraulics upon the formation and erosion of mud filter cakes. The tests were conducted to simulate drilling conditions as nearly as possible.

The formation of mud filter cake in a drilling well does not proceed at a uniform and unbroken rate. Instead, the rate of cake accumulation depends upon whether or not the mud is being circulated. If the mud column is quiescent, filter cake formation is a smooth function of the filtration characteristics of the system. If the mud is being circulated filter cake formation depends not only upon the filtration characteristics of the mud but also upon the erosive action of the flowing mud column.

Filter cakes formed during continuous mud circulation were observed to reach an equilibrium thickness after several hours' circulation. Mud circulation was maintained at a constant volumetric rate throughout each experiment. The fluid velocity at equilibrium cake thickness was dependent upon the thickness of the filter cake. Muds having exceptionally high water loss deposited thick filter cakes in spite of very high eroding velocities. The muds having good filtration characteristics deposited thin filter cakes at equilibrium circulating velocities well within the range of those used in a drilling well.

It was observed that filter cakes deposited during stagnant filtration were quite difficult to erode by mud circulation. The rate of erosion computed from the rate of filtrate accumulation after equilibrium cake thickness had been reached was in reasonable agreement with the rate of erosion obtained by direct observation. Continuous mud circulation usually caused the permeability of the filter cake to decrease with time.

Introduction

Many of the difficulties encountered during the drilling of a well have been attributed to the loss of water from the mud and the attendant deposition of solids upon the walls of the hole. Past experience has shown that a reduction of the filtration rate of the drilling fluid eliminates or greatly reduces these difficulties. Definite filtration requirements, however, are hard to establish for a given set of conditions. This is due, in part, to the fact that the usual filtration test performed upon mud does not simulate well conditions as closely as desirable.
Production Analysis of Tight-Gas and Shale-Gas Reservoirs Using the Dynamic-Slippage Concept
Authors: Clarkson C.R.. R. , Nobakht M.. , Kaviani D.. , Ertekin T..
Published: April 2012

Shales and some tight-gas reservoirs have complex, multimodal pore-size distributions, including pore sizes in the nanopore range, causing gas to be transported by multiple flow mechanisms through the pore structure. Ertekin et al. (1986) developed a method to account for dual-mechanism (pressure- and concentration-driven) flow for tight formations that incorporated an apparent Klinkenberg gas-slippage factor that is not a constant, which is commonly assumed for tight gas reservoirs. In this work, we extend the dynamic-slippage concept to shale-gas reservoirs, for which it is postulated that multimechanism flow can occur. Inspired by recent studies that have demonstrated the complex pore structure of shale-gas reservoirs, which may include nanoporosity in kerogen, we first develop a numerical model that accounts for multimechanism flow in the inorganic- and organic-matter framework using the dynamic-slippage concept. In this formulation, unsteady-state desorption of gas from the kerogen is accounted for. We then generate a series of production forecasts using the numerical model to demonstrate the consequences of not rigorously accounting for multimechanism flow in tight formations. Finally, we modify modern rate-transient-analysis methods by altering pseudovariables to include dynamic-slippage and desorption effects and demonstrate the utility of this approach with simulated and field cases. The primary contribution of this work is therefore the demonstration of the use of modern rate-transient-analysis methods for reservoirs exhibiting multimechanism (non-Darcy) flow. The approach is considered to be useful for analysis of production data from shale-gas and tight-gas formations because it captures the physics of flow in such formations realistically.
A New Additive for Control of Drilling Mud Filtration
Authors: Salathiel R.A.
Published: April 2012

A new synthetic material has been developed which is highly effective in treating drilling muds to reduce filtration rate. The material is the soluble salt of a very high molecular weight condensation product of sulfonated phenol and formaldehyde (SPIF). Laboratory tests show that SPIF is effective in muds of all salinities varying from fresh water to saturated salt water. Alkaline materials, such as soda ash or caustic and quebracho, may be used in combination with SPIF to advantage, and are essential in muds containing saturated salt water. In a field test where the water used in the mud had a salinity of about one-half that of sea water, SPIF in combination with caustic and quebracho made a very satisfactory mud. SPIF does not ferment, but due probably to additional polymerization a slight decrease in effectiveness is found when it is subjected to high pH and high temperature for a long time.

Introduction

Drilling mud is essential in rotary drilling. The influence of variations in the different properties of a mud on its ability to perform the various functions in drilling of wells is thoroughly understood in some cases and poorly understood in others. For instance, the function of mud density in restraining high pressure fluids is simple and well known. On the other hand, while the value of low filtration is widely recognized, it is seldom possible to determine precisely what filtration rate is required for the mud to perform its functions properly. Filtration rate is important because it influences the ease of moving tools in or out of the hole. Filtration rate also affects the stability of the bore hole walls, which are subject to softening and degradation by aqueous filtrate. Difficulties in rotary drilling are often avoided by using low-filtration muds.

Treatment of fresh-water muds to provide moderately low filtration rates usually consists of adding chemicals to improve the dispersion of the clays. To provide very low filtration rates, organic colloidal materials are added. Among the materials that are used in this way are starch, natural gums, and altered celluloses. In muds that contain large amounts of salt or calcium or magnesium ions, the clays are coagulated and, as a consequence, the filtration rate is undesirably high. In such muds organic colloids are of great importance.
Decreasing Water Invasion Into Atoka Shale Using Nonmodified Silica Nanoparticles
Authors: Cai J. , Chenevert M. E. , Sharma M. M. , Friedheim J.
Published: April 2012

Fluid penetration from water-based muds into shale formations results in swelling and subsequent wellbore instability. Particles in conventional drilling fluids are too large to seal the nano-sized pore throats of shales and to build an effective mudcake on the shale surface and reduce fluid invasion. This paper presents laboratory data showing the positive effect of adding commercially available, inexpensive, nonmodified silica nanoparticles (NP) (particle sizes vary from 5 to 22 nm) to water-based drilling muds and their effect on water invasion into shale.

Six brands of commercial and nonmodified nanoparticles were tested and screened by running a three-step pressure penetration (PP) test (brine, base mud, nanoparticle mud). Two types of common water-based muds, a bentonite mud and a low-solids mud (LSM), in contact with Atoka shale were studied with and without the addition of 10 wt% nanoparticles. We found that a large reduction in shale permeability was observed when using the muds to which the nonmodified nanoparticles had been added. For the bentonite muds, the permeability of Atoka shale decreased by 57.72 to 99.33%, and, for the LSMs, the permeability of Atoka shale decreased by 45.67 to 87.63%. Higher plastic viscosity (PV) and lower yield point (YP) and fluid loss (FL) of the nanoparticle muds compared with base muds were also observed. We also found that nanoparticles varying in size from 7 to 15 nm and a concentration of 10 wt% are shown to be effective at reducing shale permeability, thereby reducing the interaction between Atoka shale and a water-based drilling fluid.

This study shows for the first time that it is possible to formulate water-based muds using inexpensive nonmodified and commercially available silica nanoparticles and that these muds significantly reduce the invasion of water into the shale. The addition of silica nanoparticles to water-based muds may offer a powerful and economical solution when dealing with wellbore-stability problems in troublesome shale formations.
Improving Sweep Efficiency In A Mature Waterflood: Balcon Field, Colombia
Authors: Perez D. , Muñoz L. F. , Acosta W. , Falla J. , Martínez J. , Vidal G. , Manrique E. , Cabrera F. , Romero J. , Izadikamoue M. , Norman C.
Published: April 2012

The Balcon Field, operated by HOCOL S.A., is located in Colombia's Upper Magdalena Valley Basin. Oil production began in 1988, reaching a maximum primary rate of 5,742 BOPD in January 1994. Secondary recovery started in 1996, achieving a maximum secondary production of 9,198 BOPD in June 2001. Subsequently, water production has increased rapidly accompanied by declining oil production, due primarily to reservoir heterogeneity and an unfavorable mobility ratio. The oil recovery factor as of July 2011, as a percentage of OOIP, is estimated to be approximately 30% at a current water cut of about 84%.

This work presents a methodology to determine the feasibility of polymer gels to reduce water channeling, including water injection and production analysis, diagnostic charts, fluid movement and geological characterization. Results of this integrated analysis led to a comprehensive laboratory study to identify the appropriate gel formulation (e.g. polymer, polymer concentration and cross linker ratio) at reservoir conditions. The recommended gel system developed was validated by a core flood before field implementation.

The first gel treatment was implemented in July 2010, followed by a second injection well treatment in an adjacent pattern with significant water channeling. The treatment designs included several stages of varying gel concentrations and injection rates, which were modified during the field implementation based on surface pressure response.

Post treatment oil response occurred within approximately two months and payout was achieved in 6 months. As of April 2011 incremental oil of 212,000 bbl. has been produced. However, offset producers are still showing incremental production. These promising results led to a second (and ongoing) campaign in 2011.

Polymer gels have been successfully applied in sandstones reservoirs for decades. However, reservoir characterization tools continue to evolve contributing to the improvement of conformance treatment designs. This field case study will provide an updated framework for operators considering chemical sweep improvement technologies as part of an integrated reservoir management strategy.
Modeling Drilling Fluid Losses in Fractured Reservoirs
Authors: Oliveira J. A. , Souza J. Z. , Fontes C. E. , Waldmann A. T. , Martins A. L.
Published: April 2012

Fluid losses are still today one of the most challenging problems in well construction. Most strategies to control losses are empirical and in some situations, detrimental effects can not be avoided. This article deals with unique modeling efforts to understand the dynamics of bridging fractured zones. The main tools adopted to address the problem were the Computational Fluid Dynamics, whenever necessary coupled with Discrete Element Method packages. The main goal was to study particle deposition inside fractures due to losses through the external walls of an axial annular flow. ANSYS FLUENT® and EDEM® were the adopted simulation tools.

The study includes two different modeling strategies: Discrete Element Simulation and Granular Eulerian CFD approach. The first method solves the particle trajectory equations individually, considering collision and cohesion effects. Despite of the reliability of the approach, computation effort is huge and limits the number of particles in the system. The Eulerian approach, on the other hand treats statistically the particulate system, generating a probabilistic field of occurring one or the other phase at given space and time. This approach obviously generates smaller computational costs. The developed methodologies allow the evaluation of the efficacy of bridging agents in plugging fractured zones.
Integrated Cementing Hydraulics Design for Massive Salt Zones
Authors: Martins A. L. , Aranha P. E. , Folsta M. G. , Simão C. A. , Batalha N. A. , Pinto G. H.
Published: April 2012

Salt formations are common trap zones for prolific reservoirs. Recent discoveries in the Brazilian coast include light oil carbonate reservoirs below massive salt zones. Well construction challenges in such environments include salt creeping, leaching and proper zonal isolation.

This article presents a comprehensive integrated methodology for cementing design which accounts for the following hydraulic aspects: Adequate fluid substitution design supported by numerical simulation considering two phase flow in eccentric annuli and lubrication theoryDownhole pressures in the operational window considering free fall effects for deepwater environmentsOpen hole volume prediction based on salt leaching phenomena due to the circulation of unsaturated fluids. Flow rate fluctuation as a result of free fall is consideredIncrease in salt concentration due to conduction effects after placement and its impact on slurry properties.

The methodology is exemplified by two typical scenarios for offshore salt cementing in the Brazilian pre-salt cluster. Slurry design, slurry placement schedules and borehole stability considerations are addressed.
Numerical Simulation of Transient Flow for Gas Pipeline and Tank
Authors: Ling K.
Published: April 2012

Gas transient flow in pipeline and gas tank is critical in flow assurance. Not only leak detection requires a delicate model to simulate the complicated yet drastically changed phenomena, but also pipeline and tank design in the metering, gathering, and transportation system demands an accurate analysis of gas transient flow, through which efficient, cost-effective operation can be achieved.

Traditionally there are two types of approaches to investigate gas transient flow: one is treating gas as ideal gas so that ideal gas law can be applied; another is considering gas as real gas thus gas compressibility factor comes into play. Needless to say, the former method can result in an analytical solution to gas transient flow yet with a deviation from the real gas performance, which is very crucial in daily operation. The latter approach needs numerical method to solve the governing equation, thus leads to unstable issue but with more accurate result. Our literature review indicated that no study considered the effect of changing gas viscosity on the transient flow is available. Therefore, this effect was included in our study.

Our investigation showed that viscosity does have significant influence on gas transient flow in pipe and tank leakage evaluation. In this study, a comprehensive evaluation of all variables was done to find out the most important factors in the gas transient flow. Several case studies were used to illustrate the significant of this study. Engineers can do a more reliable evaluation on gas transient flow by following the method we used in our study.
Stepping Forward: An Automated Rock Type Index and a New Predictive Capillary Pressure Function for Better Estimation of Permeability and Water Saturation. Case Study, Urdaneta-01 Heavy Oil Reservoir
Authors: Tillero E.
Published: April 2012

Despite the great effort made to characterize reservoir rock, proper techniques in grouping rock type, in predicting permeability, and also in estimating water saturation from reservoirs that exhibit high variability in permeability-porosity relationship are still debatable today. In addition, core sampling for both routine and special core analysis may be biased in spite of the wide number of existing rock types, mostly in the case of heterogeneous rock reservoirs.

The main objective of this work was to develop a new mathematical expression for water saturation prediction, in the case study Urdaneta-01 heavy oil reservoir, in Maracaibo Lake basin, Venezuela, based on an alternative approach of traditional Leverett J-function. This new equation was developed by introducing two additional power-fit coefficient as function of water saturation (for specific capillary pressure values), Leverett J-function slope (from all values of capillary pressures test), and height above free water level (FWL). In addition, an automatic Rock Type Index was used to accurately estimate reservoir permeability.

A reliable water saturation profile according to rock type was obtained from the new water saturation approach. At least 3 to 5% difference between water saturation from log-based traditional techniques and that of the alternative approach (new expression for Sw) was obtained, mostly in heterogeneous intervals. Also it was determined that the innovative rock type indicator provides a better permeability estimation and rock description because of the high definition of rock type obtained from this new technique.
Qualitative and Quantitative Analysis of Three-Phase Distributions of Oil, Water and Gas in Bentheimer Sandstone Using Micro-CT Imaging
Authors: Feali M. , Pinczewski W. V. , Cinar Y. , Arns C. H. , Arns Ji-Youn , Francois N. , Turner M. , Senden T. , Knackstedt M.
Published: April 2012

It is now widely acknowledged that continuous oil spreading films observed in two-dimensional glass micro-model studies for strongly water wet three-phase oil, water and gas systems are also present in real porous media and result in lower tertiary gas flood residual oil saturations than for corresponding negative spreading systems which do not display oil spreading behavior. However, it has not been possible to directly confirm the presence of spreading films in real porous media in three-dimensions and little is understood of the distribution of the phases within the complex geometry and topology of actual porous media for different spreading conditions. This paper describes a preliminary study using high resolution X-ray microtomography to image the distribution of oil, water and gas after tertiary gas flooding to recover waterflood residual oil for two set of fluids, one positive spreading and the other negative spreading, for strongly water wet conditions in Bentheimer sandstone.

We show that for strongly water-wet conditions and a positive spreading system the oil phase remains connected throughout the pore space and results in a low tertiary gas flood residual oil saturation. The residual oil saturation for the corresponding negative spreading system is significantly higher and this is shown to be related to the absence of oil films in this system. The presence of films for positive spreading systems and the absence of such films for negative spreading systems is further confirmed by the computation of the Eurler characteristic for each phase.
Optimization of Production Allocation under Price Uncertainty: Relating Price Model Assumptions to Decisions
Authors: Bukhari A. A. , Jablonowski C. J.
Published: April 2012

Allocating production volumes across a portfolio of producing assets is a complex optimization problem. Each producing asset possesses different technical attributes (e.g. crude type), facility constraints, and costs; In addition to these field-level specifications, there are corporate objectives and constraints (e.g. contract delivery requirements). While complex, such a problem can be specified and solved using conventional deterministic optimization methods. However, there is often uncertainty in many of the inputs, and in these cases the appropriate approach is neither obvious nor straightforward. One of the major uncertainties is the commodity price assumption(s). This paper tackles this problem in three major sections: (1) We specify an integrated stochastic optimization model that solves for the optimal production allocation for a portfolio of producing assets when there is uncertainty in commodity prices, (2) We then compare the solutions that result when different price models are used, and (3) We perform a value of information analysis to estimate the value of more accurate price models.

Price modeling can affect decision-making, but it is surprising to find so little research that relates the price modeling assumptions (model type and the respective parameters) to the decisions that result from their use (capital investment, production optimization, etc.). Instead, we observe countless papers advocating for more and more complex price models, and an equally large body of work where models are estimated and compared for their accuracy. No one appears to have asked the basic question, "Do any of these models provide any incremental value for decision-making?" Here, we address this question by specifying an integrated stochastic optimization model that simulates decision-maker behavior. Using this model, we compare and contrast the various production allocation decisions that result from different price models. Simple price models are investigated and compared to several currently popular advanced price models with the goal of understanding the impact of price model assumptions (both the model type and its parameters) on decision-making. The results show that the optimum production allocation is a function of the price model assumptions. However, the differences between models are minor, and thus the value of choosing the "correct" price model, or similarly of estimating a more accurate model, is small. This work falls in the emerging research area of decision-oriented assessments of information utility/value. We believe it to be the first paper of its kind on this subject in the upstream literature.
Risk Analysis and Economic Evaluation of Oil and Gas Prospects Offshore Uruguay
Authors: Ferro S. , Tomasini J. , Soto M. , Morales E. , Rodríguez P. , Conti B. , de Santa Ana H.
Published: April 2012

Hydrocarbon exploration offshore Uruguay has been historically very limited. Only two wells were drilled in shallow waters in 1976. Additionally, there are about 30.000Km of 2D reflection seismic, including 6.400Km acquired in 2011. ANCAP, the National Oil Company, offered offshore areas for exploration and exploitation of hydrocarbons to interested international oil companies through Uruguay Round 2009. This bidding round successfully ended with the signature of contracts for two areas. This auspicious result, in addition to the interest shown by the upstream industry, have lead ANCAP to launch the Uruguay Round II.

The most recent 2D seismic survey allowed the definition of several prospects. This article presents the risk analysis and economic evaluation of the potential development of three prospects offshore Uruguay, of different type and depth, considering for each one the possible occurrence of dry natural gas, natural gas with condensate or oil.

The Estimated Ultimate Recovery, Net Present Value, Internal Rate of Return and Payout were determined for each prospect by Monte Carlo simulation. Different development concepts were considered for each case. A sensitivity analysis of the key variables (reservoir parameters, hydrocarbons price, capital and operational expenditures) was carried out showing the impact of each variable on the project. Finally, a decision tree analysis was used to compute the Expected Monetary Value of each case, incorporating the geological chance of success and minimum economic field size as inputs for the assessment.

ANCAP signs the exploration and production contracts with offshore Contractors on behalf of the Uruguayan Government, and is in charge of designing the fiscal regime ruling in Uruguay. Thus, this analysis includes the latest and real terms applied in Uruguay Round II, including ANCAP's participation and actual market considerations; consequently it provides a very good estimation of the oil company's take.

This work constitutes the first evaluation of this kind applied to prospects offshore Uruguay, therefore its results and conclusions are significant for those international oil companies that might be interested in carrying out exploration activities in offshore Uruguayan basins.
A Dynamic Simulation Study of an Extra-Heavy Oil Gathering System in the Orinoco Oil Belt
Authors: Brito F. , Rondon L.
Published: April 2012

The Orinoco Oil Belt (OOB) is the world's largest accumulation of heavy and extra-heavy oil with recoverable reserves of 513 billion barrels. It was divided into four production areas: Carabobo, Ayacucho, Junin and Boyaca. Based on that importance for the country's oil production, the use of dynamic flow simulators is becoming more important for the company when it comes to assess the development of such a huge oil deposit.

Currently, in the Carabobo Area, there is a significant uncertainty about the transient behavior of multiphase fluids in the gathering systems, since all studies have been conducted using steady state models. Because of that, there is no a thorough knowledge where there are slug flow formations, the impact of adding new oil production to the current pipeline networks and the transient hydraulics behavior during start-up/shut-in of wells.

This project aimed to build a dynamic simulation model, where several scenarios were established to study the impact on the current gathering system due to changes in flow patterns, additional oil and gas production, start-up/shut-in of wells.

Results showed that the predominant patterns in the system are slug and stratified flows, being the critical area a 5.7 km pipeline at the end point of the gathering system, where there are considerable slug formations. Moreover, with the oil production growth estimated in the short term (2012-2013), the slug flow formations will be reduced slightly; therefore when wells are shut-in the difficulties to transport the fluids are increased considerably. Even though the dynamic simulator underpredicted pressure values compared to real data in approximately 25%, it is possible to use the program as a reference to conduct transient analysis with oil and gas from Cerro Negro Field. This dynamic simulation proved to be a useful tool to analyzed technical and operational problems in an extra-heavy oil field and for the current and future development of the OOB's vast reserves.
BHA Selection and Parameter Definition Using Vibration Prediction Software Leads to Significant Drilling Performance Improvements
Authors: Amorim D. , Hanley C. , Leite D. J.
Published: April 2012

The understanding and mitigation of downhole vibration has been the subject of intense scientific research in the drilling industry in recent years, as inefficient drilling results in slower and more expensive operations. In order to drill ahead, a sufficient amount of energy must be supplied by the rig to overcome the rock strength, the reactive torque of the drilling system, drag forces, fluid pressure losses, as well as the energy lost by way of downhole vibrations.

It has been well documented that downhole vibrations are a significant drain on the amount of effective drilling energy available to the bit. When the drill string enters resonant modes of vibration, not only does the drilling efficiency decrease, but the likelihood of catastrophic drill string component failures increase. The amount of destructive energy expended in these resonant modes of vibration, when left unchecked, may overcome the material limits of components in the drill string. In this sense, the mitigation of downhole vibrations will result in faster, smoother, and cheaper drilling operations.

Software using Finite Element Analysis (FEA) has been developed to understand these vibration phenomena and to predict which combinations of drilling parameters should result in more efficient drilling. The software graphically presents the results, depicting undesired levels of resonant vibration produced with specific drilling parameter combinations, based on the BHA geometry and wellbore design. Predictions made by this software have produced notable results, including a world record for Rate of Penetration (ROP) in the Gulf of Mexico.

This paper also examines different Bottom Hole Assembly (BHA) designs and the resonant vibration modes that may be initiated while drilling, using the proprietary software package. The combination of proper BHA design and the correct selection of parameters results an overall improvement to drilling efficiency. A variety of case studies from Latin America, incorporating the results of the vibration analysis, will demonstrate solid improvements to drilling operations in terms of time and cost savings, increased penetration rates, and improved dull conditions. The use of field validated software for vibration prediction and mitigation has a potential role in the drilling industry as important as the introduction of PDC bits in the 1980s.
Field Application of New Proppant-Detection Technology—A Case History in the Putumayo Basin of Colombia
Authors: Torres F. , Reinoso W. , Chapman M. , Han X. , Campo P.
Published: April 2012

Traditional fracture-height and/or proppant-placement evaluation following a hydraulic fracture stimulation treatment has relied on the detection of radioactive (R/A) tracers pumped downhole with the proppant. While this technique has proven useful, it raises environmental, safety, and regulatory concerns and issues. In some areas of the world, transport and use of R/A tracers is prohibited.

The proppant placement determination method described in this paper eliminates the downhole placement of R/A materials. A high thermal neutron capture compound (HTNCC) is incorporated into a ceramic proppant during manufacturing in sufficiently low concentration that it does not affect proppant strength or conductivity. Proppant is then detected using standard compensated or pulsed neutron tools, with detection based on the high thermal neutron capture of the compound relative to the surrounding downhole constituents.

Two detection methods use a comparison of before-frac log-count rates and after-frac count rates, with reduced after-frac count rates observed in zones containing proppant. Another detection method, especially useful when formation gas saturations change, involves only the after-frac log.

This paper will describe the methodology and results of an application of the new detectable proppant in the T sand of the Villeta and Caballos formations of Juanambú field in the Putumayo basin of Colombia. The results obtained from this novel technology provided the operator an improved understanding of the geomechanical characteristics of the formations and the achieved fracture dimensions. Additionally, this information will help improve future stimulation treatments. This paper should be beneficial to all completion engineers looking for methods to determine fracture height and/or proppant placement in an environmentally acceptable manner.
Successful Implementation of a Relative-Permeability Modifier Along With Hydrocarbon-Based Ultrafine Cement: Case History from Mexico's Offshore Region
Authors: Castillo M. A. , Chacón W. A. , Cancino V. M. , Palomares A.
Published: April 2012

This paper presents a case history of a well in the Ku Field, Gulf of Mexico (Fig. 1) where, for the first time, a water-control treatment combined the use of a relative-permeability modifier (RPM) and a hydrocarbon (HC)-based ultrafine cement slurry. The challenge was to activate the HC-based ultrafine cement before it was lost into a highly conductive channel in a reservoir with high porosity and natural fractures.

The HC-based ultrafine cement is mixed to form pumpable slurry, which is inactive until contact with water. On contact with water, the slurry remains pumpable for a period of time before forming a dense, hard set. The system is applicable for high temperatures up to 400°F. The RPM additives are basically solutions of polymers that act because of their adsorption on the walls of the pores, achieving a reduction in water permeability without damaging the oil permeability.

This paper documents the pumping technique used in the first well in the offshore Mexico region where the water inlet was controlled with a combination of RPMs and HC-based ultrafine cement. After the treatment was applied, water production was cut from 8 to 0%, which has been maintained for more than 3 years. The benefits to the operator are summarized as follows: Because oil from the Ku field goes directly to sales, quality standards are quite strict and wells with water cuts similar to those presented in this study cannot be produced. Applying the water-control treatments outlined in this study has decreased the water cut and thus allowed the wells to continue production.Production could be maintained at a good pace because the choke had to be reduced to control the flow of water.Application of the documented water-control treatment was a lower cost to the operator than repairs using interventions.
Rock Type Modeling: An Effective Method to Determine Reservoir Quality Rock to Discretize Net Pay in Lower Guadalupe Formation, Abanico Field, Colombia
Authors: Betancourt Jose
Published: April 2012

The quality of a reservoir rock is determined, among other factors by porosity, permeability and the connection between the pores, known as pore throat radii. The determination of the values of this last parameter is important for estimating the flow and storage capacity of the reservoir rock. The aim of this study is the determination of quality rock types in the lower member in Guadalupe Geological Formation in Abanico Field. To achieve this goal were identified pore throats radii in 3 cores taken in the central and north area of the Abanico Field.

Winland, the mid-70's, showed a statistical correlation between the optimal flow through the rocks and the radii of pore throats, when 35% of the pore space of a rock is saturated with a phase that does not wet, during capillary pressure test by mercury injection. For his part, Pittman, achievement extends the study of Winland, which development an empirical set of equations, through the use of a system of multiple regression statistical analysis.

This is job was based on Pittman equations. Pittman calculated the pore thorat radii that correspond to the 35 th percentile, which was extended to a spread of mercury saturations percentiles (between 10 and 75%). Using this methodology it was determined that the dominant pore throat radius in the samples studied for the Lower Guadalupe Formation, corresponds to a mercury saturation of 45% (R45). This result is relevant because from of testing was determined the percentage of pore volume that contributes to the flow capacity of the rock and the percentage of pore volume that provides storage capacity.

Integrating the capillary-pressure data with well log information from the production history, it was determined that the hydraulic unit Lower Guadalupe is primarily Macro-porous type with pre throat radii between 2 and 10 microns, with minor variations Mega-porous rocks (> 10 microns), Meso-Porous (0.5–2 microns), Micro-porous (0.1–0.5μm) and Nano-porous (<0.1), allowing the generation of iso-quality rock maps, which show in an areal way, areas with the best thicknesses which are related directly to the production of hydrocarbons in the Lower Guadalupe Formation, being a key parameter in the characterization of rock-fluid system.
Probabilistic Production Forecasts Using Decline Envelopes
Authors: Brito L. E. , Paz F. , Belisario D.
Published: April 2012

One of the most frequently method used for production forecasting is the decline curves analysis, which can be harmonic, exponential or hyperbolic; being the most commonly used the exponential decline curve.

However there are wells that exhibit complex production behaviors, where the exponential decline curve does not fit the entire production history. One of the solutions that have been used is to divide the production history into several segments and then apply different decline factors for each segment. This complex behavior results from a long transient period observed in formations with very low permeability that have been stimulated with hydraulic fractures.

In this paper, we propose an approach that considers a table of time-dependent factors; each factor results from dividing the production rate at time t, q (t), by the initial production rate, q (0), so the production history becomes a profile of factors with values between 0 and 1, which represents more accurately the behavior of the well decline. When this method is used to analyze a reservoir or a field, each well produces a decline profile, and using the information from all wells generates an area in which a profile for each well can be found. This area is defined by two envelopes, an upper bound, representing the most favorable performance, with lower production decline, and a lower bound which represents the worst performance with higher production decline. The upper bound is generated using the maximum function, and then a smooth curve is found with a hyperbolic fit; for the lower bound a similar process is used but using the minimum function. Additionally an average curve is determined.

In order to perform a probabilistic production forecast using these envelopes, a profile is generated within the envelopes using a probabilistic distribution of the ubication. A random value between 0 and 1 is generated and added to the respectives values for each month of the lower envelope, to get a new profile. Using this profile a production forecast can be made and multiple simulations can be performed to obtain a probability distribution curve of all the possible outcomes.
Hydraulic Fracture Geometry Evolution and Pressure During Pumping: Chicontepec Experiences Indicate that Natural Fractures or Fissures Are not Activated
Authors: Luces J. , Salguero J. , Morales J. M. , Riano J. M.
Published: April 2012

Natural fractures exist in many oil and gas reservoirs. The activation of these fractures can have a significant influence on the initial production and the EUR of the wells. It is therefore very important to know whether they are interconnected and their impact on oil recovery, thus optimizing the development plans of the reservoirs. The giant Chicontepec field, located in central eastern Mexico, with 140 billion barrels of oil in place (OOIP), with laminated turbidite sequences, limited lateral extent, low porosity and permeability, very low current recovery, there are natural fractures or fissures. These natural fractures have been observed in many cores, as well as image logs and outcrops. It is considered that the natural fracture system must be analyzed in Chicontepec in more depth and more importantly, the degree of interconnection may have and its impact on oil recovery because it is estimated that may not be effectively interconnected.

Due to the low permeability of the rock, wells are hydraulically fractured. The analysis of the evolution of the pressure at the bottom of the well and or net pressure during a fracturing job is a valuable tool to infer the geometry of the fracture that was generated by the fracturing job. Furthermore, this analysis of the pressure is a powerful tool that can support the identification or existence of interconnected natural fractures and therefore with a certain level of contribution to the producing wells and the recovery of oil from the reservoir.

This report presents the application of the analysis of the evolution of the pressure during fracturing jobs in Chicontepec with examples that allow inferring that the natural fractures in Chicontepec are not interconnected or very little.
Formation Damage Modeling Improves Well Candidate Selection and Stimulation Treatment Design in Western Area of Putumayo Basin, Colombia
Authors: Franco C. A. , García C. C. , Henao W. A. , Zapata J. F. , Ortiz J. C. , Gonzales J. G. , Bahamon J. I. , Madera K.
Published: April 2012

A special engineering methodology was developed to understand the complexity of formation damage mechanism currently affecting the well productivity of the oil fields being operated by SOP (Superintendencia de Operaciones Putumayo) Ecopetrol.

The initial stage of this study involved the characterization and analysis of reservoir fluids samples taken along the time during different exploitation stages. The analyzed data was processed through specialized software to identify formation damage associated with both organic and mineral scales. Simultaneously a second stage was developed to determine and quantify the influence of production parameters on both fines migration and water production.

The data obtained during the previous stages were properly combined to generate a comprehensive formation damage model. Nodal system analysis, material balance, reservoir fluids characterization, and mineral/organic scale models and correlations were finally combined to identify and quantify the main formation damage mechanisms taking place in SOP′s fields.

Once the main formation damage mechanisms were identified and quantified then an extensive lab job was performed. This lab study determined the Best In Class (BIC) fluids required to dissolve and mitigate the formation damage.

The combination of formation damage model with lab data allowed designing an optimized treatment schedule by each well producing in SOP fields. Finally, an economical study was involved in the study in order to help in well prioritization to start the stimulation and inhibition campaign for SOP field.

A 3D simulation of certain formation damage mechanism was included as the final stage in this study. It was very important, especially when optimizing the stimulation-inhibition designs in those wells in which local grid refinement is required to better understanding of certain critical formation damage parameters.

The final list of well prioritization was optimized and stimulation-inhibition campaign for SOP fields was finally outlined to be started during the second semester of 2011.
Comparison between Real Field Data and the Results of Wax Deposition Simulation
Authors: Noville I. , Naveira L.
Published: April 2012

This study used transient simulation to represent the wax deposition phenomenon in the subsea pipelines. The aim was to identify another tool able to estimate the pigging operation frequency to remove wax from wells in which topside arrival temperatures are below the measured WAT (Wax Appearance Temperature). This tool may also be applied to those wells in which data of pressure and temperature, PDG (Permanent Downhole Gauge, installed in the tubing, close to the reservoir) and TPT (Temperature and Pressure Transmitter, installed in the subsea Christmas tree) sensors, are not available.