bluuebunny/crossref_metadata_2025 huggingface dataset:
A Macroscopic Method of Measuring Microscopic Scale Phenomena in Porous Media: The Transition Between a Sharp and Diffuse Imbibition Front
Authors: Aminzadeh Behdad , DiCarlo David
Published: October 2009

The efficiency of one fluid displacing another through a permeable medium depends greatly on the pore-scale dynamics at the main wetting front. In particular, the capillary desaturation curve (CDC) shows that with increasing capillary number the residual nonwetting phase saturation (Sor) decreases. This is hypothesized to be a result of the complex dynamics at the main wetting front, which manifests also itself in whether the front is sharp or diffuse. In the sharp front regime, the displacing fluid occupies nearly all the pores and throats behind the main wetting front and the saturation changes abruptly. In contrast, in the diffuse front regime, pores are filled gradually at the main wetting front, and the saturation change is gradual in space. Along with affecting the CDC, the different fronts can greatly alter the relative permeability curves, and the specific trapping mechanisms. Directly measuring the dynamics at the front is difficult. Instead, here we correlate the front dynamics to saturation overshoot, which occurs for moderate to high flux vertical displacements of low density fluid by a higher density fluid in 1-D homogenous permeable media.

We hypothesize the sharpness of wetting front can be explained by competition between two different pore - filling mechanisms (called snap-off and piston-like). The competition controlled by the velocity of the front and thus the injected capillary number. We conduct a series of infiltration experiments to determine the saturation profile as a function of capillary number for seven different fluids. We find that for each fluid there is a capillary number (called overshoot capillary number) below which saturation overshoot ceases and the front is diffuse. We find that overshoot capillary number is independent of the viscosity of the fluid, but does show a dependence on the surface tension. We also find that the fluid's vapor pressure plays no role in the front dynamics. We discuss how overshoot and desaturation have the same overall dependencies, but with critical capillary numbers 2-3 orders of magnitude apart which are most likely due to the lack of initial wetting layers.
Development of a Coupled Compositional Wellbore/Reservoir Simulator for Modeling Pressure and Temperature Distribution in Horizontal Wells
Authors: Shirdel Mahdy , Sepehrnoori Kamy
Published: October 2009

The calculation of production parameters that address multiphase flow in wellbores is challenging. A great deal of research has been conducted to simulate fluid flow in horizontal wells. In most cases, only stand-alone wellbore models for black-oil have been used to simulate reservoir and well dynamics interactions. These models are based on simplified assumptions that lead to unrealistic estimation of pressure and temperature distributions in the well. In addition, most reservoir simulators use rough estimates of perforation pressure as boundary conditions between wellbore and reservoir, and neglect pressure drop in the horizontal wells. A steady-state, non-isothermal, fully-coupled compositional wellbore/reservoir simulator is developed to simulate fluid flow in horizontal wells in conjunction with vertical wells. This simulator is capable of handling concurrent flow of gas, oil and water in both horizontal and vertical wellbores. It can also accurately calculate pressure and temperature profiles, holdup, and component mass-flow rates in wellbores. Our simulation results can explain remarkable differences in flow rate between coupled wellbore/reservoir simulator and stand-alone reservoir simulator at the early stage of production. In this study, variation of liquid fraction along the well is also investigated. Liquid is unloaded in the horizontal well at the early stage of production and then loaded, starting from the upstream of flow, at the late stage of production.
Pros and Cons of Applying Proxy-Models as a Substitute for Full Reservoir Simulations
Authors: Zubarev D. I.
Published: October 2009

This paper presents a comparative study of proxy-modeling methodology (also known as surrogate modeling or metamodeling) as a computationally cheap alternative to full numerical simulation in assisted history matching, production optimization and forecasting. The study demonstrates the solution space complexity for different simulation models and the applicability of the proxy-models to mimic it. Focus is given to the practical aspects of model construction and to the limitations of which engineers should be aware. Results of stochastic optimization driven by full numerical simulation are compared to the proxy-model solutions in order to demonstrate strengths and weaknesses of each approach and determine desirable areas of application.

Several simulation models of different complexity were used to demonstrate the impact of model structure, number of uncertainty parameters and type of problem on simulation model response and on efficiency of proxy-model application. The results are presented for different datasets, proxy-models and simulation model outputs to demonstrate the dependence of the approximation quality on these parameters. The dependence of the proxy-model prediction quality on sampling method, and on uncertainty domain complexity has been revealed. The efficiency of proxy-model application in history matching and production optimization was compared to stochastic optimization with full reservoir simulation.

The results of this study have demonstrated that with increasing complexity of the solution space and number of uncertainties, the application of the proxy-modeling methodology is not recommended for history matching. In the history matching case, the use of full reservoir simulations, combined with stochastic search methods, is preferable and, above a certain level of complexity, the only acceptable solution. Nevertheless, proxy-modeling might be a good approach for certain production optimization projects and appropriate tool for forecasting of Hydrocarbons Initially In Place (HCIIP) and oil recovery (OR).

This study suggests areas of application for proxy-models and full numerical simulation. It addresses pros and cons of both approaches in reservoir simulation and provides advice for their efficient application.
Surfactant Screening for Wettability Alteration in Oil-Wet Fractured Carbonates
Authors: Gupta R. , Mohan K. , Mohanty K. K.
Published: October 2009

Surfactants have been identified that can change the contact angle of an initially oil-wet calcite plate for all four types of reservoirs: low temperature-low salinity (<50 °C, < 3 wt %), high temperature-low salinity (70-90 °C, < 3 wt %), low temperature-high salinity (<50 °C, 4-8 wt %) and high temperature-high salinity. The contact angle was found to decease with the increase in temperature for all surfactants. About 35-70 % OOIP was recovered with most of the screened surfactant in all four regimes. The oil recovery was found to be a gravity-driven process. Rate of oil recovery increases with an increase in the extent of wettability alteration towards water-wet condition, temperature, and fracture density. Increase in IFT increases the oil recovery rate if the wettability can be changed to water-wet conditions and vice versa if the rock remains oil-wet.
New Mixer Optimizes Crude Desalting Plant
Authors: Linga H. , Al-Qahtani F. A. , Al-Qahtani S. N.
Published: October 2009

Saudi Aramco Gas Oil Separation Plants (GOSPs) utilize conventional static mixers (usually globe valves) for mixing of crude with fresh water (wash water) as part of the desalting process. This mixing method often results in consuming high quantities of wash water and chemicals with relatively low mixing efficiency.

In order to optimize GOSPs’ operations, a trial test of a new mixing technology provided by ProPure was conducted at Shedgum GOSP-4 during the period December 2007 – May 2008. The ProPure mixing system technology (ProSalt mixer system) was installed at the inlet line of the desalter in parallel to the arrangement of the conventional mixing valves (three in parallel).

The objective of the test was to evaluate the technology performance and reliability in optimizing desalting processes for Saudi Aramco crude processing facilities. This can be achieved by providing more efficient and effective use of wash water and chemicals while maintaining GOSPs treated crude specifications within Saudi Aramco acceptable criteria which are salt content below 10 PTB (Pounds per 1000 Barrels of Crude) and BS&W (Basic Sediment & Water) below 0.5% by volume.

At the end of the trial test, the Saudi Aramco team evaluated the ProPure mixing technology in comparison to the conventional type and concluded the following results;

Pressure drop across the ProPure mixing system decreased by 60% Wash water rate was reduced by 40% (from 50 GPM to 30 GPM) Oil in water content reduced by 40% The salt content and BS&W have been on spec all the time

The paper describes the mixer concept and results at Shedgum GOSP-4 and further quantifies the implications on installation, treatment capacity and consumables as wash water and demulsifier.
A Hybrid Ensemble Kalman Filter with Coarse Scale Constraint for Nonlinear Dynamics
Authors: Watanabe Shingo , Datta-Gupta Akhil , Efendiev Yalchin , Devegowda Deepak
Published: October 2009

The recent interest in Ensemble Kalman Filters (EnKF) is driven to a large extent by the need for continuous reservoir model updating and uncertainty assessments based on dynamic data. The EnKF approach relies on sample-based statistics derived from an ensemble of reservoir model realizations. Sampling error in these statistics, particularly with the use of modest ensemble sizes, can severely degrade EnKF performance leading to parameter overshoots and filter divergence. However, for computational efficiency, the ensemble size needs to be kept small resulting in spurious sample correlations and loss of geologic realism during model updating. Moreover, facies-based non-Gaussian geologic models and the non-linearity of multiphase flow problems pose significant additional challenges for the EnKF. The EnKF updates are designed to be optimal only for Gaussian priors and linear model dynamics. For multiphase history matching, the posterior distribution will be nonGaussian and the ensemble mean is not a good representation of the central tendency. As a result the EnKF can result in a poor match to the data or unrealistic model updates.

The hybrid multiscale EnKF proposed here provides an improved approach to operational data assimilation problems and tends to overcome many of the limitations associated with the classical EnKF implementation. Our approach combines nonlinear inversion with the EnKF to account for the inherent non-linearities of multiphase inverse problems. Specifically, we update the ensemble mean in a conventional EnKF through a non-linear inversion at selected time intervals and replace the ensemble mean with the ‘posterior mode’ from the inversion. This explicitly recognizes the fact that for non-Gaussian distributions, the posterior mode is a better representation of the central tendency compared to the ensemble mean. Furthermore, the inversion results are imposed on the individual ensemble members via a coarse-scale constraint using a sequential second stage updating in the conventional EnKF and a flow-based upscaling. Our approach ensures that the ensemble members in the conventional EnKF will follow the trajectory of the non-linear inversion within a specified degree of tolerance. This not only allows us to account for non-linearities in the model updates but also prevents filter divergence arising from the use of limited ensemble size. We first illustrate the advantage of the hybrid approach using a synthetic example and present a detailed validation of our results. Next, the approach is applied to a west Texas carbonate reservoir to demonstrate its power and utility for practical field problems.
Simultaneous Interpretation of Pressure, Temperature and Flowrate Data for Improved Model Identification and Reservoir Parameter Estimation
Authors: Duru Obinna O. , Horne Roland N.
Published: October 2009

Permanent downhole gauges (PDGs) provide a continuous source of downhole pressure, temperature, and sometimes flowrate data. Until recently, the measured temperature data have been largely ignored. However, a fine scale observation of the temperature measurements reveals that the temperature signal is not constant but changes with changing flow conditions.

This observation inspired the study of the temperature distribution in the reservoir as a possible source of additional reservoir information beyond that conventionally obtained in pressure transient analysis. As a first step to this problem, a physical model was developed for the temperature profile in flowing and shut-in reservoirs as a function of formation parameters, fluid properties, and flow conditions in space and time. A semianalytical solution scheme, Operator Splitting and Time Stepping (OSAT), was applied to the model and this gave an approximate solution in the form of a convolution integral between a convective temperature term, which depends strongly on flowrate, and a diffusive temperature term. This convolution is also quasilinear between temperature and flowrate measured at the well. The solution matched both field and synthetic data.

In the second step, Bayesian inverse modeling was applied to the problem for the assimilation of pressure and temperature data. This stochastic inverse technique treats parameters as jointly distributed random fields, and yields confidence intervals in addition to best estimates of the parameters. When applied to this assimilation problem, the method allowed for the deconvolution of the pressure and temperature signals, yielding discrete forms of their kernel, which are useful in reservoir parameter estimation and flowrate reconstruction. A useful outcome of the temperature function deconvolution is the ability to generate approximate estimates of the flowrate using temperature signals only. This is a useful in the common situations where downhole flowrate information is unavailable. The Bayesian inverse method was also applied to data denoising in cases where the temperature, pressure and flowrate signals are corrupted with noise. When applied iteratively, the method yielded estimates of the signals that were very close to the true reservoir response. The Bayesian inversion framework also allows also the computation of large number of conditional realizations which are equiprobable solutions given the data and these in turn help give better understanding of the unknown function.
Acoustic Signatures, Impedance Microstructure, Textural Scales, and Anisotropy of Kerogen-Rich Shale
Authors: Prasad Manika , Mukerji Tapan , Reinstaedtler Michael , Arnold Walter
Published: October 2009

Organic-rich shales (ORS) have been studied in detail to understand the provenance and the generation of oil from source rocks. Organic-rich gas and oil shales are gaining importance as unconventional hydrocarbon resources in their roles as source, reservoirs, and as sealing formations. Proven and recoverable oil reserves from these shales account for about 33 trillion tons of shale and 68 billion tons of oil, respectively. However, a successful exploration and production program for these resources requires reliable characterization of the physical properties, maturity, and changes in mechanical, elastic, and flow properties through indirect methods. The seismic properties of kerogen are still poorly understood and so, predictions of kerogen maturity and rock-kerogen systems remain a challenge. Assessment of maturity from indirect measurements can be greatly enhanced by exploiting correlations between physical properties, microstructure, and kerogen content.

In this paper, we analyze possible reasons for changes in impedance microstructure and elastic properties of ORS due to maturity. We have examined scanning acoustic microscopy images to quantify textural anisotropy, size of heterogeneities, and relative acoustic impedance contrast in the images and related these textural properties to maturity and to impedance from ultrasonic wave propagation measured at centimeter scales. This combined study of impedance and microstructures of ORS gives important insight in changes due to kerogen maturation.

We find that Porosity exhibits a first order effect on velocity: in high-porosity ORS, velocity has a direct correlation with porosity.In low-porosity ORS, velocity is directly correlated with kerogen content. The acoustic impedance of an ORS is related to its total organic content and to its hydrogen index (HI).Quantifying microscale impedance texture and contrast in the images allows us to correlate them with larger-scale ultrasonic measurements.Textural heterogeneity, elastic impedance, velocity, and density increase with increasing shale maturity.
Extending the Limit: Interval Pressure Transient Testing in Low-Permeability Reservoirs in the North Sea
Authors: Samuelsen Eivind , Gisolf Adriaan , Seri Gerardo , Eriksen Kåre Otto
Published: October 2009

The use of wireline-conveyed formation testers for sampling, downhole fluid analysis (DFA), interval pressure transient testing (IPTT), and producibility estimation is well established in the oil and gas industry. The increasing demand for hydrocarbons is driving the exploration and production of reservoirs previously deemed uneconomical. The low-permeability limit for such reservoirs is continually being reduced while the limit for reservoir temperature is increasing. IPTT techniques address these trends by extending the limits for high-quality data acquisition.

The decision on whether to perform IPTT requires an estimate of permeability. This estimate usually comes from either pretesting or other well data such as nuclear magnetic resonance (NMR) logs. However, these measurements have a shallow depth of investigation and may underestimate the mobility of the reservoir fluids because of formation damage such as fines invasion, or high-viscosity fluid in the invaded zone. To displace invaded fluids in low-permeability formations can be challenging, usually requiring a high drawdown to pump the mud filtrate and fines from the formation. High-performance packers and pumps are essential in such environments that require a large number of high differential-pressure cycles.

In this paper three case studies of IPTT in low-permeability reservoirs in the North Sea are presented. In the first, pretesting with a single probe and dual-packer indicated a tight formation (no fluid communication between the tool and formation was established). IPTT was attempted and fluid moved at a drawdown of around 80 bar. The subsequent influx of formation gas reduced the drawdown significantly and a large increase in mobility was observed.

In the second tight gas case study gas influx was detected, but because of the large drawdown the gas compressibility prevented a large-volume cleanup and the test was aborted. This case shows the limit of what is achievable in this environment.

The third case study illustrates a very low-permeability limestone that was straddled with a dual-packer-standard-probe testing configuration. The downhole pump was equipped with a high-pressure displacement unit (DU). This pump configuration handled the high initial drawdown required to clean up the damaged zone. Initial cleanup pumping was followed by 30 hours of producing time and then a final pressure buildup. The result was a high-quality estimate of deep formation properties and fluid samples with very low contamination levels. A lesson learned was that formations considered "tight" according to data available before formation testing may be productive and capable of flowing hydrocarbons when evaluated with IPTT. Compared with the cost of a drillstem test (DST) in low permeability conditions, the dual-packer tool provided a fast, cost-efficient, and flexible way of testing individual zones.
Non-Retrievable Rotating Liner Drilling System Successfully Deployed to Overcome Challenging Highly Stressed Rubble Zone in a GOM Ultra-Deepwater Sub-Salt Application
Authors: Kunning Jim , Wu Yafei , Thomson Ian J. , Marshall Larry , Daigle Derrick , Mata Henry J. , Pena Robert , Hensgens Matt , Eppley Billy
Published: October 2009

Worldwide drilling and exploration activities offshore in deep and ultra-deep waters have increased significantly in the last few years. Many of the most attractive prospects are sub-salt or near-salt environments in the Gulf of Mexico (GoM), Brazil, and West Africa.

Operators are always looking for ways to reduce risks and maximize value in these extremely high-cost environments. Highly technical challenges include: drilling through depleted formations, lost circulation zones, weak formations, rubble zones, and tar/bitumen intervals. When encountered, these hazards lead to a significant increase in nonproductive time (NPT) and ultimately to significant financial losses.

This paper presents some of the geo-mechanical drilling hazards encountered in an ultra-deepwater well in the GoM Walker Ridge area, the impact of those hazards to the drilling operation, and the outcome of the deployment of a non-retrievable rotating liner drilling system. This drilling system, in conjunction with a specially designed liner drilling PDC bit, enabled operators to drill through and isolate a challenging highly stressed rubble zone found adjacent to a problematic tar/bitumen layer.

The result of this successful deployment and the high deepwater drilling operating costs show the tremendous potential to deliver value by providing a simple proven solution that saves drilling time and cost when in a hostile environment. Before running the liner drilling system, nonproductive activities accounted for a total of 26 days. These included attempts to overcome unexpected issues associated with a severe tar attack, and sidetracking the well, which represented millions of dollars in losses to the operator.

A successful liner drilling system solution was crucial, and it enabled the operator to finish the well and hit the proposed pay zone. Without the success of this operation, it is likely that an extra string of liner would have been required and that the operator's final objectives wouldn't have been achieved.

Casing and liner drilling has demonstrated to have the potential in a wide variety of other offshore areas where similar hazardous environments may be encountered.
Data, Information, Knowledge, Wisdom: Shaping E&P World
Authors: Lyadina-Saville E.
Published: October 2009

Modern measurement systems for E&P applications produce overwhelming amounts of raw data often facing limitations of storage, transmission, analysis, interpretation and decision making. Rational assessment of information content at each stage of measurement, processing and interpretation is necessary for optimization of data flow. Analysis of data evolution and its nature along the information pyramid becomes of primary importance in E&P applications.

We performed an information-theoretical analysis of various types of data available in E&P applications, in their evolution from raw Data to Information to Knowledge to Wisdom as defined by Ackoff hierarchy (DIKW).

Our analysis is applicable to broad range of E&P information systems for MWD, LWD, wireline and other tools.

DIKW hierarchy is the way from ‘know nothing’ (data) to ‘know what’ (information) to ‘know how’ (understanding) to ‘know what is best’ (wisdom). This is the class of models for representing structural and functional relationships between data, information, knowledge, and wisdom, where the later is understood as ability to increase effectiveness and add value. Evaluated understanding (wisdom) is the only stage of DIKW evolution dealing with the future; this is the tool for decision making. We describe how such mathematical and computational techniques as data mining, data compression, filtering, pattern recognition, classification and clustering operate within DIKW information pyramid. In addition to classic Ackoff information model, we explore its various modifications, which include feedback loops. Such feedback from the stage of evaluated understanding (wisdom) to information stage is useful when solving inverse problems common in E&P applications. Evaluated understanding (wisdom) provides ‘what is best?’ answer acting as prior information for solving an inverse problem. We give examples of DKW evolution for various MWD, LWD, wireline data systems and Reservoir Management. These examples are based on publications stored in SPE e-library – the invaluable tool for information exchange between E&P professionals. Conclusion: Analysis of DIKW hierarchy is the effective tool for designing optimal measurement, processing and interpretation systems for oil and gas industry.
A Unified, Multidisciplinary Approach to the Planning and Design of Deepwater Waterflooding Projects
Authors: Chaban Fady R. , Sharma Mukul M. , Suri Ajay , Gibson Grant
Published: October 2009

Today and in the future many of the deepwater projects in the Gulf of Mexico and elsewhere around the world will be producing under waterflooding conditions to increase hydrocarbon recovery and support reservoir pressure. The success of the water injection program is critical to the overall project economics. As such a clear methodology, workflow and attention to detail are needed in the planning, design and implementation of these projects.

This paper presents an integrated and practical approach for implementation at the Front End Engineering Design (FEED) stage of a project to optimize the future field development strategy, injectors design, facilities planning, and to maximize the total value of the asset. The proposed method efficiently interconnect elements related to surface facilities, topsides process, subsea architecture, subsurface equipment, water quality, well completion, down-hole flow controls and target injection rates in a common context.

The workflow consists of coordinating the diverse elements of design in the project: facilities design (pump requirements and water treatment options), topsides-subsea network flow design, injector, drilling and well planning, and critical data gathering. Results of the studies to be conducted will provide reliable estimates of well injectivity, fracture lengths under different injection scenarios, the impact of thermal stresses on injectivity and fracture growth, injector completion design, surface injection pressure requirement, and subsea-subsurface flow parameters. The development of a comprehensive model incorporating these elements subsequently allows the evaluation of the major factors that can impact the fracture length, bottom-hole and surface injection pressures based on: injection rate and temperature, water quality, reservoir pressure, Young's modulus, absolute and relative permeability to water, and rock thermal coefficient for diverse completions types. Ultimately, a robust design of the waterflooding project with long-term water injection is obtained.

This methodology plays a crucial role guiding the planning, design, evaluation and development of the details and specifications for the water injection system. The output generated helps to improve overall field understanding, utilizing and linking valuable information and technologies that are available to the subsurface and topsides design teams. Likewise, this approach represents a tool to solve technical and business challenges associated with waterflood project design.
Changing Selection Concepts: True Optimization of Drill Bits with Latest Generation Rotary Steerable Systems
Authors: Barton Steve , Pierce Garrett , Stroud Daryl
Published: October 2009

Use of Rotary Steerable Systems (RSS) has steadily increased since their introduction in the mid-1990's. Improvements in durability, reliability, and operator familiarity, have moved these systems further into mainstream drilling use around the globe. However, the large majority of footage drilled with RSS is with side force (Push) tools. These tend to require some degree of sidecutting, thus utilize drill bits that have specifically engineered cutting structure, profile, and gauge design to achieve this. Due to common availability of this type of bit design, plus extensive experience with operators, they are often also utilized on the growing number of Point RSS. Due to the significant difference in operating mechanism, these bit designs can be poorly suited, resulting in sub-optimal drilling performance.

This paper describes a joint engineering approach in developing specific drill bits for the latest generation of RSS that utilizes point-the-bit technology. The project has included systematic testing at a purpose-built, full-size drilling test facility. This has enabled a direct comparison of the directional response, hole quality, and drill string vibration to be made for the various combinations of drill bit and RSS configurations tested. The testing and subsequent field performance has led to development of specified characteristics of the drill bit for optimal performance. To ensure consistent and accurate matching of the bit to this specific RSS, an interactive, intranet tool was developed. This software incorporates logic regarding tool operation and assesses these against key characteristics of the bit including length, profile, gauge geometry, cutting structure, and sidecutting capability. This allows the ideal design to be rapidly identified, particularly as some characteristics are not visible within the visual geometry of the bit.

Several case studies are documented that clearly demonstrate that the correct matching of drill bits to this specific Point RSS has delivered improved drilling efficiency with excellent directional control.
Solid Paraffin Inhibitor Pumped in a Hydraulic Fracture Provides Long-Term Paraffin Inhibition in Permian Basin Wells
Authors: Smith Tony , Szymczak Steve , Gupta D.V. Satya , Brown J. Mike
Published: October 2009

In a novel chemical technology development, a robust liquid paraffin inhibitor is adsorbed onto an inert solid matrix. This solid fits within the size distribution range of a 20/40 proppant. As a manufactured product, the solid composite holds sufficient paraffin inhibitor to provide more than one year of continuous paraffin inhibition in the subject wells.

Five wells have been treated since November 2007 by including a solid paraffin inhibitor composite with the proppant during a hydraulic fracture. These include rod-pumped and electric submersible pump (ESP) wells. The wells produce oil, gas and water and oil production have ranged between 50 – 300 BOPD (barrels of oil per day). The traditional treatment approach for paraffin inhibition for similar wells includes continuous downhole chemical injection, batch treatment with a paraffin inhibitors or paraffin inhibitor squeezes. For paraffinic wells that still precipitate paraffin despite chemical treatment, it is common to remove accumulated paraffin by circulating hot water or hot oil in the well.

To be effective and economic, a solid inhibitor composite must have two critical characteristics. First, it cannot adversely affect the fracturing fluid or proppant pack, thus calling for extensive fluid compatibility, crush and conductivity testing. Secondly, it must perform to inhibit paraffin deposition for a period of time deemed to be cost-effective. Chemical effectiveness is measured in the lab through comparative pour point tests, cold finger deposition tests and through field observation history, e.g. the ESP's pulled for maintenance reasons show no sign of paraffin deposition unlike untreated offset wells. To date, except for a problem due to the loss of power in the field the operator reports paraffin deposition-free production.

Operator lifting cost is a function of lease expenses and oil production. When a well fails due to paraffin deposition the operator incurs a cost of remediation and a loss of production. By placing an inhibitor in the fracture, the paraffin is inhibited in the formation, at the perfs and in the tubulars. The cost of the inhibitor is more than justified by the savings in operational costs and the value of continuous and increased oil production.
Low Pressure System for Gas Wells: Do We Need It? How Low Should We Go? A Compression Strategy for Tight Gas Wells in South Texas
Authors: Bui Quynhthy , Harms Larry , Munoz Efren , Becnel Joe
Published: October 2009

In a large field with thousands of wells of different ages and qualities, determining the optimum operating pressure is a challenging task. This study looks at the Lobo Field in South Texas which has approximately 1800 tight gas wells currently in production to determine the effect of pressures on recovery and the benefits vs. costs of compression. Wells were divided into 3 groups that share similar characteristics and modeled using the integrated production modeling tools to evaluate recovery vs. line pressure. Results show that the better wells can produce longer in a high pressure system before loading up and needing lower pressure, therefore, cost of compression per unit volume is lower. Wells with lower reserves do not stay in the intermediate pressure gathering system long before needing low pressure, thus for these wells the fuel savings from having an intermediate pressure system does not offset the cost. Well head compression is only attractive for the better wells.
Role of Failure Mode on Rock Cutting Dynamics
Authors: Block Gareth , Jin Howie
Published: October 2009

Rock cutting leads to a combination of brittle and ductile failure, and each failure mode has a different effect on drilling efficiency and the morphology of cuttings produced while drilling. A commercial, two-dimensional Discrete Element Method (DEM) code was used to investigate the link between cuttings morphology and downhole conditions using a single polycrystalline diamond compact (PDC) cutter. The methods described here differ significantly from previous studies in that grain-level forces were spatially averaged to determine the rate of energy dissipation within the rock volume during the entire cutting process. Stress-space methods and plasticity theory were then used to calculate the total energy lost due to brittle and ductile failure modes separately. Results indicate a direct and quantifiable relationship between confining stress, down-hole pressure, drilling efficiency and a transition from chip-like to ribbon-like cuttings morphologies.
Predicting Flow Profile of Horizontal Well by Downhole Pressure and DTS Data for Water-Drive Reservoir
Authors: Li Zhuoyi , Zhu Ding
Published: October 2009

Downhole pressure and temperature data are important information to help us understand the bottom-hole flow condition. The data today are readily available from permanent monitoring systems such as downhole gauges or fiber optic sensors. In previous study we have showed that using temperature and pressure data, water entry along a horizontal wellbore can be detected by a semi-analytical model. Flow in the wellbore is well-defined but flow in the reservoir is described by a single phase, one-dimensional model. The assumptions limited application of the model for mostly a single-phase condition

In this paper, we present an improved model that is more flexible. We use streamline simulation method to solve the flow problem in the reservoir for fast track of reservoir flow. We developed a transient, three-dimensional, multiphase reservoir thermal model to calculate reservoir temperature. We integrated the reservoir flow model and thermal model with a horizontal well temperature model to predict the pressure and temperature distribution in a horizontal well system. We apply the model to a synthetic example. The example is an infinite water-drive case. The results of simulation show that the temperature features in a horizontal well can successfully detect the location and amount of water breakthrough. Meanwhile, even the pressure trend does not reflect the water entrance as clear as temperature curve, its value of easily indentify the reservoir permeability distribution is very helpful in temperature calculation. We apply the model to a field case - a horizontal well in the Sincor Field for heavy oil production. The results showed that we can successfully identify where and how much water entering the horizontal well in this field example.

We use an inversion method to interpret the pressure and temperature data to obtain flow rate profile along horizontal wells. The inversion method is the traditional Markov Chain Monte Carlo (MCMC) method. This stochastic method searches the possible solution in the parameter space and use the Metropolis-Hastings algorithm to judge the acceptance. We discuss how to reduce the parameters to make the inversion method work more efficiently according to the downhole pressure and temperature data.
Acid Re-fracturing: Is it a Good Practice?
Authors: Pournik M. , Mahmoud M. , Nasr-El-Din H. A.
Published: October 2009

The success of acid fracturing depends on the conductivity created and retained under closure stress in addition to the length of conductive fracture. Majority of acid fracturing treatments show a sharp decline in conductivity with increasing closure stress with almost no significant conductivity after a short production time. As a result, many wells are re-fractured in order to restore back to the original productivity after the initial fracture. However, the success of these re-fracture treatments has been diverse with respect to extent of stimulation. The effect of re-fracturing on acid fractured wells has not been studied and the conditions that result in success or failure of re-fracturing operations are not understood.

An experimental study was conducted to investigate the effect of re-fracturing on already acid fractured cores exposed to closure stress. Indiana limestone cores were acidized with a typical acid system of 15 wt% HCl acid viscosified with a polymer under typical field conditions. After the first acidizing process, conductivity measurements were conducted on acid-etched core faces up to a certain closure stress. While the fracture was kept under the closure stress, a re-fracturing treatment was conducted under the same conditions as the initial acidizing. The re-etched fractures were once again placed under different levels of closure stress and conductivity measurements taken at each stress. Experiments were conducted under different conditions of leak-off, polymer concentration and closure stress after the first acidizing in order to determine influence of these parameters on the re-fracturing conductivity.

Acid re-fracturing enhanced fracture face etching, while significantly increased fracture conductivity under closure stress. However, leak-off, polymer concentration, and closure stress did influence the degree of success of acid re-fracturing. The refractured sample with leak-off and lower polymer concentration resulted in the most enhanced fracture conductivity in comparison to the initial acid fracturing process.
Qualification Testing Towards Utilizing an In Well Flow Meter for Production Optimization and Allocation in Nigeria
Authors: Ong J. Tim , Meinert David , Oyewole Anthony , Blowers Michael , Thomson Russell
Published: October 2009

The Agbami project offshore Nigeria uses a suite of production monitoring, control and optimization tools and techniques. The project uses an intelligent well completion whereby production and injection is optimized from the well through the relevant time feedback of information from downhole pressure, temperature gauges and flow meters. A downhole interval control valve provides the capability to control production and injection, thus maximizing the recovery of hydrocarbon from the field.

The field consists of both injection and production wells. Oil production is from multiple zones, which are co-produced into the wellbore. Due to the complexities of the subsea production and injection manifold and riser configurations, downhole flow meters are used for production and injection allocation purposes for the different formations within the reservoir.

Agbami Field utilizes an in-well flow meter. The technology is based on a differential pressure full bore electronic flow meter which is first in the industry. The sensors utilized are high resolution pressure and temperature sensors. In order to demonstrate the robustness and the capability of the flow meter for production and injection allocation purposes, a series of flow loop qualification testing have been designed. One of the tests used a mixture of oil and water in a test facility to demonstrate the capability of the flow meter to accurately measure oil and water production. This test is probably the first of its kind using a test structure over 100 ft in height.

The paper will outline the aims, the preparation requirements, the conducted test and the resulting qualification testing. It will also demonstrate how the results will assist in the production allocation and optimization of recovery from the field. Through this testing, the operator demonstrated commitment to the intelligent well completion initiative as well as the provision of an accurate method of allocating production using in-well flow meter and pressure and temperature gauges.
Increased Production Through Microseismic Monitoring of Hydraulic Fracturing Over a Multiwell Program
Authors: Barker William
Published: October 2009

Surface based microseismic monitoring enabled an E & P company to optimize their hydraulic fracture treatments. This case study covers a six well program, consisting of 25 stages with 84 hours of continuous microseismic monitoring. The first part of the program consisted of stimulations in three vertical wells. This part of the program provided information indicating fracture orientation and lateral extent of the asymmetrical hydraulic fractures. This was then used to design optimal spacing and fracture design of the stimulations in the remaining three horizontal wells. The common fracture azimuths are 320° +/− 10° and 40° +/− 8°. More complex multi-stage stimulations in the horizontal wells showed microseismic activity growing before the proppant injection with a significant fracture half length. However, microseismic activity occurred near the wellbore during the mid and late portion of the proppant injections indicating the bulk of the proppant load was delivered near the wellbore. High initial post-stimulation production with a rapid decline was observed, supporting this interpretation. This led to the redesign of the fracpack treatment using smaller proppant sizes resulting in larger fractures and more productive wells. We also estimated a stimulated reservoir volume for each stage. The data were then combined into a table for reference, along with aerial extents of activity for the six wells. The microseismic activity then increased with more optimized treatments. We show that generally the production of each well is proportional to the stimulated volume. These results have given the operator an insight to the fracture orientation, and fracture effectiveness of 25 individual hydraulic fracture treatments.
Rapid, Interactive Assessment of Petrophysical and Geometrical Effects on Density and Neutron Logs Acquired in Vertical and Deviated Wells
Authors: Heidari Zoya , Torres-Verdín Carlos , Mendoza Alberto , Ijasan Olabode , Voss Ben , Preeg Bill
Published: October 2009

Borehole, geometrical, and petrophysical effects can significantly affect density and neutron logs. Tool location around the perimeter of the borehole, tool standoff, and wellbore deviation have a measurable effect on density and neutron logs, hence on the estimation of porosity and fluid density. It is difficult to diagnose and quantify these effects a priori without numerical modeling. The multiple-particle, radiation-transport Monte-Carlo code (MCNP) has traditionally been used by the logging industry to simulate borehole nuclear measurements acquired in complex rock formations. Despite its versatility and accuracy, MCNP is not numerically efficient for rapid simulation of nuclear logs and does not lend itself to interactive testing of multiple petrophysical/fluid hypotheses.

We describe the successful application of a new method for nuclear-log simulation based on linear iterative refinement of nuclear sensitivity functions pre-calculated with MCNP. The procedure is fast, accurate, and efficient in most practical logging applications, including the simulation of nuclear logs acquired in invaded formations and in highly-deviated wells. Density and neutron logs acquired over a depth segment of 1000 ft can be accurately simulated within minutes of CPU time, compared to days with MCNP. Simulations are successfully verified against MCNP in a number of extreme cases of borehole, petrophysical, and fluid conditions wherein the error of the simulations does not exceed 2 porosity units.

We implement the new simulation method to reproduce several field examples where logs are affected by presence of clay and invasion with water- and oil-base muds. Our rapid simulation procedure enables the interactivel quantification of the relative effect of clay, invasion, fluid density, and rock petrophysical properties on field logs. It also permits efficient integration with induction resistivity measurements for assessment of free and clay-bound water saturation, as well as for the assessment of residual hydrocarbon saturation. Additional simulations of density and neutron logs are performed to quantify the influence of shale laminations on hydrocarbon-bearing and invaded thinly-bedded formations. Because of their longer radial length of investigation compared to density logs, neutron logs may exhibit false cross-over effects across thin beds.
A Placement Model for Matrix Acidizing of Vertically Extensive, Heterogeneous Gas Reservoirs
Authors: Nozaki M. , Hill A. D.
Published: October 2009

A critical issue in matrix acidizing of vertically extensive carbonate reservoirs is the acid distribution along the wellbore. This estimation is very important especially for the case where the reservoir properties (permeability and damage distribution) vary along the wellbore. Several acid placement models for oil reservoirs have been developed and applied in the field successfully. However, when evaluating acidizing in a gas well, the models are not adequate because of the viscosity contrast between the reservoir fluid (gas) and the injected fluid (acid) and because of relative permeability effects. We have developed an acid placement model for acid injection into vertically extensive gas wells in heterogeneous carbonate reservoirs that includes gravity segregation in the wellbore, viscosity contrast, relative permeability effects, and a wormhole model. The effects of all of these factors on the local injectivity during acid injection are incorporated into a dynamic skin factor model.

To test this new model, we analyzed coreflooding data in the literature. The analysis showed that the differential pressure across a gas saturated core did not linearly drop during acidizing, but instead increased during a large part of the acid injection period. From this analysis, we determined that the pressure drop in a spent-acid zone ahead of the wormholes dominates the overall pressure drop behavior.

Applying this model to typical field conditions, we find that a natural viscous diversion takes place in heterogeneous gas reservoirs because of the viscosity contrast between the gas and the injected acid. In particular, we have modeled thick carbonate gas reservoirs having a few thin, very high permeability thief zones. Before wormholes break through the damage zone in the high permeability parts of the reservoir, this viscous diversion effect distributes acid more uniformly than expected. However, after wormholes break through the damaged zone, thief zones will take a large portion of the injected acid. Another important prediction with this model is that the injection pressure often increases during acid injection into gas wells. Without an understanding of the role of mobility contrast on the injection pressure response, operators may incorrectly conclude that the injected acid is not stimulating the formation.