bluuebunny/crossref_metadata_2025 huggingface dataset:
Probabilistic Determination of Productivity Index for a Horizontal Well in a Heavy-Oil Reservoir
Authors: Lisboa E. A. , Castro M. R.
Published: December 2007

The objective of this study is to determine the minimal well length required to achieve a desired productivity index (PI). It considers the main uncertainties associated to fluids and reservoir properties (vertical and horizontal permeability, net oil thickness and oil viscosity). Monte Carlo analysis is used to consider possible combinations of these parameters and generate probabilistic results.

This study was developed for a heavy oil reservoir. Oil of 15°API or less and viscosities up to 150 cp are expected. The results obtained can be used in the planning phase. The reservoir properties are evaluated initially by a pilot well; afterwards they are estimated along the horizontal length. During the horizontal well drilling, this model can be easily updated. A theoretical model presented in JOSHI (1988) is used to calculate the horizontal well PI. It considers the influence of anisotropy in permeability.

This work is divided in two parts. Initially, a sensibility analysis is performed regarding each uncertainty parameter separately. This first stage is necessary to evaluate the most impacting parameters. The procedure was applied for several well lengths. In a second phase, Monte Carlo analysis is applied, considering simultaneously the uncertainties associated to these parameters. This analysis provided three levels for well PI: pessimistic, most probable and optimistic curves as a function of well length.

This methodology is flexible and, for this practical case, it was implemented through a spreadsheet that comprised the required probability density functions and the Monte Carlo analysis. It can be implemented with other development programs that suit the reservoir engineer. The results obtained can improve the estimates for the performance of the wells and can be used to design adequate horizontal wells for field development.
A World-Wide Economic Analysis of the Non Conventional Supply Based on a Modelling Approach
Authors: Saniere Armeelle , Lantz Frederic
Published: December 2007

The global energy trend forecasts point out an increasing demand over the next decades, especially for electricity and automotive fuel. Over the next 25 years, the growing activity of the transport sector will involve increasing quantities of liquid fuels. On the supply side, the crude oil share in the total primary energy supply should remain to around 35% until 2030. Thus, the non conventional supply, coming from non-conventional oil (tar sands, extra-heavy oil and oil shale) as well as technologies transforming gas or coal to liquids should give a significant and necessary contribution to the global crude oil availability.

We have analysed the potential development of the non conventional supply in a worldwide model which aims to satisfy the oil products demand until 2030. In this analysis, several geographical areas have been distinguished, to take into account the regional dimension of the supply and the demand. This paper is organised as follow: section 1 concerns the resources availability, section 2 deals with the production technologies, ongoing and future known projects, section 3 gives an overview of the modelling approach and, finally, the results are given in the last section.

Heavy crude which often result from a bacterial oxidation of conventional oils inside the reservoir rock, have different physical and chemical properties, generally degraded: they have much higher viscosity, higher heavy metals and higher sulphur and nitrogen contents. Due to those specific properties, their exploitation implies specific methods to extract, transport and transform them into final products. Different categories of heavy crude are usually defined according to their density: -the heavy oils, the API° degree of which is between 10 and 22.3;-the extra-heavy oils and bitumen, the API° degree of which is less than 10. The « in situ » level of viscosity makes the distinction between extra-heavy oils and natural bitumen: -extra-heavy oils have a viscosity smaller than 10 000 centipoises (cP), which means that they are flowing at reservoir conditions;-natural bitumen, also called tar sands or oil sands, have a viscosity greater than 10 000 cP; they are not flowing at reservoir conditions.
A MultiParameter Methodology for Skin Factor Characterization: Applying Basic Statistics to Formation Damage Theory
Authors: Restrepo A. , Duarte J. , Sánchez Y.
Published: December 2007

The following paper describes a Skin Factor characterization methodology that has been developed and successfully applied in fields operated by BP in Colombia, South America. The method is based on basic statistic correlations that are applied for the ranking of different measured or estimated damage parameters; the primary purpose of the method is to weight the different formation damage mechanisms taking place in the complex reservoirs of the Colombian Foothills in such a way that multicomponent skin characterization maps can be estimated. The presence of compositional fluids, active tectonics environments, stacked reservoirs and well access issues all account for the above mentioned complexity.

By the application of this methodology, the design of chemical stimulations has become more efficient as the output of the method, which is a Multi-Parameter characterization of the skin, is available for all the wells; in this manner, stimulation packages include components for the control of the main skin mechanisms in the ratios estimated by the model. The model is being continuously updated through the incorporation of measured and estimated damage related variables such as physical chemical analysis of back flowed samples (after stimulations), output from mineral and organic scaling index estimation models, laboratory studies and well intervention records, among others; all of them taken into account for the entire life of a particular well.

Fed by the Multi-Parameter model, a skin characterization mapping tool has been developed and has become a key input in the periodically reviews of well productivity; stimulation and well intervention options are being efficiently ranked in terms of benefit leading also to a better planning of well work campaigns.
Well Clean up Issues in Field With Sand Coproduction Philosophy in Oman
Authors: Putra Rafliansyah A. , Azkawi Ahmed , Bharti Sanjay , Oyemade Stella
Published: December 2007

The case reservoir is a field in South Oman and produces high viscous oil from well sorted unconsolidated formation sand with a small average grain size (40 microns). Initially the wells were completed with downhole sand control but suffered from extreme plugging due to very fine nature of formation sand.

After performing some trials it was proved that, it is better to produce the wells without downhole sand control. A pre-drilled liner is used for downhole completion and Progressive Cavity Pump is for artificial lift as it is the most sand tolerable available pump.

Sand co-production (i.e. sand removal at surface) is the optimal development for this field. Sand fill up in the well bore however became an issue in the high producers that are impacted by nearby water injection wells. This phenomenon caused a reduction in well productivity. Few methods were trialed to remedy this issue. Sand clean out with a wash string by reverse circulating didn't work because the reservoir is sub-hydrostatic.

Coiled Tubing clean out with foam was trialed but somehow the result was not effective to bring the well back to previous productivity especially on long horizontal wells. The annular velocity was probably not high enough to lift up sand from the well bore.

Concentric Coil Tubing was trialed also which does not require foam or nitrogen for sand clean out. This unit and its special tool (i.e. jet pump) uses water to create a vacuum in the well bore to have fluid return while lifting loose sand or debris to surface. This method bring the well back to its actual productivity when no hard obstruction is encountered during clean out.

This paper presents WRM team experiences in dealing with sand clean out and sand co-production issues.
A Comparison of Methodologies for Handling Produced Sand and Solids to Achieve Sustainable Hydrocarbon Production
Authors: Rawlins C. H. , Hewett T. J.
Published: December 2007

All oil and gas wells produce sand or solids in varying types and amounts. The size and concentration of natural solids (i.e. formation sand) and artificial solids (i.e. workover debris) determine their net effect on production equipment and the resulting management of hydrocarbon production. Conventional exclusion methodology prevents solids from entering the wellbore but may adversely affect inflow production due to skin buildup. Inclusion methodology allows the solids to be produced with well fluids for surface separation and handling. A comparison of the performance, operability, cost impact, and effect on production rate is made for both methods through application examples. The goal is to show that the increased production resulting from allowing solids to be produced in some high sand rate wells allows more sustainable hydrocarbon production with a cost benefit compared to downhole exclusion for certain producing regions.
Economic Evaluation of the Afghanistan Natural Gas Sector
Authors: Cronshaw Mark
Published: December 2007

Gas fields were developed by the Soviets in Afghanistan in the 1960s and 1970s. Gas infrastructure has deteriorated since their departure. There are attractive business opportunities for developing the natural gas sector. This requires simultaneous development of the upstream fields and facilities, downstream markets, transmission and distribution infrastructure, and the legal/regulatory framework governing gas activity.
The 2007 SPE/AAPG/WPC/SPEE Reserves and Resources Classification, Definitions, and Guidelines: Defining the Standard!
Authors: Etherington John R. , Ritter John E.
Published: December 2007

In late 2004, a focused effort was begun to update the 1997 SPE/WPC Petroleum Reserves Definitions and the 2000 SPE/WPC/AAPG Petroleum Resources Classification and Definitions. The evolution of the industry, driven by advancements in technology, the international expansion of the E&P sector and the increasing role of unconventional resources in meeting global energy needs, drove the requirement to update what had served the industry well for the last 10 years.

The 2007 system builds on previous industry efforts to provide sufficient guidance to achieve a high level of consistency in estimating resource quantities; it incorporates best practices identified in other international petroleum and minerals classification systems. It recommends a rigorous approach based on applying a series of defined projects to hydrocarbon-bearing reservoirs. Resource classes are defined according to the maturity of the applied projects expressed as qualitatively or quantitatively as the chance of reach producing status. Within each resource class, the relative uncertainty in the estimated quantities that may be recovered by each project under those conditions forecast to exist during its implementation are denoted by assignment to categories. Assessments may be conducted using deterministic and/or probabilistic methods.

In order to satisfy requirements of the full range of industry stakeholders, the 2007 system introduces additional classification and categorization terminology. The resulting document is a set of technical guidelines that can be adapted by oil and gas companies to better manage their business; moreover, it forms a standard that can be referenced by government agencies in defining reporting requirements.
Computation of Sand Production in Water Injectors
Authors: Vaziri Hans , Nouri Alireza , Hovem Knut , Wang Xiuli
Published: December 2007

A significant proportion of the future oil production is expected to be driven by water injectors and in reservoirs that are sand prone. Achieving sweep efficiency and sand control in such formations is challenging. In many cases the ideal sand control is no sand control (e.g., a C&P completion) requiring rigorous sanding assessment. Sand production in injectors often go unnoticed until it is too late (sand covering the pay) making it difficult to ascertain the specific set of conditions resulting in sanding and the severity of the individual sanding episodes. Based on physics and mechanisms governing sanding, general factors can be postulated on the causes of sanding but not in a quantitative form. To provide a deeper insight into this matter, a numerical study has been undertaken to model sanding in injectors with due account of several inter-coupled factors including injection pressure, crossflow, waterhammer pressure pulses, degradation of the formation matrix resulting from repeated shut-downs and others.

This paper describes the concepts used for sand production modelling and shows application of the model to a field problem involving a C&P completion in a sand prone reservoir. The results show the mode and magnitude of sanding are influenced by the rock properties, injection operations and the equipment type and installation. The cases analyzed indicate a correspondence between the rate of shut-in and the onset of sanding. In cases involving unconsolidated sands, the waterhammer effects have a pronounced impact on sanding. Sand control can be omitted in even very weak rocks provided the injection pressure is optimized, frequency of hard shut-downs is controlled and hardware is positioned in such a manner to reduce the waterhammer pressure pulse magnitude. The proposed modeling can be used in determining the sand sump capacity required over the projected life of the well.
Engineering Evolution for an Effective Zonal-Isolation Process in Production Casings for the Antonio J. Bermúdez Basin in South Mexico
Authors: Cázares Robles Francisco , Corbalá Marco Antonio Corona , Monroy Rafael Rodríguez , Kulakofsky David , Caballero Carlos , Rivera Jorge
Published: December 2007

Oil reservoir depletion resulting from commercial exploitation of mature fields has increased the frequency of special drilling conditions caused by low formation pressures that can lead to massive drilling fluid losses. Several of these challenges have been addressed by cementation engineering, specifically applied to the production casing.

Because of these conditions, the Antonio J. Bermúdez basin has been constantly evolving with regard to cementing technology as well as drilling fluids concerns in an effort to effectively obtain long term zonal isolation.

Application of cementation engineering for production casing in development fields has resulted in the need for low-density slurries that can rapidly develop compressive strength. Furthermore, improvement in rock mechanics understanding using formation-evaluation technologies, has positioned cementation engineering as a technical discipline focused on application of solutions encompassing the entire life of the well. As a result, for example, the concepts of elasticity and durability have become important for cementation engineering, which is now moving far beyond the traditional application of hydraulic principles for slurry design.

This paper describes the evolution and maturing of the Antonio J. Bermúdez Basin during the past ten years and the changes in design and execution of cementing operations as a result of new challenges in oil-based and water-based mud environments as well as the introduction of under-balanced drilling methods.
Analysis of Longitudinal Vibration of Drillstring in Air and Gas Drilling
Authors: Li Zifeng , Guo Boyun
Published: December 2007

Vibration of drillstring has detrimental effects on drilling performance. This type of vibration is much more severe in air and gas drilling than in liquid drilling due to the low damping effect of air and gas. It is highly desirable for drilling engineers to have a reliable mathematical model to simulate the vibration and identify resonance conditions before and during the drilling operations. This paper fills the gap.

Traditionally drillstring vibrations have been analyzed using bit-force as a boundary condition. Accuracy of such analyses is often questionable as the discrepancies have been observed between model-predictions and field data. Mathematical models of longitudinal vibration of drill strings excited by both bit-force and bit-displacement have been established in this study. Equations are solved using the method of separation of variables. Calculations with the solutions indicate that the resonance rotary speeds of drillstring predicted by the bit-force model are non-resonance rotary speeds predicted by the bit-displacement model, and vice versa. A field case study is presented in this paper. Data from a field operation with drillstring failure seems to support the bit-displacement model, not the bit-force model. The models are presented to drilling engineers to further verify their accuracies. Once fully validated, the mathematical models will provide drilling engineers an effective tool for designing drill string for air and gas drilling operations against drillstring failure.
Decision and Risk Analysis Through the Life of the Field
Authors: Paul Hultzsch , Lake Larry W. , Gilbert Robert B.
Published: December 2007

Investing in an oil and gas field is capital intensive and usually involves many risks. Nevertheless, the economic evaluations of these types of investment opportunities often ignore risk or are based on subjective risk assessments that are frequently biased. Furthermore, as the life of the field progresses, well and seismic data become available and the risk level of the project changes. In this paper we demonstrate a decision and risk analysis (DRA) method that minimizes the subjectivity in the evaluation and that can be consistently updated as the life of the field progresses.

We use a tank production model and Monte Carlo (MC) methods to simulate the possible economic outcomes, and ensuing risk, of a primary oil recovery project as a function of the uncertainties associated with the reservoir properties. During the early stages of the field (i.e. pre-discovery) the uncertainty information comes from the analysis of analog fields. In the post-discovery stage, the initial uncertainties are updated with well and seismic data using an application of Bayes theorem.

The method demostrated here gives decision makers a consistent and relatively transparent way to evaluate E&P investment opportunities. It also allows them to track how the risk level of a project changes through the life of the field.
Beyond Portfolio Optimization
Authors: Faya L. C. , Lake L. W. , Lasdon L. S.
Published: December 2007

Methods to obtain optimal portfolios have been used extensively in the financial community for several decades. The first methods were published by Markowitz in the 50's and the literature has been vastly expanded since these days. Most discussions and publications to date have been centered on the methods to perform portfolio optimization. However, the greatest value added by portfolio optimization is not in the optimization itself, but on the use of the results as an aid to decision making. Unfortunately, little research has been done on this behalf. This paper proposes a new approach, and intends to bridge this gap showing concrete portfolio management applications.

Portfolio optimization is not a single event, on the contrary, it is an iterative procedure where the results gathered from each iteration are used to feed the decision making process. After some decisions are made, or company policies established, the process must be repeated to observe the results of the simulation and to provide feedback to the decision making process. This paper describes three portfolio applications that aid corporate decision makers. The first application deals with the effect that production and capital constraints have on the portfolio optimization process. These constraints assist management in the setting of realistic company goals. The second application explains how acquisitions and divestures can be evaluated in the portfolio context, and the effect that those projects have on the company objectives. The third application explains the use of portfolio optimization to manage and drive the company strategy. Using these methods, management could manage acquisitions and divestures in a proactive way, set realistic goals and objectives. As a result, management gain more control and insight over the company future.
Inevitable Disappointment in Projects Selected Based on Forecasts
Authors: Chen M. , Dyer J.
Published: December 2007

Investors often select project whose estimated performance meets or exceeds a hurdle value. At the time of decision making, the true performance of a project is unknown but uncertain forecasts are available. Decision makers (DM) often ignore the prediction errors when they use these forecasts to choose projects. To the disappointment of the DM, many selected projects result in smaller actual yields than the ones that were forecasted.

Some have attributed the cause of this to the optimistic bias of the predictions. This paper shows that this disappointment can occur even if the prediction is unbiased. In this case, a bias can be introduced by the selection process that will allow more unattractive (over-estimated) projects to be accepted than attractive (under-estimated) ones. Although a similar phenomenon has been noted in statistics and finance research, it is not well understood in the context of project selection by decision analysts.

We present a solution method based on Bayesian updating, and demonstrate its effectiveness in eliminating the disappointment in project selection with realistic data from oil E&P projects.
Geosteering Horizontal Coalbed Methane Reservoirs: A Case Study
Authors: Meszaros G.
Published: December 2007

It is well known that horizontal wells provide maximum reservoir contact to optimize production rates and recovery. This holds true for Coalbed Methane (CBM) drilling as well. The direction and position of a horizontal CBM well can be controlled to intersect face cleats and take advantage of directional permeability. In this manner one can stay in zone in CBM drilling just as in other horizontal applications.

The use of at-bit gamma ray and inclination measurements in a Logging-While-Drilling (LWD) tool string greatly enhances the geosteering capabilities of the Bottom Hole Assembly (BHA). The measurements are made in a short sub positioned immediately above the drill bit. At-bit measurements improve directional control in geosteering complex sections. These tools are routinely used in CBM drilling, and other horizontal applictions, to extend the horizontal section within a particular coal seam.

Geosteering requires a software package capable of pre-well modeling, displaying the measured information and interactively adapting the model to the real-time data. Offset well data are used with the well plan for a horizontal well to predict the log response of the different logging tools. Different models can be generated to predict what the log response will be when drilling out of zone either at the top or the bottom, or when dramatic facies changes occur. While drilling, the models are continuously updated and compared to the real-time data to improve the formation model and structure. This allows real-time decisions to modify the well path and stay in the intended zone.

This paper describes the results of drilling horizontal CBM wells. The horizontal drilling includes combining at-bit measurements, LWD resistivity, and forward-modeling software.
Single Point of Initiation, Dual-Fracture Placement for Maximizing Well Production
Authors: Surjaatmadja Jim B.
Published: December 2007

Placement of a fracture in a formation has become a well-understood process in the industry. Recently, this practice was improved by the introduction of a method to properly initiate the fracture into a specific direction using super-high-energy jetting. A drawback of this jetting method though is not knowing exactly where the far-field fracture has gone. Although we know that the fracture will extend in the local minimum-stress direction, it is not known where that direction might be. In all probability, the fracture has gone into a less-than-desired area in the formation, and will result in only an "acceptable" improvement of production.

It was once thought that refracturing merely reopened existing fractures. Recently, however, it has been shown that refracturing can actually create new fractures. In addition, when refracturing causes older fractures to reopen, the results generally show that some new area has been reached by the fracture. It is the opinion of this paper that these new areas are not substantially different from the one reached by the first fracture because local depletion enhances the effects of the original stress regime.

This paper discusses a process whereby fractures are generated in a formation using at least two different fracturing techniques to reach formations in a manner not reached by conventional fracturing alone. In this process, the first fracture may achieve "acceptable" production goals, although the cost may be high. A second fracture is then quickly created to take advantage of the stress modification resulting from the first fracture. This rapid followup fracture is thus able to reach more productive rock not accessible to the initial fracture. Field data supporting the feasibility of this concept will be presented. Various situations where this approach could reap substantial benefits are also described.
Nanotechnology Applications in Viscoelastic-Surfactant Stimulation Fluids
Authors: Huang Tianping , Crews James B.
Published: December 2007

Viscoelastic surfactant (VES) fluids have been widely used in the oil industry as completion and stimulation fluids. The surfactants structurally arrange to form rod-like micelles that increase VES fluid viscosity for regular fracturing and frac-packing fluids. However, high fluid leak-off and low viscosities at elevated temperatures have limited VES fluids for hydraulic fracturing and frac-packing applications.

This paper will introduce a nanotechnology application for maintaining viscosity at high temperatures and controlling the fluid loss of VES fluid, without generating formation damage. The nanometer-scale particles studied display unusual surface morphologies and have high surface reactivity. These nanometer-scale particles, through chemisorption and surface charge attraction, associate with VES micelles to: 1) stabilize fluid viscosity at high temperatures; and 2) produce a pseudo-filtercake of viscous VES fluid that significantly reduces the rate of fluid loss and improves fluid efficiency. When internal breakers are used to break the VES micelles, the fluid will dramatically lose its viscosity and the pseudo-filtercake will then break into nanometer-sized particles. Since the particles are small enough to pass through the pore throat of producing formations, they will be flowed back with the producing fluids, and no damage will be generated. The results of rheology, leak-off and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
Decision-Making Process in Development of Offshore Petroleum Fields
Authors: Deguchi Hayashi Suzana H. , Ligero Eliana L. , Schiozer Denis J.
Published: December 2007

Risk is inherent to all phases of a petroleum field lifetime due to geological, economic and technological uncertainties, which are very significant on oil recovery in development phase, the focus of this work. The acquisition of additional information of uncertain attributes and flexibility during the development are key points to risk mitigation. The Value of Information (VoI) is used to quantify the benefits of new information, giving more accuracy to the project. The Value of Flexibility (VoF) measures the benefits of adding flexibility to the project considering different possible scenarios.

A new and reliable methodology has been proposed to quantify VoI and VoF based on the decision tree technique in order to combine the uncertain attributes. All reservoir models generated by the tree are submitted to parallel simulation and Geological Representative Models (GRM) are selected to represent geological uncertainties. The methodology includes the criteria used for selection of GRM, optimization of production strategies of each GRM considering the gathering of additional information and statistical treatment of the results.

The methodology has been applied in a decision-making process of a giant offshore petroleum field. The field has been developed by blocks due to its physical limitations and intrinsic characteristics and the high investment necessary to develop a giant field.

The contributions of this work are (1) to show the importance of VoI and VoF concepts in decision-making process in petroleum field development and the complexity of this type of decision, (2) to apply the proposed methodology in a giant offshore field modeled by parts, minimizing risks associated to the development of this type of field and (3) to evaluate the importance of the reservoir uncertainties in risk mitigation. An additional important contribution is to present the details of the use of reservoir simulation in the process, trying to obtain the best relationship between computation effort and reliability of the decision making process.
Optimising Diversion and Pumping Rate To Effectively Stimulate Long Horizontal Carbonate Gas Wells
Authors: Liang Jin , Wong Paul , Sinanan Brent
Published: December 2007

Malaysia is a significant gas producer and LNG exporter within Asia-Pacific region. Many of the country's gas fields are offshore carbonate reservoirs. The exploitation of these reserves involves drilling horizontal wells for maximizing reservoir contact and hydrocarbon drainage. Many of these wells experience drilling mud damage. One of the challenges in stimulating long horizontal wells with open-hole completion is the placement of stimulation fluids for effective zonal coverage and generating wormholes to pass the damaged zone.

Placing gelled acid through coiled tubing has been the standard practice to clean up the wellbore. Due to the low pumping rate, stimulation results have been limited. A change was initiated aiming to have the acid pass the damaged zone and generate wormholes through effective diversions.

This paper describes the application of acid/diversion systems and pumping schedules to improve acid coverage. The selection of in-situ crosslinked and particulate diverters through laboratory testing is described as well as the implementation of a unique mixing system. Several case histories are presented illustrating the effectiveness of the fluid systems and mixing process in improving well productivity and job economics.

A stimulation campaign was executed in 2006 to utilize the systems selected in long open-hole horizontal carbonate gas wells. To maximize the results, the following have been practiced: Clean up and test the wells after completion to get initial productivity.Bullheading acid to increase pumping rate.Use a mixing-on-the-fly unit in limited barge space.Learn from previous jobs to improve subsequent ones by optimising pumping procedures.Clean up and flow test right after stimulation to evaluate results.

7 wells were stimulated in the campaign. Significant gain has been achieved through progressively optimising pumping procedures. Indication of diversion was observed compared to previous practices. Stimulation cost is less than that of using coiled tubing.
The Application of Specifically Formulated Bridging Materials To Successfully Reduce Pore Pressure Transmission To Enable Depleted Fractured Reservoirs To Be Drilled and Produced Without Incurring Formation Damage
Authors: Vickers Stephen , Cowie Martin , Burgess Mick , Anderson David
Published: December 2007

There is an increased demand for the design and application of non-damaging fluids in reservoirs that are depleted and susceptible to deep invasion of damaging mud solids. To enable a reservoir drilling fluid to function correctly, it is necessary to very rapidly deposit an external filter cake and reduce filtrate loss to a minimum. The cake must be backflowed in the production phase with minimum liftoff pressure and leave little or no permeability reduction. To achieve this, an accurate description of the pore throats in the reservoir is required. If this cannot be obtained, or the reservoir is at risk to fracture, then another approach is required.

This paper illustrates the methodology of utilizing a variable calcium carbonate bridging distribution mixed with powdered graphite which overcomes the problems of drilling reservoirs with varying pore throats and fractures. The bridging materials will enable an efficient control of filter cake deposition, and also allow for easy disruption of the cake integrity, when the well is back flowed in the production phase.

Results proving the effectiveness of this approach can be shown from return permeametry work in the laboratory, and successful field trials of its application in the Southern North Sea and the Middle East.

The use of these non-damaging products, and the engineered size distribution, will greatly decrease the difficulty at which fractured and depleted reservoirs can be drilled and will not reduce the productivity of these wells, that have in the past experienced formation damage due to deep fluid and solid invasion.
Thermophilic Enzymes for Filtercake Removal at High Temperature
Authors: Cobianco S. , Albonico P. , Battistel E. , Bianchi D. , Fornaroli M.
Published: December 2007

Since developments in the biotechnological field contribute to the implementation of new enzyme breakers for removing polymer damage, significant improvements in well productivity have been proved mostly in horizontal and multilateral wells. Indeed, a delayed clean-up treatment is often required for removing the filtercake after drilling when the drawdown of the well is not enough. Conventional acid treatments promote a rapid, localized reaction resulting in a partial, non-uniform removal of the mud cake. Additionally more and more restrictive regulations push to find less corrosive and more environmentally safe clean-up options including low toxic oxidizing agents and enzyme breakers. Historically, the enzyme's applications have been limited to low temperature treatments due to their pH, salts and temperature concerns. Recently, new temperature-stable, polymer specific enzymes have been isolated and investigated for degrading the polysaccharides (starches and viscosifying agents) commonly used in the Drill-in Fluids.

This paper describes the laboratory evaluations performed on three new enzymes with the aim to develop a non-corrosive clean-up treatment specifically designed for degrading starches, xanthan gum and scleroglucan at temperatures reaching 100°C. Static break tests showed that these polymer-specific enzymes aggressively attack the polysaccharide backbone resulting in a complete break of the polymer. Nevertheless the treatment fluid do not have an immediate reactivity, which might ensure a uniform distribution of the fluid across long pay sections with minimal leak off during placement. Degradation is very effective and the generated fragments are small, soluble molecules. Besides the temperature and pH dependence, the influence of different heavy brines (CaCl2, CaBr2, etc.) on the enzyme activity and salting-out effect were also investigated. The optimal application concentration range for each brine was identified. By coreflooding tests the effectiveness of these breakers in removing the filtercake has been confirmed and the non-damaging properties of the degraded fragments assessed.
The Effects of Acid Contact Time and the Resulting Weakening of the Rock Surfaces on Acid-Fracture Conductivity
Authors: Melendez M. G. , Pournik M. , Zhu D. , Hill A. D.
Published: December 2007

Acid fracturing is a stimulation process in which lasting conductivity after fracture closure is created by uneven etching of the fracture face. The success of an acid fracturing treatment depends on the conductivity created being retained under overburden stress. Fracture conductivity is usually predicted using correlations based on limited tests conducted at low injection rates that may misrepresent hydrodynamic effects that occur in the fracture. We have conducted a new series of acid fracture conductivity experiments at conditions more representative of field conditions to explore the correlation between the experimental conditions and the rock properties with the final conductivity.

In order to reproduce field conditions in the lab, we have used a lab set up properly scaled through matching of dimensionless numbers. Tests were conducted with Indiana limestone, San Andres dolomite, and Texas Cream chalk. A gelled acid system was used with varying contact times. The etched fracture surface was characterized and the rock embedment strength was measured before and after acidizing in addition to standard conductivity measurements for each experiment.

In this paper, the results from a systematic experimental study are presented. Experimental results illustrate that the fracture surface etching pattern is a dominant factor for fracture conductivity. If channels are created, the fracture will have retaining conductivity after closure. Rock strength is another important parameter in acid fracturing. Formations with low initial Rock Embedment Strength (RES) values or a lager reduction in RES after acid injection have lower conductivity after closure. Measurements and analyses of rock embedment strength provide understanding of the conductivity behavior in acid fracturing.

The results of preliminary tests for a North Sea chalk are also presented and discussed in the paper.
Real-Time Fluid Distribution Determination in Matrix Treatments using DTS
Authors: Glasbergen Gerard , Gualtieri Dan , Van Domelen Mary Susan , Sierra Jose
Published: December 2007

In matrix treatments, placement of the injected fluids is essential for success. Over the years, several diversion and placement techniques have been applied to obtain a desired fluid distribution. Real-time evaluation of a treatment was limited to observing injection pressures or bottomhole pressures. These measured pressures provided some information on the diversion process. The application of distributed temperature sensing (DTS) during matrix treatments to monitor the temperature profiles along the wellbore in real time is a recent method to obtain a qualitative indication of the fluid distribution. In this paper, we will discuss whether DTS can also be used to quantify the fluid distribution during a matrix treatment.

For the real-time quantification of the fluid distribution during a matrix treatment from temperature surveys, both real-time read outs of the temperature surveys and an accurate real-time model are needed. With DTS, the real-time read out is a feasible technique that has been developed to present and evaluate the temperature surveys in real time. Further, a coupled wellbore and near-wellbore thermal model is available that runs in real time. This paper will describe these techniques and models and validations using several case histories.

In addition, an analysis of matrix treatments using DTS temperature surveys, where available, will be presented. The models will be used in the analysis to obtain calculated fluid flow distribution. We will discuss how this methodology can be applied in real time and what benefits quantification of fluid flow distribution offers. Further, we will describe what other benefits can be obtained from real-time temperature profiles during stimulation treatments.
An Acid-Placement Model for Long Horizontal Wells in Carbonate Reservoirs
Authors: Mishra Varun , Zhu D. , Hill A. D. , Furui K.
Published: December 2007

In several places around the world, notably the North Sea and the Middle East, carbonate reservoirs are being accessed with very long horizontal wells (2000 to 20,000 feet of reservoir section.) These wells are often acid stimulated to remove drilling fluid filter cakes and to overcome formation damage effects, or to create acid fractures or deep matrix stimulation to enhance productivity. Good acid coverage with a relatively small acid volume is required to economically obtain the desired broad reservoir access.

We have developed a model to predict the placement of injected acid in a long horizontal well, and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion.

We have used this model to simulate treatments that are typical of those performed in the North Sea and in the Middle East. We present a hypothetical example of acid placement in a long horizontal section and an example of using the model to history match actual treatment data from a North Sea chalk well.
Optimized Perforation Tunnel Geometry, Density and Orientation to Control Sand Production
Authors: Zhang J. , Standifird W. B. , Shen X.
Published: December 2007

Destabilization of completed sandstone reservoirs reduces production rates and degrades production equipment. A major cause of such destabilization is perforation tunnel failure, which causes sand production.

Classic mechanically-based sand control techniques are effective, but potentially unnecessary for some reservoirs. Modeling the occurrence and severity of sand production should help identify the most economical pairing of sand control remediation methods with the desired production rate.

This paper examines an advanced technique for modeling such failures, leading to improved drilling and completion practices. In this study, 3D poro-elastoplastic Finite Element Methods (FEMs) are employed to model perforation tunnel stability. Wellbore geometry, reservoir properties, draw-down rate and perforation properties such as tunnel size, spacing and orientation are addressed, with particular attention focused on the transient phenomena near perforations, including stress redistribution and failure development for different perforations.

The results show that stability of the wellbore and perforation tunnel strongly depends upon drilling and perforation directions and perforation shot density. The relationships of the bottomhole flowing pressure, drawdown, perforation orientation, rock strength and in-situ stresses are given to provide optimal perforation for mitigating sand production.
Recent Advances in Deepwater Horizontal Injector Wells Acidizing in Campos Basin
Authors: Pereira Alexandre Z.I. , Calderon Agostinho , Chagas Carlos M. , Pinto Edilson A.
Published: December 2007

In most of its deepwater Campos Basin oilfields, Petrobras' strategy has been to develop the waterflooding systems by using open hole horizontal gravel packing. Both, perforation and gravel packing operations, are only possible by the presence of the filtercake, formed on the formation face during the drilling process. Nevertheless, that film becomes an impediment to injection and must be removed to obtain good injectivity.

Despite the development of special tools that permit to acidize just after the gravel packing operation, there was still a need for reducing the operation time and to increase the damage removal efficiency.

With this purpose, changes were made in the diverting systems to allow each acidizing stage to treat larger intervals, thus reducing the treatment's total number of stages. This improvement was possible by modeling the fluid flow through the tool's perforated extension, which saved 30% of the pumping time.

Parallel to this development, acidizing historical data were revised and filtercake invasion studies were performed. The conclusion was that more aggressive acidizing formulations could be used, what reduced the pumping volume and reduced the job time even further, to about 50% of the previous times.

Post job formation tests performed have shown that not only a job time reduction was achieved, but also, a better formation damage removal.

The good effects observed have resulted in a general review in the design of the horizontal injectors acidizing jobs, improving the operation's safety, efficiency and effectiveness.

This paper will describe the technique, job details and the results obtained for these particular operations.
Formation-Damage Observations on Oil-Based-Fluid Systems Weighted with Treated Micronized Barite
Authors: Kågeson-Loe Nils , Watson Russell , Prebensen Ole Iacob , Van Der Zwaag Claas , Taugbøl Knut
Published: December 2007

A unique oil-based drilling fluid system weighted with treated micronized barite (TMB) slurries has been developed and successfully introduced to the field. The utilization of this weight material provides the fluid system with low viscosity, reduced torque values, superior sag stability thus giving a fluid with low Equivalent Circulating Density (ECD) contribution and excellent hydraulics performance. These exceptional fluid characteristics make the fluid system an excellent solution for drilling sections with narrow mud-weight windows, coiled tubing operations, managed pressure drilling and extended reach drilling. Many of these drilling challenges are encountered in high-temperature, high-pressure (HTHP) and ultra-deepwater field developments and in depleted, mature fields.

Much of the early fluid system development focused on design, the system's physics and chemistry, and the optimization of mineralogy of the weighting agent. Also of concern was the variability of results seen both from return permeability as well as from standard fluid-loss experiments. On this basis a comprehensive study was undertaken to identify and understand the damage mechanisms operating in the formation and filter cake. During this period the fluid system was used in a number of operations in the North Sea such that the current available database includes 5 different types of field applications.

The paper presents the findings of the formation damage study including relevant productivity data from the various field applications. The results demonstrate that while invasion of the formation by treated micronized barite can occur, it does not necessarily lead to permanent productivity impairment. Furthermore, the micronized barite does not interfere with the added fluid-loss-control material over a wide range of fluid densities and formation permeabilities. The authors discuss the processes observed relating them to current field experience describing why the formation damage mechanisms do not concur with previous preconceptions and moreover describes where the limitations of the system occur.