bluuebunny/crossref_metadata_2025 huggingface dataset:
Acid Stimulation of Extended Reach Wells: Lessons Learnt From N'Kossa Field
Authors: Mazel J. M. , Poitrenaud H. , M'Bouyou P.
Published: December 2007

N'Kossa is an offshore field located 60 km west of the coasts of Congo in water depths of 170 m. The field is producing light sweet oil from an Albian age reservoir buried between 3100m and 3400m TVD. In order to access reserves located in the southernmost compartments of the reservoir, Extended Reach Drilling (ERD) was implemented. Six ERD wells have been drilled to date with lateral extensions close to 6500 m leading to total depths sometimes in excess of 8600m. In addition to the challenges pertaining to the drilling itself, the completion also carried its own ones as the formation would require effective acid-stimulation (not only an acid wash) to reach the desired levels of productivity. Stimulation of long intervals, and how to ensure full coverage of treatments is a recurrent topic of debate, several approaches have been discussed in the literature. In the particular case of N'Kossa, this issue was not only rendered difficult by the length of the perforated intervals (up to 1200m) but also derived from the combination of lithology and permeability contrasts existing in the formation: indeed the reservoir is an alternation of rather tight carbonates (with permeabilities as low as 1 mD) and porous sandstones (which permabilities sometimes reach up to 400mD). The contrast in permeability is unfavorable as the high permeability layers are often encountered at the heel of the drains. Finally, the reservoir temperature is 150°C (300°F), leading to the need for retarded acid systems.

Building on the experience acquired from the successive treatments performed on N'Kossa, the methodology and treatment design, fluids and diversion have been continuously evolved. The treatments currently involves two phases: An injectivity initiation is performed via Coiled-Tubing creating an artificial thief zone at the toe of the well; then a massive treatment based on emulsified acid and ball-sealer diversion is bullheaded from a stimulation vessel.

This paper will discuss design considerations and operational aspects of the acid treatments performed of these ERD wells. We will discuss some of the observations made and present lessons learnt from such treatments.
Laboratory Assessment of Drilling-Fluid Formation Damage in Sandstone Cores and Mitigation With Lignite Additives for High-Temperature Fields
Authors: Kelessidis V. C. , Marinakis D. , Tsamantaki C.
Published: December 2007

This paper describes first results of an extensive laboratory research program aiming at identifying potential additives for bentonite suspensions which would extend their use at high temperatures by maintaining or even improving the rheological and the filtration characteristics of these fluids.

Five different Grrek lignites have been tested, at 3% wt. concentration, together with a commercial lignite product, used as reference. API filter press data and rheological data showed that thermal aging of bentonite suspensions results in deterioration of rheological and filtration properties while lignite addition was very beneficial.

Static filtrations tests against Berea sandstones have been performed using a core holder and the various mud formulations. Pressure ports along the core holder allowed determination of permeability evolution during testing of the formed cake as well as of the core itself. A backflash arrangement allowed for determination of permeability recovery.

Thermally aged muds reduced significantly core permeability and gave recovery rates around 50%. Three of the lignite samples, have maintained original core permeability giving also very high recovery rates. Some of the lignite samples, including the commercial one, did not perform as well and also gave permeability recoveries between 10 to 80%. Thus, static filtration against cores allows for differentiation of well performing lignite samples not only in API filter press tests but also in core permeability experiments.
Robust Recovery of the Filtration Function for Flow of Water With Particles in Porous Media
Authors: Alvarez Amaury Cruz , Hime Gustavo , Marchesin Dan , Bedrikovetsky Pavel
Published: December 2007

Models for deep bed filtration during the injection of seawater with solid inclusions depend on an empirical filtration function that represents the rate of particle retention. This function must be calculated indirectly from experimental measurements of other quantities. The practical petroleum engineering purpose is to predict injectivity loss in the porous rock around wells. This phenomenon is studied in laboratory injection tests, where the effluent particle concentration is measured over time.

We presented in a previous work1 a method for determining the filtration function from these measurements. In this work, we improve on this method introducing a data preprocessing technique which makes the algorithm robust, and present numerical results with data which could not be treated before. The main purpose of this paper is to present this complete method for the solution of the inverse problem of determining the filtration function in the classical deep bed filtration theory from injected and effluent particle concentration measurements.
Modeling and CT-Scan Study of the Effect of Core Heterogeneity on Foam Flow for Acid Diversion
Authors: Farshbaf Zinati F. , Farajzadeh R. , Zitha P. L. J.
Published: December 2007

We present a new 2D analysis based on the recently developed stochastic bubble population foam model, focusing on the effect of the core heterogeneity. In the frame of the model presented in a parent paper in the conference, we assume that the bubble generation kinetics is dependent on layer permeability. We present experiments consisting of co-injection of N2 gas and surfactant solution in layered cores, with layering parallel and to the flow directions. The cores are obtained by combining two porous media chosen from Benteimer and Berea sandstone and sintered glass, with large permeability contrast. X-ray computed tomography (CT) scans are used to visualize and quantify local fluid distributions and differentiate foam propagation in the different layers. From both the model and the experiments we conclude that foam is primarily generated in the high-permeability layers, where it propagates at a much higher speed than in the low permeability layer. The propagation of foam in the low permeability layer requires that the pressure gradient is higher than the capillary entry pressure for the layer. The new stochastic population balance foam model reproduces rather well the main features of foam motion in heterogeneous cores containing a surfactant. Core floods combined with CT scan imaging provide valuable specific information about the effect of heterogeneity for better design of acid diversion operations.
Optimizer's Curse: Removing the Effect of this Bias in Portfolio Planning
Authors: Schuyler John , Nieman Timothy
Published: December 2007

Even with unbiased judgments and project calculations, an insidious bias will still be present in an approved projects portfolio. The screening and ranking process used to select projects causes an optimizer's curse effect (Smith and Winkler, 2006). A portfolio's true outcome value will tend to fall below the forecast distribution mean. Stated another way, we should expect to be disappointed in the value of the eventual outcomes. This optimizer's curse effect can be huge: the true portfolio value might be half its forecast value when forecast in the usual way.

This paper describes a correction process based upon Bayesian inversion obtained with Monte Carlo simulation. Estimate/Actual distributions characterize component evaluation errors. The mean and standard deviation of the E/A distribution measures the quality of judgments and estimates. Examples demonstrate the value of better information in project or asset evaluation, portfolio optimization, and competitive bidding.

The premise of our approach to correct for optimizer's curse is straightforward enough, though implementing this method requires judging the population of evaluated projects—or at least assessing the shape of this population's distribution. We offer a process and guidelines for correcting for the optimizer's curse in both project and portfolio value calculations. Correcting estimates for systematic biases restores luster to the recommended expected value-maximizing decision policy. We also tie-back to the winner's curse (Capen, Clapp and Campbell, 1971) experienced in competitive bidding and how it affects bid optimization.
Field-Data-Based Prediction of Well Productivity Decline Due to Sulphate Scaling
Authors: Bedrikovetsky P. G. , Monteiro R. P. S. , Daher J. S. , Gomes J. A. T. , Amorim V. C.
Published: December 2007

The system where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation. We derived an analytical model-based method for determination of kinetics and formation damage coefficients from production well data consisting of barium concentrations in the produced water and of well productivity decline.

We analyse production data for five scaled-up producers from giant offshore field A, submitted to seawater flooding (Campos Basin, Brazil) in order to predict productivity index and to plan the well stimulation program. The wells are completed by gravel packs. Complete mixing of sea and formation waters in production well neighbourhoods in the reservoir under consideration was assumed in previous works. Using this assumption, quasi steady state model for reactive flow around production well is formulated. We obtained values of the two sulphate scaling damage parameters. The two coefficient values were used for prediction of productivity decline for these wells.

Both coefficient values as determined for five wells are inside the variation intervals for scale damage coefficients obtained from coreflood data. It allows concluding that the productivity damage in wells under investigation was caused by sulphate scaling and validates the mathematical model. It also permits to perform a reliable prediction of well productivity. The values for kinetics and formation damage coefficients as obtained from well and laboratory data are recommended for use in reservoir modelling of sulphate scaling.

Sulphate scaling can have a disastrous impact on oil production in waterflood projects with incompatible injected and formation waters. This is due to precipitation of barium / strontium sulphate from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity.
Incorporating Geomechanics into Petroleum Reservoir Numerical Simulation
Authors: Rodrigues L. G. , Cunha L. B. , Chalaturnyk R. J.
Published: December 2007

There is currently a need in rock engineering for a coherent approach, which allows the identification and incorporation of the important parameters and mechanisms for any rock engineering activity. This is the case of reservoir numerical simulation studies of oil/gas recovery strategies in which geomechanical effects play an important role on the underlying physics of the recovery process. For example, during the depletion phase or the cold-water injection of high-pressure/high-temperature reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, improvement of natural fractures, induced fracturing, and fault activation, which continuously modify the reservoir properties such as the porosities, the permeabilities and the fault transmissibilities. Modifications of such parameters strongly influence the flow pattern in the reservoir and ultimately the final recovery factor. In this work, a methodology is developed which enables the incorporation of key mechanisms and parameters to solve a numerical reservoir simulation problem that considers geomechanical aspects. The proposed technique utilizes an iterative-coupled reservoir-geomechanical modeling approach to capture the link between flow and in-situ stresses. In a validation stage, results from the coupled model are compared to ones obtained from a classical simulation approach (constant rock compressibility model). The usefulness of technique developed here is illustrated for reservoir performance forecasting of a giant Brazilian deepwater oilfield producing by water injection. The solution achieved to the real case problem revealed important geomechanical features that must be considered in complex oil exploitation project scenarios in which limited information and production uncertainties are present.
Modeling Rapid Multiphase Flow in Wells and Pipelines Under Nonequilibrium and Nonisothermal Conditions
Authors: Michel Guillermo , Civan Faruk
Published: December 2007

An improved mathematical model considering the nonequilibrium and the non-isothermal effects involved during rapid multiphase flow in wells and pipelines is presented. The extent of the non-equilibrium effect on deviation from the equilibrium model predictions is delineated under prevailing flow rates, fluid saturations, and temperatures. Applications for three-phase (oil/water/gas) systems are presented. The model presented here can be coupled with reservoir simulation for accurate representation of the well-fluid hydraulics and simulation of flow conditions in pipelines under nonequilibrium and non-isothermal flow conditions.
Estimation of Reserves Using the Reciprocal Rate Method
Authors: Reese P. D. , Ilk D. , Blasingame T. A.
Published: December 2007

In this work we develop, validate, and apply the "reciprocal rate method" to estimate oil reserves using only rate-time production data. This approach requires the development of boundary-dominated flow, and can be used to validate reserve extrapolations from numerical/analytical reservoir models. The methodology does presume that flowing well bottomhole pressures are approximately constant — but we will demonstrate that the method is tolerant of substantial changes in the flowing bottomhole pressure.

This approach requires a plot of the reciprocal of flowrate (1/q) and the so-called "material balance time" (cumulative production/flowrate or Np/q). The "secret" to this approach is the use of material balance time — this function accounts for most variation in rate/pressure, and permits the extrapolation of the 1/q function.

This methodology has been applied for oil wells (including oil wells with high water production) — and in all cases, the reciprocal rate method has proven to be robust and consistent.

The primary technical contributions of this work are: Direct method to estimate reserves using only rate-time data (time, rate, and cumulative production).The reciprocal rate method is based on variable-rate theory, and is more rigorous than Arps approach (exponential or hyperbolic rate relations).
A Numerical Two-Phase Flow Model Coupling Reservoir and Multisegment Horizontal Well
Authors: Gui Ping , Cunha L. B. , Cunha J. C.
Published: December 2007

To simultaneously simulate the flow behavior in the reservoir and horizontal wellbore, it is necessary the developing of a coupled model integrating both reservoir domain and horizontal wellbore domain. This paper investigates the transient flow behavior of horizontal wellbore and reservoir using a two phase coupled model. All the variables for both reservoir and wellbore domains are solved simultaneously, so that the results can reflect the flow characteristics and interactions between the reservoir and horizontal wellbore. The results show that the proposed coupled model can reveal the finite conductivity features of the horizontal wellbore. The influx and its effect are actually non-uniform distributed. A case study was conducted and analyzed in this paper.
A Probabilistic Approach to Shale Gas Economics
Authors: Gray William M. , Hoefer Troy A. , Chiappe Andrea , Koosh Victor H.
Published: December 2007

Unconventional resource plays, and shale gas plays in particular, are generally characterized by lower geologic risk and higher commercial risk. Large, continuous accumulations of tight, often naturally-fractured shale serve as both a hydrocarbon source and a potentially-productive reservoir. The likelihood of commercial production is a primary uncertainty in these plays, resolved in part by drilling pilot (appraisal) wells. The need to understand the range of potential for commercial realization places a heavy burden on the economic evaluation process. This requires maximum insight into the basis for a decision to pursue or not pursue any particular shale gas resource play. Beyond this, a consistent approach to economic evaluation is of critical importance when comparing the economics of various plays. Without consistency, comparison of multiple shale gas plays becomes extremely difficult, if not impossible.

The ability to define and represent key uncertainties and understand their respective impacts on economic feasibility is vital to play entry and subsequent decisions involving continued investment. Issues such as well design (vertical, horizontal, multi-lateral, etc.), well performance (initial production rates, estimated ultimate recovery, etc.), stimulation technologies, commodity price environments, as well as commercial aspects such as acreage availability and cost, project execution timing, and rig count are critical. Furthermore, because there are few well-established commercial plays, analogs are constructed mainly from these data-bearing plays; e.g. Fort Worth Barnett, and applied to emerging or prospective plays. Uncertainty surrounding the technical or commercial fit of a given analog for new basins/plays must be accounted for in the play/project evaluation process.

Pioneer focused on a number of domestic shale plays that differ in many ways, most notably in terms of "the stage of commercial maturation." Due to the large number of unknowns, deterministic economic modeling gave the team a low confidence in the results and was viewed as merely a scoping indication of commercial potential. It was recognized by the team and by management that deterministic, single-point solutions are unable to provide a reality check for the input assumptions, which typically leads to overly optimistic results. Therefore, it was determined that these models, while good for quick scoping evaluations, would be inappropriate for decision-making in emerging plays. A better solution had to be found.

This paper describes a consistent, systematic process employed in the evaluation of a number of shale gas plays, how various software applications were deployed, the vital role of multi-disciplinary participation, iterative modeling efforts and conclusions. In a general sense, we believe the lessons learned here can be applied either to unconventional or conventional upstream oil and gas projects.
Stochastic Modelling of Shale Gas Resource Play Economics
Authors: Stabell Charles , Gonzales Rosella , Langlie Espen
Published: December 2007

Unconventional petroleum resource plays present unique assessment challenges. These large, single accumulations cannot be counted and analysed as discrete entities that are delineated by down-dip water contacts. Equally important, the main assessment challenge relates to exploitation risks and uncertainties. This paper presents an integrated stochastic assessment framework for decisions related to shale gas resource plays. The shale gas resource play is modelled as a set of discrete cells that have not been explored (exploited) and that have the potential for economic production. The distinctive aspect of the modelling tool is the use of stochastic simulation to calculate the risks of failure in either the exploration, the appraisal/pilot, or the exploitation phases of the project on the basis of both sub-surface uncertainties and above-surface activity performance, cost and duration uncertainties. The tool also generates stochastic performance metrics that capture alternative outcome scenarios, economic returns and the delivery schedule of production and reserves. The performance metrics support both project-level and portfolio-level decisions related to unconventional resource plays. Project-level application is illustrated using data from a Canadian shale gas resource play.
Stacking Seismograms to Improve Microseismic Images
Authors: Shemeta J. E. , Maxwell S. , Warpinski N. R. , Quimby S. , Riebel T. , Phillips Z. , Kinser J. R. , Hinds G. , Green T. W. , Waltman C. K.
Published: December 2007

Microseismic mapping's primary limitation is its viewing distance which is affected by noise, attenuation, and the intrinsic size of the source event. In the Rocky Mountains the required viewing distances are often less than typical offset-well spacings, making accurate mapping difficult in many fields. A new approach to improving microseismic mapping capabilities is to digitally stack the signals from separate adjacent receivers to obtain noise cancellation. This approach requires large numbers of receivers and fast telemetry rates to obtain the necessary data. An experiment has been conducted in the Uintah basin with a 12 level receiver array in which 3 of the 12 levels consisted of triple receiver stacks. The improvement in the signal quality consists of reduced noise, improved hodogram linearity, and clearer phase arrivals. The subsequent microseismic maps using stacked data are both more accurate and contain more events that can be analyzed.
Refracture Treatments Proving Successful in Horizontal Bakken Wells: Richland Count, Montana
Authors: Lantz Tom , Greene David , Eberhard Mike , Pershall Richard
Published: December 2007

The Bakken reservoir development in Richland County, eastern Montana, has been a center of activity and has received significant attention in the industry since the first horizontal well was completed there in 2000. For one operator the initial completion program utilized cemented liners in the laterals in wells oriented to promote longitudinal hydraulic fractures. As discussed by Wiley, et al.,1 radioactive tracer logs indicated that there were often significant intervals, especially in the heel section of laterals that were not stimulated using this technique.

In late 2003, one operating company decided to attempt a refracture treatment in a well that showed long lengths of unpropped interval based on its tracer log. The approach was to emulate the completion technique then in use on new wells with uncemented liners. The result from this first refracture treatment was encouraging with a peak post-refracture treatment production rate in excess of the peak production rate after the original completion stimulation. As a result of this success, a refracture treatment program was initiated.

To date, all but one of the initial cemented liner wellbores have had refracture treatments pumped into them. The overall result has been an increase of over 1,300,000 stock tank barrels (STB) in the estimated ultimate recovery (EUR) for the wells in this program. Results showing the improved coverage from tracer logs will be presented along with examples of pre- and post-treatment production curves.

Over the course of this refracture treatment program, the fracture treatments have evolved. Treatment size has remained the same; however, the method of pumping the treatments has changed. This paper discusses how the refracture treatments were pumped and the results of the program.
Improving Reserves Estimates From Decline Curve Analysis of Tight and Multilayer Gas Wells
Authors: Cheng Y. , Lee W. J. , McVay D. A.
Published: December 2007

Decline curve analysis is one of the most commonly used techniques to estimate reserves from production data. In tight formations that have been stimulated, especially when there are multiple layers that communicate only at the wellbore, the uncertainty in reserves estimates from this technique is quite large because forecasting future performance is quite difficult. This uncertainty can affect the classification of reserves, and could limit what we should call "proved developed reserves." In this paper, we present new procedures to mitigate the complexity of decline curve analysis in multilayer tight gas wells. Using synthetic and field examples, we demonstrate how reserves can be estimated more reliably.

For tight and multilayer gas wells, it is not uncommon that decline curve analysis yields an Arps decline-curve parameter ‘b’ larger than 1. Single-layer hydraulically fractured tight gas wells also appear to have b values greater than one. Different practices are used to handle such complexity. For forecasts, some analysts simply use the ‘b’ value obtained from matching production data, while others force the ‘b’ value to be 1. Still others use the hyperbolic decline and the matched value of ‘b,’ but, when the decline rate reaches a predetermined limit, they switch to exponential decline for the remainder of the forecast. Thus, forecasted performance differs significantly when different analysts analyze the data. Consequently, the reserves estimate has large uncertainty, which can, in turn, affect its classification.

In this paper, we first present an in-depth investigation of decline behavior of tight, single-layer and multilayer gas wells by analyzing depletion characteristics using simulated data sets. We illustrate the long-duration transient effects present in single-layer stimulated tight gas wells and the complex flow regimes present when wells in layered reservoirs are produced commingled. Our work indicates that, as observed in field data, transient effects and coexistence of different flow regimes between layers lead to abnormal decline behavior (b>1.0) in multilayer tight gas wells, which leads to errors in production forecasts. Our new procedure provides a method to minimize these errors.
Investigation of Water-Coning Phenomenon in Iranian Carbonate Fractured Reservoirs
Authors: Namani M. , Asadollahi M. , Haghighi M.
Published: December 2007

The water coning caused by the imbalance between gravity and viscous forces is the most important reason for water production in different fractured reservoirs. There are various controllable and uncontrollable parameters affecting this phenomenon. In this study different dynamic models were constructed to search for the key parameters affecting the coning process in both single-well and Cartesian multi-well models.

It has been determined that oil layer thickness, perforation thickness, fracture permeability and its orientation, especially horizontal not vertical fracture permeability, production rate, mobility ratio, and fracture storativity have the major role in water coning phenomenon. Also it has been determined that fracture spacing, aquifer strength and skin factor have insignificant effect on water coning in fractured reservoirs. The variation of water breakthrough time respect to each effective parameter has also been studied. We concluded that for any production program or adjusting the wells location, the parameter study is very important.

Multi-well studies using an Iranian fractured reservoir data show that the trend of dependency of water coning on each parameter is similar to the single-well model. However, in field scale, it is necessary to have all reservoir data including well location, and production history for a successful water coning simulation because a small pressure drawdown exerted by a far well will affect the cone shape and its breakthrough time.
In Situ Gelled Acid as a Diverting System in Water Injection Well
Authors: Miniawi Mohamed A. , Ahmed Wael A. Fattah , Ahmed Yaser Ali , Soufi A. Rahman
Published: December 2007

The formation damage of water injection wells reduces the ability of the injected fluids (water) to flow through the formations in order to maintain the reservoir pressure and sweep the oil to producer, therefore it is common use the acid to remove theses damages and enhance well injectivity.

This paper describes the successful job in one water injection well in Libya by using an In-situ gelled acid as a diverter with acid treatments to remove formation damage and improve permeability along the whole interval.

The water injection well was suffering high skin damage along 27 ft of the total 42 ft interval; the remaining 16 ft took the entire volume of the injected water. The objective of the treatment was to remove the damage and improve the permeability in the damaged zone.

Use of the In-Situ gelled acid was decided to block temporary the high permeable zone and allow the regular acid to create worm hole in the damaged zone.

The In-situ gelled acid is tested at the laboratory before performing the job. The polymer was cross linked at pH 2 and the sudden rise in viscosity was to about 1000 m Pa S (cp).

The design, quality control and results are detailed in this paper.
Innovation, Who Pays—Making the Economic Case for Adopting New Technologies
Authors: Kozicz John
Published: December 2007

Since the early 1980's hydrocarbon finding and development costs measured in $/BOE declined steadily reaching a low in the mid 1990's. This improvement in Capital Efficiency was driven by the adoption of technologies such as PDC bits, improved drilling fluids, and dual activity rigs, which help reduce costs as well as technologies such as horizontal drilling, and advances in well completion technologies which significantly improved well recovery. Additionally, advances in seismic and other exploration technologies significantly improved the exploration success rate and hence increased reserve additions.

However, since the mid 1990's finding and developing costs have been rising steadily as the rate of discoveries and additions in mature basins decline and fields become smaller resulting in higher costs as more wells and infrastructure are required to exploit these reserves. Furthermore exploration and production activities have moved to ever more demanding regions such as deepwater offshore, and harsh environment areas such as the Arctic requiring ever more costly wells and infrastructure to develop resources in these areas.

Technological innovation drove the improvement in capital efficiency realized during the 1980's and early 1990's. Since then the pace of technological innovation has slowed due in part to the desire to minimize technical and commercial risk as exploration and development activities move to these more demanding environments. The consequence of this is deterioration in capital efficiency. In particular the efforts to control costs have created barriers to the development and application of new drilling technologies which could significantly reduce the current 25 – 30% non productive time experienced drilling wells today.

This paper discusses a phased approach to technology evaluation, development and adoption which seeks to minimize the risks, both technical and economic associated with applying new drilling technologies or innovations.
Minimizing the Risk of Well Collisions in Land and Offshore Drilling
Authors: Poedjono B. , Akinniranye G. , Conran G. , Antonio T. San , Phillips W.
Published: December 2007

Today's increasingly complex and crowded drilling environments have placed a greater emphasis on wellbore collision avoidance. The safety and financial implications of shutting in production on platforms or repairing damaged wells have established a need for the industry to evaluate the potential for collision with a producing well. This paper will describe an effective approach to evaluating, minimizing and mitigating these hazards, and will include a number of case studies illustrating the successful application of this approach in the field. This paper, the latest in a progressive series will detail the importance of gathering appropriate data—such as completion type, offset surveys, well pressures, casing depths, reservoir fluids and mud densities—and analyzing this data to accurately assess potential collision risks.

Each well and field poses different challenges; not all data is available and wells can vary from simple vertical land wells to crowded offshore and fishbone designs. The well position uncertainties are determined by using survey error models from the Industry Steering Committee on Wellbore Survey Accuracy. This method was chosen because it is an industry-recognized standard of defining the magnitude of survey uncertainty. Recommendations for minimizing risk are based on the status and conditions of the adjacent wells and the nature and severity of the risks associated with a collision. These recommendations are formulated to minimize the risk while ensuring that production is disturbed as little as possible.
A Dynamic Maximization Model for Exploration and Development Efforts in a Petroleum Field
Authors: Marques J. B. , Trevisan O. V. , Suslick S. B.
Published: December 2007

Many works on dynamic models for the maximization of the Net Present Value (NPV) on upstream projects have been published in recent years, originating in the academy as well as the industry. These models usually treat the effort considering either the exploration stage or the development stage of the petroleum field, but not both together. This paper will investigate of the optimum net present value in the upstream project considering both exploration and development efforts simultaneously. This model will enable to address some of the following question: (a) What is the optimum exploratory effort for a petroleum field? (b) What is the optimum time span which the exploratory efforts deserve investment before the beginning of the development stage? (c) What is the appropriate value of the reservoir recovery factor? The maximization of the NPV is represented by an objective function. The influence of the parameters in the estimation of the proposed objective function is shown by means of sensitivity analysis. Among the companies in the world exploring petroleum, several do not usually adopt a methodology combining the exploration and development efforts. Filling this gap in the methodology is the main motivation for this work, which intends to disseminate the use of the combined model in the analysis of the economic viability project of the upstream area.
An Innovative Approach to Uncertainty Assessment of Hydrocarbon Estimates in Fluvial Systems: A Case Study
Authors: Al-Khalifa Mohammad A. , Payenberg Tobi H. D. , Lang Simon
Published: December 2007

A novel method was developed and applied to a fluvial reservoir for the uncertainty assessment of hydrocarbon estimates related to geological input. Uncertainty assessment is a crucial step in any volumetric study, because it exists in all variables used to estimate hydrocarbons originally in place. Conventional volumetric estimation methods such as Monte Carlo simulation and curve decline methods do not consider the uncertainties in depositional facies proportion.

Monte Carlo simulation is a powerful tool in measuring uncertainty in hydrocarbon estimates. Monte Carlo models can be easily built and run extremely fast. The output results can be examined visually as well as statistically. However, the main drawback is the absence of any geological knowledge in the simulation process. The geological knowledge comes from different sources such as drilled cores, wireline well logs, facies maps, modern and ancient analogues and most important of all it grows with the geologists experience. This knowledge is currently employed in the stochastic modeling process only.

The new method presented here merges stochastic facies models with the Monte Carlo Simulation method to produce geological driven volumetrics (GDV). The stochastic facies models are built based on different facies proportions associated with their respective uncertainties. Facies volumes were extracted from the different stochastic facies models and were used as a geological input into the Monte Carol simulation algorithm to generate GDV estimates. Using the GDV method gave hydrocarbon estimates that were higher in volume and had less uncertainty compared to the Monte Carlo Simulation and the stochastic modelling method. The Stochastic modelling method is much more time consuming, for uncertainty assessment because it requires running hundreds of stochastic realisations, while the layout of the GDV is equally as efficient as a Monte Carlo Simulation.
The Effect of Fluid Saturation Profiles on Three-Phase Oil Relative Permeabilities and Oil Recovery
Authors: Mahmud Walid Mohamed
Published: December 2007

Network models are often used to predict oil, gas and water relative permeabilities and residual saturations. It was recently shown that most previous network model calculations involving significant numbers of double-displacement events were invalid because of material balance errors1.

The current study used a model that conserved oil, gas and water volumes. The model accounted for heterogeneity and the snap-off displacement mechanism. Gas injection followed waterflooding to displace the remaining oil saturation. The remaining saturations were a function of the level of snap-off events that occurred during waterflood imbibition. The model was used to study the effect of the fluid saturation profiles at the end of waterflooding on three-phase oil relative permeabilities and oil recovery from a subsequent gas flood.

The level of snap-off events during waterflood imbibition displacement significantly affected the remaining oil and water saturations before gas flooding. This, in turn, affected three-phase oil relative permeabilities and recoveries. Residual oil saturation to gas flood increased with increased remaining oil saturation following waterflood. Introducing spatial and local correlations significantly increased oil, water and gas relative permeabilities and reduced remaining oil and water saturations.

Oil relative permeability was found to be a function of both oil saturation and the oil remaining after waterflood. Gas and water relative permeabilities were only functions of their respective saturations.
Real-Time Onshore Control Center Enables Offshore Personnel Reduction in Coiled-Tubing Managed-Pressure Drilling Operation
Authors: Geddes Martin , Deady Andy , Speagell Mal , Fernandez Raj
Published: December 2007

One of the main constraints facing many offshore platforms is the shortage of accommodation. The balance between continuing field development and maintaining existing production and platform integrity inevitably requires a compromise in the crew allocation for well engineering activities.

This paper will discuss the challenge faced on Shell’s Gannet Alpha platform in conducting a coiled tubing managed pressure drilling (CTMPD) operation with a 20% reduction in crew numbers over the previous CTMPD operation. The key enabler of this reduction was the use of a supplier’s established onshore control centre located in Norway for remote support. A two-way real time data connection from the platform was established that allowed two key roles to be removed from the platform – drilling data acquisition and quality control, and control of a dynamic annular pressure control system.

This implementation of remote support was unique as the main drilling supplier not only used this facility to reduce his rig-site presence but also facilitated other third party suppliers to remotely operate their equipment by providing space and IT infrastructure within the facility.

As well as the principle benefit of reducing personnel on board required to run the CTMPD, additional benefits were realised through the dissemination of real-time data throughout the operator and supplier organisations. By utilising the WITSML data protocol, the operators reservoir model and well-planning programs were populated in real-time enabling subject experts to participate in the decision making process. Additionally, onshore technical support and engineering personnel were able to utilise the two way connection to access the offshore systems in real-time in order to troubleshoot problems, perform software upgrades and carry out diagnostics on surface hardware and downhole tools as required.

This paper will describe the upfront preparation both in terms of the IT infrastructure and the personnel multi-skilling. It will then describe the ways in which the data was transmitted and used during the operation, and the contingency procedures that were developed in the event of loss of communication. Finally, the future of real time operations will be discussed and how the learnings from this operation can be used in the ongoing development of this technology.
First Field Applications of Microflux Control Show Very Positive Surprises
Authors: Santos Helio , Catak Erdem , Kinder Joe , Franco Emmanuel , Lage Antonio , Sonnemann Paul
Published: December 2007

After a series of successful tests conducted at a research facility for a vertical well using full scale equipment, the Micro-Flux Control (MFC) equipment was taken to its first field applications to begin exploring the performance of the system under actual drilling conditions. These conditions include the presence of cuttings in the return fluid and effects of pipe movement; neither of which could be tested at the research facility.

The accuracy of the MFC had been demonstrated for both WBM and OBM at the research facility, detecting influxes and losses at very low volumes. The first two field wells drilled confirmed the accurate measurement capabilities and showed additional and unique information in terms of flow and pressure.

This paper describes the first two wells drilled with the system. The first was a shallow exploratory well for Petrobras in Brazil using WBM (1824 ft drilled and 3018 ft TD). The second well, drilled for Chevron in Texas using OBM was a development well in a challenging area with ROP approaching 300 ft/hr (2587 ft drilled and 13,000 ft TD).

The system proved to be capable of being used on a wide variety of rigs; whether conventional, without any automation or sophisticated controls and employing a kelly; or latest generations, with fully automated controls and employing a top drive.

The results to be presented include the summary of the planning, the challenges and problems targeted, preparation of the wells, rig up of the equipment, and the results. Among data disclosed is the influence of pipe movement, accuracy of the flow measurements under various conditions, and identification of drilling related problems using the various parameters collected. Several influxes were detected along the well and positively confirmed when gas reached surface. The influx detection data was analogous to the mud logging data.
Underbalanced Drilling Technology for the Exploration of Tight Sands in the Neuquen Basin: An Evaluation of Results from 11 Wells
Authors: Garcia Daniel G. , Moreyra Juan D.
Published: December 2007

The objective of this paper is to summarize the future application, limitations, advantages and disadvantages of UBD technology, based on eleven wells that were drilled in this type of reservoir.

The geographic location of the wells is the Center of the Neuquen Basin, located in the state of Neuquen, Argentina. The objective was to define the reliable range of the stratum flow capacity value or permeability, in order to forecast the reservour productivity with UBD Technology, assuming the absence of formation damage (skin).

The method used was based on the transient-state production equation theory. Implementation was based on the drilling hydraulics design: maintaining constant Pwd close to the reservoir of interest formation pressure; stopping drilling to allow the development of transient production; establishing drilling conditions and detecting the production contributions in new stratums to be evaluated; determining the average production; correlating detected inflows with the pressures obtained by formation testing.

The method, together with other data, allowed us to estimate the structure potential productivity, despite the poor petrophisycs characteristics (Tight gas reservoirs) and to demonstrate that the results during completion could give reliabie properties estimatations used in the forecast.
Combining a Mechanical and Chemical Solution to Mitigate Corrosion in MPD/UBD/Air Drilling Operations
Authors: Kippie David P. , Bellinger Charlie E. , Scott Paul D.
Published: December 2007

Corrosion mitigation is critical for successful managed pressure drilling (MPD), underbalanced drilling (UBD), and air drilling operations. During these operations, large volumes of gas are injected to lower the hydrostatic pressure in the annulus. Most often the injected gas contains some oxygen and the gas is circulated in combination with some quantity of drilling fluid or liquid. Due to the oxygen content and aqueous environment, corrosion potential during MPD/UBD/air drilling operations is high.

Without a proper corrosion mitigation program during these operations, corrosion can lead to the catastrophic failure of drillstring components with corrosion rates 15 times or higher than the industry-acceptable rate of <2 lb/ft2/yr. These high corrosion rates can lead to numerous operational problems resulting in higher well costs and/or formation damage.

This paper discusses how to properly design, implement, and monitor a successful corrosion program to mitigate corrosion during MPD/UBD/air drilling operations. Furthermore, it highlights a process that utilizes membrane technology as a mechanical means of reducing oxygen concentration in the gaseous media in combination with chemical corrosion inhibitors to alter the drilling fluid environment. By using this process, the corrosion rates can be controlled to satisfactory levels during these operations.

Other areas of discussion include membrane technology, drilling fluid chemistry in terms of corrosion control, and the types of corrosion that occur during a MPD/UBD/air drilling operation. Laboratory data will be presented demonstrating the development and limits of the various corrosion control chemistries. And finally, the operational considerations of an effective corrosion control program with case histories will be presented.
Produced-Gas Measurement Using Ultrasonic Metering During Underbalanced Operations
Authors: Wiemers Timothy O.
Published: December 2007

The accurate measurement of produced gas during underbalanced and managed pressure drilling operations is recognized as one of the most critical requirements for determining production capability of drilled producing zones, accurate wellbore flow modeling, quantifiable reservoir characterization, and for determining methods for well control.

Most underbalanced equipment service providers currently use conventional orifice meters to measure annular gas flow during underbalance drilling operations. However, there are a number of disadvantages with the use of conventional orifice metering technology for this application. Such disadvantages include:

Inaccuracies in flow calculations if incorrect gas compositions are assumed Difficulty of measuring widely varying gas-flow rates and high turn-down ratios Difficulty of rapidly removing and/or changing orifice plates when flow rates change quickly Possible downstream equipment damage as the result of dislodged orifice plates.

An ultrasonic meter can resolve some of the above problems, since it has no physical restrictions or moving parts, and therefore, the need to physically remove and/or change a plate due to varying gas-flow rates is eliminated along with the danger of damaging downstream equipment due to dislodged plates. The local computer provides for "hands-off" measurement once the electronics are calibrated and properly programmed. The meter is capable of turn-down ratios of over 250:1 to accommodate varying gas-flow rates. The electronic capabilities also provide automatic flow correction for rapidly changing gas composition.

This paper discusses several lessons learned from designing and testing a portable ultrasonic metering system in the field that was customized specifically for underbalanced operations. Suggestions are given for comparing an ultrasonic measurement system versus conventional orifice measurement system for use in an underbalanced application.