bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Transient Pressure Response near a Horizontal Well – A Coupled Diffusion-deformation Approach
Authors: Li Y. , Wong R. C. K. , Yeung K. C.
Published: December 2007

Analysis of transient pressure response near a horizontal well has been based largely upon the analysis of mathematical solutions for the diffusivity equation. The diffusivity equation satisfies the principle of mass conservation, but does not consider the principle of equilibrium. No deformation properties of reservoir are included in the diffusivity equation. However, in some deformable reservoirs, the stress and deformation caused by injection or production could be so significant that it might affect the pressure response. This paper presents analyses of transient pressure response near a horizontal well using a coupled diffusion-deformation method. The results are compared with those obtained from the single diffusivity equation. Implications on practical applications such as well testing are addressed.
Experimental Investigation of Sanding Propensity for the Andrew Completion
Authors: Venkitaraman A. , Li H. , Leonard A. J. , Bowden P. R.
Published: December 2007

One of the main concerns during the completion phase of the planned Andrew horizontal wells was sand production. Analytical models based on inputs from log details and core analyses preferred perforated, cemented liner completions to lessen the likelihood of sand production. To further strengthen this recommendation and to perform a risk analysis of formation failure at the time of underbalance perforation and expected producing conditions, laboratory experiments were conducted on three reservoir core samples selected from two pilot wells. The core samples were perforated with shaped charges under simulated downhole conditions. The perforated core samples were flowed, while monitoring any sand production resulting from the effects of increasing rate, onset of water cut and depletion (increasing effective stress).

The core samples did not show any propensity to produce sand during single-phase oil flow (rates of up to 10 B/D/perforation). When water cut was introduced transient sand production was observed, indicating the production of perforation-generated rock debris. As the percentage water cut was increased, the sand production declined. The core samples did not show any propensity for sand production during depletion testing. The wells were subsequently completed with perforated cemented liners with no sand control. Now, into two years of production no sand problems have been encountered. These experiments are presented as a means of complimenting existing sand prediction models in completion designs for sand prevention.
Improving Recovery Efficiency of Water-drive Channel Sandstone Reservoir by Drilling Horizontal Wells Laterally
Authors: Zhiguo Fu , Qinglong Du , Pingshi Zhang , Bingyu Ji , Weigang Lu
Published: December 2007

Injected water always advances along the bottom of channel sandstone reservoir with high heterogeneity during development by water injection in vertical well. Even if the time of water-drive is very longer, there is still some non-producing thickness at the top of the oil reservoir, which make an unsatisfactory result of recovery. This paper give an example that horizontal well was drilled in the reservoir of only 4m thick remaining oil by using of existing casing pipe of low efficiency vertical wells to make the top remaining oil reservoir produce. The research shows that drilling horizontal well laterally can improve development result of this kind of reservoirs.
Screening and Design Criteria for Steam Assisted Gravity Drainage (SAGD) Projects
Authors: Singhal Ashok K. , Ito Yoshiaki , Kasraie Mahnaz
Published: December 2007

Certain insights into screening and design of SAGD projects, derived from in-depth analyses of three successful field projects in Canada [Tangleflags, Underground Test Facility (UTF) and Imperial Oil's Horizontal Well Pilot I (HWPI) projects] are presented. It was seen that for obtaining attractive oil rates and oil reserves, one must attempt to obtain as large a confined steam chamber, as feasible. Towards this end, one can select suitable sites by carefully scrutinizing various reservoir/geological characteristics for their impact on confinement and size of an expected steam chamber. Important design options include staggering of the injectors (horizontal and vertical) around the horizontal producers in pools with mobile heavy oil; injector to injector spacing so that adjacent steam chambers merge into each other, thereby providing a more efficient mobilization and drainage of oil; and using geo-mechanical effects to advantage, by suitably programming injection and production schedules.

It was seen that for continuous net pay thicknesses of 15 m or larger, encouraging performance during SAGD could be expected. Furthermore, for in-situ oil viscosities of 35 000 mPa.s or lower, staggering of injectors around the producers becomes feasible. In this case, the "steam trap" constraint on production can be ignored during early periods of steaming for obtaining high initial oil rates. If sub-fracture injectivity of steam into the formation is limited, one can attempt an "intermittent SAGD" or a "Single Well SAGD" to maximize returns. Other similar ideas for obtaining an optimal performance are also discussed.
Best Practicable Control Technology Currently Available To Remove Oil From Produced Brine
Authors: Sebesta Ed C. , Winn W.T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The recommended effluent oil concentration limitation guidelines for "Best Practicable Control Technology Currently Available" (BPCTCA) for produced water discharges are a long term average of 44 ppm with a maximum of 100 ppm. BPCTCA consistent with the Federal Water Pollution Control Act Amendments of 1972 was Pollution Control Act Amendments of 1972 was defined after a thorough analysis of existing treatment system performance in coastal Louisiana and costs for various treatment system modifications.

Introduction

The purpose of the study is to define the "Beat Practicable Control Technology Currently Available" (BPCTCA) to remove oil from water produced with oil and gas consistent with the goals of the Federal Water Pollution Control Act Amendments of 1972 (FWPCAA of 1972). Section 302 (b) of the FWPCAA of 1972 states that assessment of BPCTCA shall include the following factors:The total cost of application of technology in relation to the effluent reduction benefits to be achieved from suchapplication.The age of equipment and facilities involved.The process employed.The engineering aspects of the application of various types of control techniques.Process changes.Non-water quality environmental impact (including energy requirements).
Optimum Development of a Thin Box-Shaped Reservoir with Multiply Fractured Horizontal Wells
Authors: Lietard Olivier , Hegeman Peter
Published: December 2007

Very low permeability reservoirs are commonly developed with hydraulically fractured wells. Quite often, drilling costs must be reduced and/or the number of slots on an offshore platform is limited. Vertical wells are then replaced by a horizontal well with a set of parallel, equal size hydraulic fractures. A recurrent question concerns the productivity index of this multiply fractured horizontal well.

Simple analytical expressions of this index have been provided by Mukherjee et al.1 and later corrected by Lietard et al.2 They however underestimate to a large extent the actual performance of this type of well.

The present paper proposes a much better definition of the productivity index of multiply fractured wells. It is based on the usage of Dietz’ shape factors3 for vertical wells centered in independent box-shaped drainage areas of equal size in the considered reservoir. For this purpose, Gringarten’s work4 about shape factors for hydraulically fractured wells has been revisited, and corrected equations are presented in this paper.
Selectively Placing Many Fractures in Openhole Horizontal Wells Improves Production
Authors: Love T. G. , McCarty R. A. , Surjaatmadja J. B. , Chambers R. W. , Grundmann S. R.
Published: December 2007

This paper summarizes stimulation results from an openhole horizontal well that was treated with a new fracturing process called hydrajet fracturing. With this process, operators can accurately place many fractures at different locations in a horizontal well without using sectional isolation techniques. In particular, the process uses high-pressure jetting to concentrate fracturing energy at a precise fracture location. Surface and downhole pressure recorders, flow recorders, and tracers obtained pertinent data for further study of the process. The well in this study was hydrajet-fractured with acid.

This study demonstrates that openhole horizontal wells can be hydrajet-fractured effectively and economically.
Horizontal Drilling in Miocene thin Sand of the Lake Maracaibo
Authors: Partidas Carmen
Published: December 2007

With a long history of drilling vertical wells aiming at producing hydrocarbons from several different pay intervals, the Lake Maracaibo Basin has reached a stage of maturity that requires resorting to new technologies to overcome problems normally found in basins at this stage of development. Horizontal drilling provides a means to increase recovery, drain individual sands more efficiently and thoroughly, avoid negative effects like water coning or finguering resulting from fast production, and, shortening producing periods by recovering reserves more rapidly. Miocene sands where this technology was applied, presented several intervals of unconsolidated sands of variable continuity, pay intervals with most frequent thickness in the ten to twenty feet range and reservoir pressures predominantly at hydrostatic or below hydrostatic values.

The horizontal drilling program in the Lagunillas Lago Production Unit of Maracaibo was initiated in 1995. To date, 91 wells have been drilled with a total horizontal footage of 94,173 feet drilled. Results can be assessed only through an economic analysis in which time plays an important role. Pay out. Profit to Investment Ratio and Net Present Value properly discounted, are some parameters used in the evaluation of horizontal wells. For instance, of the 18 horizontal wells drilled in 1996, 42% show less than a 2-year pay out. 42% a pay out of 2 to 4 years and, 16% a pay out of more than 4 years. Profit to Investment Ratio for the same time period was distributed as follows: 68% greater than 2, 21% between 1.5 and 2, and 11% less than 1.5.

Future horizontal drilling will be dictated by volumes of Remaining Reserves combined with performance of vertical wells in the same area. Vertical wells showing high water cuts will be considered for replacement by horizontal wells, provided that Remaining Reserves justify investment. Because of the low pressures in many reservoirs, formation damage by drilling fluids will be carefully assessed. Dual horizontal drilling in heavy oil reservoirs, in combination with steam injection, will be an important consideration in future programs.
Surveying and Analyzing Injection Responses for Patterns with Horizontal Wells
Authors: Fedenczuk Leon , Hoffmann Kristina
Published: December 2007

This paper presents a novel method for visualizing injection responses in patterns that include horizontal and/or vertical wells. Horizontal wells can respond to half a dozen or more vertical injectors. Understanding fluid communication between the horizontal well and the surrounding injectors is essential to estimating the effectiveness of the waterflood and helps to predict responses to the waterflood. Armed with the understanding of responses, we can optimize injection patterns, improve production rates, and achieve more efficient oil recovery.

Comparing the produced rates of oil and water to the injected water demonstrates fluid communication through a reservoir. However, typical oilfields can exhibit complex geology in patterns, accidental schedules of wells and/or random changes in the injection and production rates. Together with the shear volume of data, manual analyses may lead to ambiguous and biased associations between producers and injectors. The technique presented in this paper provides a rigorous and unbiased approach. It is based on the Spearman rank correlation between the injected and produced rates over a period of time. The correlation and the time lag between the injection and the associated production rates allow us to compress these two series of rates into a set of two simple parameters.

The advantage of the approach outlined in the paper is the capability to do a quick analysis and interpretation of fields under the waterflood, with a large number of injectors and many years of history. Furthermore, the analysis is based only on the ready available injection and production history. The development of the methodology was originally intended for injection optimization. It may however play an essential role in studies to locate the under-performing fields that may represent the acquisition targets.
The Dynamics of Vertical Pulse Testing in a Slab Reservoir
Authors: Falade Gabriel K. , Brigham William E.
Published: December 2007

Introduction

Pulse testing, as a practical method of reservoir analysis, was introduced into petroleum engineering literature by Johnson et al. in 1966. Since then, several authors have discussed, expanded on, or applied some of the basic concepts of horizontal pulse testing. Pulse testing as originally formulated by Johnson et al. can provide two pieces of information from which the reservoir transmissibility (T = krh/Î¼) and storage (S = Î¦cth) can be obtained. It does not address itself to the problem of evaluating the in-situ vertical permeability, which is important in reservoir processes where there is appreciable vertical flow.

It has been recognized that vertical interference testing has considerable promise for simultaneous evaluation of the horizontal and vertical permeability; however, no one has considered the use of multipulse tests and the Johnson gradient method for this purpose. This is despite the inherent advantages of multipulse testing over the other techniques.

The objective of this paper is twofold:to examine the behavior of multipulse pressure transients in a vertically pulsed slab reservoir, noting the effect of the finite characteristics of the reservoir, andto generate correlation curves, based on known pressure response characteristics, for interpreting dynamic data from pulse-tested reservoirs.
History Matching of Laboratory Coreflooding Experiments
Authors: Fincham A.E. , Ferreol B.
Published: December 2007

This paper describes a new program (Caropt) which analyses data from dynamic coreflooding experiments and simultaneously estimates relative permeabilities and capillary pressures. Relative permeability curves are parameterised using a new modified form of standard spline interpolation that allows more flexibility in their functional form. Caropt has proven to be both robust and efficient in practice. Examples are given of the application of Caropt to two laboratory coreflooding experiments. The results produced with Caropt show that capillary pressure has a significant effect on the predicted relative permeability curves.

P. 95
Novel Cements Materials for High-Pressure / High-Temperature Wells
Authors: Noik Ch. , Rivereau A. , Vernet Ch.
Published: December 2007

The two primary technical objectives for well cementing are to isolate the producing formation reservoir and to support the casing. The development of deep offshore drilling and HP/HT formulations leads to improve the quality of such operations and needs performant materials.

The present paper focused on new cement composition developed for high temperature wells. Materials is composed with classical Portland cement and silica particles. The original idea of this work is to control and manage with the different component granulometries. At least two types of silica have been used, one is composed of crushed sand particles and the other is silica fume with respectively mean particles size of 30um and 0.1um. Considering the granulometry partition of class G Portland cement, the choice of grain size distribution of silica which partially overlaps the cement one, permitted to adjust the compacity of the powder content system.

Then the water quantity is optimised in relation with the cement primary porosity in order to fill the vacant site between grains and assure the slurry rheology. The consequences on the setting material is to improve the durability and the mechanical strength and decreasing the permeability specially at temperature above 100 C. Good performances were noticed through varying test conditions including: Classical API tests, rheological measurements and durability tests in sea water in the presence of gas.

P. 189
Optimum Offshore Development Schemes Selected with Computer Assistance
Authors: De Ghetto G. , D'Amato M. , Buelli M. , Negri I. , Giacometti L. , Bonuccelli M. , Ferretti C. , Basana R. , Berti D.
Published: December 2007

Reducing the development time to first oil is crucial for oil companies. especially for offshore where, often, large capital commitments are necessary. It is vital to determine the optimum development scheme quickly and efficiently. The process is made more difficult because of the necessity to combine and enhance, often by trial and error, the vast amount of information and data from a variety of sources such as reservoir, drilling, completions, artificial lift, offshore structures. marine operations and project economics. To facilitate this task, we have developed a decision support system that can quickly process all available data from reservoir to export, and determine the technically feasible developments schemes. Project economics are evaluated simultaneously with technical parameters. The system contains a variety of environmental and geographical databases and costs for drilling and completions, offshore structures, marine operations, oil and gas processing, etc. The program determines designs of multiphase pipelines (well and surface), floating vessel requirements, risers and moorings, oil and gas processes. The decision support system evaluates also feasibility development schemes and economics in situations where there is a lack of information such as exploration and appraisal phases.

P. 259
Treating Flow-Rate Uncertainty in Pressure Transient Analysis
Authors: Ovens J.E.V.
Published: December 2007

Pressure transient analysis (PTA) relies on the input of information from a variety of sources; pressures from downhole gauges, flow-rates from surface test separators, PVT properties from Lab measurements and geometric properties such as formation height from, for instance, logging. The traditional methods of analysis such as the Horner plot, the Skin plot and even history matching of the full test signal, all try to match the pressure response while implicitly assuming that all the other sources of information have no uncertainty, however, it is almost universally acknowledged that the measurement of flow-rate is possibly the least accurate source of information.

In this paper, this paradox is addressed and a remedy is proposed.

A Monte-Carlo program is used to examine the contribution that uncertainty in flow-rate measurement makes to the overall uncertainty in the estimates of permeability, skin and nonDarcy skin in a multi-rate gas test, using the traditional Horner analysis/ skin plot technique. From this example, it is shown that rate uncertainty completely dominates the errors in output parameters. A new algorithms is outlined for treating rate uncertainty in this type of analysis; the algorithm is based on the problem of fitting a straight line through a set of points where it is known that there are errors in both the dependent and independent variables. Using the Monte-Carlo technique, the paper demonstrates that the new algorithm reduces uncertainty in computed parameters. Finally, an outline is presented as to how the concepts developed above may be applied to the full history matching process.

P. 297
Relations Between Ultrasonic Amplitude and Petrophysical Characteristics
Authors: Chelini V. , Meazza O. , Verhoeff E.K.
Published: December 2007

Empirical evidence suggested that Ultrasonic Amplitude by CBIL tool could be related to formation porosity. A core plug container was designed to investigate this relationship under a variety of controlled conditions. The container holds a number of plugs, radially distributed around the tool transducer. With this experimental setup three different experiments have been carried out. Sandstone, limestone and dolostone samples saturated in water and light hydrocarbon have been used to evaluate the amplitude-porosity relation. The third experimental setup to study the effect of different mud systems on the aforementioned relation has been carried out. The Ultrasonic Amplitude has a distinct linear relation with the core plug porosity for each lithology. The presence of hydrocarbon in pore space increases the CBIL amplitude. The effect of the mud attenuation on the amplitude is independent of the porosity. Measurements of attenuation provide a possible calibration of the amplitude for the downhole environment to the amplitude measured in water. The observed relationships are supported by current theory and model studies. The relation between the CBIL reflection coefficient and plug permeability has also been investigated. The results are applied at downhole acquisitions to evaluate the porosity of the formation using the CBIL amplitude.

P. 307
Tin Fouye Tabankort Gas Field - How Understanding of Abnormal Fracture Propagation and Reservoir Uncertainties Led to Successful Hydraulic Fracturing Operations
Authors: Baylocq Pascal , Sahnoune Abdelkader , Martin Antonio , Sims Michelle
Published: December 2007

Development of the Tin Fouye Tabankort Gas Field, located approximately 600 miles South-Southeast of Algiers, was initiated in 1996 with the simultaneous start-up of surface facilities construction, workovers of existing wells and drilling of new wells, The evaluation of hydraulic fracturing operations was an important step in the formulation of the optimal development strategy for this complex Ordovician age sandstone reservoir. However, production performance and hydraulic fracturing design were uncertain due to large reservoir uncertainties (heterogeneity's, kh, skin, presence of natural fissures, etc.) and doubts about the fracture height growth behaviour.

To overcome these uncertainties, a complete set of measurements were performed including pre and post- hydraulic fracturing well tests, minifracturing on all wells including some bottom-hole pressure recording, temperature logs, and radioactive isotope tracing in both gel and proppant. Analysis of the collected data allowed a better understanding of reservoir characteristics, the influence of natural fissures on fracture design, and fracture growth behaviour. Indeed, results showed that the radioactive shale immediately above the IV-3 reservoir was often not a barrier to fracture growth.

With this knowledge, perforation and hydraulic fracturing strategies were steadily improved to maximize post-job production, and optimize project economics, Results proved to be very successful with the average production increasing by a factor of 5 at significantly reduced drawdown pressures.

P. 361
An Integrated Approach For Evaluating Matrix Stimulation Effectiveness And Improving Future Design In The Gullfaks Field
Authors: Kotlar H.K. , Karlstad S. , Jacobsen S. , Vollen E.
Published: December 2007

Production decline in several wells in the Gullfaks field in the Norwegian sector of the North Sea has been attributed to various formation damage mechanisms. These include fines migration, scale formation, relative permeability changes after floodwater breakthrough, possible emulsion formation and byproducts of bacteria. To address this decline, many types of treatment operations are employed.

This paper describes how a software program for design of matrix acidizing treatments has been validated for the Gullfaks field. Emphasis has been given to sensitivity analysis of this particular software as a function of variations in critical design parameters. The paper also describes how this program, StimCADE, has been used as an integrated part of a chain of analytical engineering applications, introduces a complete design methodology for possible identification of the damage mechanisms.

The method revolves around analyzing each well's historical production data, immediately before and after a given treatment operation, for changes in reservoir skin using nodal analysis. The actual treatment parameters of the chosen job are input to the StimCADE simulator. The pre-treatment actual and predicted skin values are calibrated to one another by adjusting various input reservoir parameters in either one or both of the nodal analysis and StimCADE programs.

Differences between the post-treatment actual and predicted skin values are interpreted to determine the formation damage mechanism. This improved damage determination is used to design more effective future treatments. The subsequent skin reduction prediction from the StimCADE program is input into nodal analysis to assess the production and thus economic impact of the new design.

Four wells in the Gullfaks field in the Norwegian Sea, operated by Statoil, serve as the basis for a case study. Recommendations are made on how to extend the technique to other similar fields.

P. 413
Downhole Separator Produces Less Water and More Oil
Authors: Verbeek P.H.J. , Smeenk R.G. , Jacobs D.
Published: December 2007

A downhole oil/water separation system is operational since 1997 in the Eldingen field located east of Hannover (Germany). The installation is the first successful demonstration of the downhole separation concept outside North America. The well produces light oil with a high watercut from a consolidated sandstone reservoir. Originally eighty cubic metres of fluids were produced daily with the assistance of a beam pump. The new well completion consists of a hydrocyclone for oil/water separation and of electric submersible pumps for drawdown and for re-injection of the separated water. The downhole separator increases the effective capacity of the flowline thereby debottlenecking the Eldingen production system. By recompleting the well, net oil has increased by a factor of three, whilst net water has decreased threefold. In the first year of operation re-injection of water, separated downhole, didn't cause any damage to matrix permeability, however, an increase of the watercut in the project area is observed.

P. 429
New Applications for Enzymes in Oil and Gas Production
Authors: Harris R. E. , McKay I. D.
Published: December 2007

Historically, enzymes have been used in the oil industry both for improving the characteristics of a range of biopolymers employed in the industry and as breakers for biopolymer gels.

Until recently, the use of enzymes downhole was limited to gel breaking applications where suitable enzymes are used to break down or degrade a specific gel. In this case, the enzyme is used to remove a chemical which is no longer required, such as biopolymers in filter cakes following drilling or in tracing gels after the frac has occurred.

More recently, enzymes have been used to produce useful chemicals in-situ. An enzyme-based method has already been reported which generates organic acids for a variety of acidizing applications such as matrix acidizing, the stimulation of natural fracture networks, damage removal over long horizontal intervals or gel breaking. The generation of acid in-situ following placement of the fluid ensures the even delivery of acid over the whole of the treated zone.

The use of enzymes for generating useful oilfield chemicals has now been extended. Examples in the use of enzymes for the in-situ generation of minerals, gels and resins with potential for use in applications such as water shut off and sand consolidation are now reported.
A Review of Injection Modes and Associated Skin Values for Vertical Wells in High-Permeability Reservoirs
Authors: Lietard Olivier
Published: December 2007

Water injection and stimulation treatments in vertical wells are routine techniques. Injectivity index forecast is however still a problem for many production technologists.

This paper aims at describing the various injection modes a vertical well in a high permeability reservoir experiences when increasing the injection rate. The apparent skin value is derived for each mode and is used to estimate the stabilized injectivity index of the well.

The following injection modes are considered: partial completion matrix flow, damage breakthrough with vertical extension of a forced fracture, radial forced fracture and forced fracture with lateral extension (PKN). Horsepower requirements are calculated in each case. In addition, Step Rate Tests are analytically simulated and discussed.

An actual multi-rate injection test is presented to support the theoretical developments of this paper.

P. 487
Simultaneous Determination of Gas and Liquid Compressibility Factors for Gas Condensates
Authors: Potsch K.T.
Published: December 2007

The compressibility factors for the gas and liquid phases are not directly measurable during a PVT-experiment. Empirical correlations or EOS give just rough estimates. This work presents a method for determining both compressibility factors from volumetric measurements by parameterizing their functional form and finding the coefficients by linear regression. As an alternative an iterative procedure is suggested.

P. 555
Production Forecasting of an Unstable Compacting Chalk Field Using Uncertainty Analysis
Authors: Hegdal T. , Dixon R.T. , Martinsen R.
Published: December 2007

Accurate production forecasting is a critical factor in an oil company's management and decision making. The production forecast forms the basis for long term planning and decision making, investment decisions and to set performance targets for the organization. For the Valhall field, offshore Norway, forecasting has proved to be difficult as a single discrete event, like the failure of a key producer, can reduce annual average production by up to 10%. The current activity level at Valhall is at an all time high, with two drilling rigs occupied with drilling of new production wells, adding up to 12 new, long reach horizontal wells to the production potential yearly. Accurate prediction of drilling time and initial well rates has proved challenging, adding significant uncertainty to the production forecast.

Past years forecasting performance has demonstrated that single most likely' prediction of future production is inadequate for management and planning purposes. Based on this an effort was initiated to improve the forecasting methodology and procedures with special emphasize on handling of uncertainty in Short Term Production Forecasting (STPF). With the STPF being an ongoing effort throughout the year, the preferred methodology should balance the need for using techniques that adequately handle complex relationships while still being efficient and relatively easy to apply in the daily work situation.

A spreadsheet based approach to the problem is described, where the standard parameters that impact the future production of most oil fields are handled, as well as the special challenges faced in predicting the performance of the Valhall field. The proposed methodology shows how a customized spreadsheet and use of commercially available statistical analysis ad-ins allows for traditional deterministic production forecasting, partially probabilistic analysis or fully integrated uncertainty analysis. The resulting forecasts assign probabilities to all outcomes as well as a ranking of the uncertainties in the form of a tornado chart.

The approach is not unique, as some companies are using techniques based on similar concepts. The specific challenges at Valhall adds additional layers of complexity, and requires extensive integration of the various risk elements.

In addition to having an effective forecasting tool, communication and integration of knowledge are seen as key success factors in order to improve the short term production forecasting. The production forecast requires input from several departments and many individuals to ensure that the "company knowledge" is fully reflected. A common language's to communicate uncertainty, and an auditable process to ensure buy-in and consistency is critical for a successful outcome, and is equally important when communicating results. This paper discusses both the development and use of the forecasting tool, and the forecasting process.

P. 149
A New Approach to Gas-Liquid Separation
Authors: Stewart A. C. , Chamberlain N. P. , Irshad M.
Published: December 2007

Effective gas-liquid separation is important not only to ensure that the required export quality is achieved but also to prevent problems in downstream process equipment and compressors. Once the bulk liquid has been knocked out, which can be achieved in many ways, the remaining liquid droplets are separated from by a demisting device. Until recently the main technologies used for this application were reverse-flow cyclones, mesh pads and vane packs. More recently new devices with higher gas-handling have been developed which have enabled potential reduction in the scrubber vessel size. This paper will present some of the recent developments in scrubbing technology which have been aided by the use of computational fluid dynamics.

In addition, this paper will review some of the latest compact separation systems which have also enabled a whole new approach to gas-liquid separation to be considered. There are several new concepts currently under development in which the fluids are degassed upstream of the primary separator. These systems are based on centrifugal and turbine technology and have additional advantages in that they are compact and motion insensitive, hence ideal for floating production facilities
Scale Inhibitor Squeeze Treatments in High-Velocity, High-Calcium Wells
Authors: Fielder Glenn D.
Published: December 2007

Application of scale inhibitors by the formation squeeze technique is a common method for mitigating downhole scale in oil and gas wells. Factors which can adversely affect inhibitor returns include high fluid velocity and high calcium concentrations in the produced water. It has been observed that high calcium levels, particularly at higher temperatures, can suppress inhibitor returns both immediately following the squeeze and thereafter. When coupled with high velocity, wells must be retreated frequently to maintain adequate inhibitor residual concentrations. By increasing inhibitor levels through improved adsorption-desorption properties, squeeze life can be lengthened.

Laboratory data have been reported that polymer/phosphonate combinations can improve both inhibition of calcite and the desorption rate of the phosphonate.1 In the current study, dynamic tube blocking and longer term static scale inhibition tests were conducted against both calcite and barite to evaluate the effectiveness of polymer/phosphonate blends for preventing scale. Flow tests in sandpacks were run to determine dynamic adsorption and desorption characteristics of both polymer and phosphonate from blended formulations. Simultaneous or coadsorption of polymer and phosphonate appeared to be a factor in increasing inhibitor returns.

Data from field squeeze applications show the combination inhibitors provided longer squeeze life compared to phosphonate alone in the presence of calcium concentrations in excess of 10,000 mg/L, at temperatures up to 200F and at near wellbore fluid velocities of 0.01 ft/sec. Field data are presented which are in good agreement with computer modeling results that predict the sensitivity to increased velocity.
Studies on the Damage Induced by Drilling Fluids in Limestone Cores
Authors: Xiao L. , Piatti C. , Giacca D. , Bartosek M. , Nicula S. , Gallino G.
Published: December 2007

Well productivity can be seriously reduced by excessive fluid loss and solids invasion while drilling. If not adequately controlled, losses may push hydrocarbons very far from the hole and solids may plug the pores, increasing the time necessary for testing the well and distorting the evaluation of its productivity potential.

Laboratory procedures for determining the damage of a mud system on rock samples are traditionally based on the return permeability test which provides an indication of both the damaging potential of mud and the efficiency of cleanup techniques.

The non-destructive nuclear magnetic resonance (NMR) measurement is a new methodology for studying the influence of small scale geological heterogeneities on fluid flow and trapping. It permits to check the invasion of solids and filtrate present in the mud using different experimental set-ups. The main advantage is the possibility to have the spatial distribution of the invading phase inside the rock sample. Low frequency (2 MHz) nuclear magnetic resonance relaxation (NMRR) measurements were also used for following the effect of solid mud particulate invasion on the pore size distribution. These techniques provide fast and reliable analysis without the destruction of the sample.

This paper reports the laboratory procedures and the results of a study aimed at determining the damage coming from the penetration of bentonite/mixed metal particle aggregates and polymers into low permeability carbonatic reservoirs. The results were compared with both traditional and innovative methods. Combined with spurt loss, non conventional rheological approaches, dynamic filtration and mud cake SEM (scanning electron microscopy) observations, nuclear magnetic resonance imaging (NMRI) provides precise and directly observable results to distinguish the severity of damage, the type and depth of invasion and, even more, the distribution of invaded particles in the matrix.

The integration of conventional and advanced methods to study damage appears to be highly promising for selecting drilling fluids, with suitable components and particle size distribution appropriate to protect the reservoirs.
Novel High-Pressure/High Temperature Fluid Loss Reducer for Water-Based Formulation
Authors: Audibert A. , Rousseau L. , Kieffer J.
Published: December 2007

Deep drilling require non polluting fluids stable at temperature up to 390 °F. In terms of formation damage, it is now well accepted that prevention is better than remediation since well treatment using washing fluids can be hazardous. This is of major importance for complex well configuration using openhole completion.

Novel polymeric structures were investigated. The additive structure and molecular weight were selected in order to limit the damage due the filtrate invasion. The selected additive was proved to be stable at temperature up to 360 °F. This novel additive was implemented in different water based formulations such as classical bentonite formulation or drill-in fluid and tested in a large range of experimental conditions. The possible damage arising from overbalanced conditions was evaluated in terms of static and dynamic filtration properties, cake permeability, fluid loss characterization and reduction in oil permeability after mud exposure.

Compared to other commercially available fluid loss reducers, it presents better rheological and filtration properties. After ageing at 320°F, no fluid gelation was observed. Under dynamic filtration conditions, the formulation presents a very low filtration rate.

The approach was validated on long core filtration test performed under representative reservoir conditions. Use of a stable additive limits the formation of degradation products that could badly affect the reservoir permeability by plugging effect. Such a design of chemical additive within a water based formulation effectively prevents the well known formation damage arising from the use of water based formulations.
Impact of Synthetic-Based Drilling Fluids on Oilwell Cementing Operations
Authors: Patel Arvind D. , Wilson J. Michael , Loughridge Bill W.
Published: December 2007

This paper presents chemistries of new synthetic-based muds and describes how they affect cement-spacer design. The paper also shows how new fluids and spacers affect the hydraulic bonding of oilwell cements to casings and formations. It discusses the polarity and dispersibility of various synthetic-based fluids and how their chemistry influences cement bonding. Insights into designing new surfactant packages for displacement fluids are provided. Other oil-based fluids are reviewed and compared to the new synthetic fluids. Also presented are new fluid system formulations and other factors affecting drilling performance vs. cementing.

Rising drilling and completion costs, along with an increased awareness of sensitive environmental concerns, have placed more emphasis on effective annular sealing during the primary cement job. Synthetic-based drilling fluids have strong oil-wetting characteristics. Therefore, the following considerations should be made before cement can be successfully pumped behind these fluids: (1) the annular fluid (drilling mud) should be physically displaced by another fluid, and (2) the displacement fluid should leave the casing and formation water-wet. Laboratory experiments testing compatibility and shear bond presented in this paper demonstrate techniques used for cementing behind the new synthetic-based drilling fluids.
Chemical Structures of Group 4 Metal Crosslinkers for Polygalactomannans
Authors: Harry David N. , Putzig Donald E. , Moorhouse Ralph , DelPesco Tom , Jernakoff Peter
Published: December 2007

In SPE 37280 and SPE 39531,* Harry et al., and Moorhouse, et al., respectively, demonstrated that seemingly minor variations in aqueous based crosslinker chemistry can produce significant differences in the rheological responses of polygalactomannan-based fracturing fluids crosslinked with these agents. While the work contained some references to boron crosslinking and the principle conclusion can be applied to both boron and zirconium fracturing fluid systems, the emphasis was on zirconium crosslinked systems. Not surprisingly, some of the observed differences in performance could be attributed to variations in the crosslinker chemistry. Crosslinker differences that were isolated and evaluated included differences in the ligand chemistry, the ligand-to-metal-ratio, the nature of the zirconium starting material, etc. Moorhouse, et al., suggested several mechanisms by which these phenomena might be explained. The authors stopped short, however, of making any attempt to correlate the chemical structure of the crosslinker with its rheological performance.

With this paper the authors advance their studies to present a more comprehensive examination of the proposed structures of titanium and zirconium alkoxides and aqueous-based chelates, including a general discussion of the methods employed to manufacture these crosslinkers and factors present in Group 4 metal crosslinkers that may affect their crosslinking response with polygalactomannans. There is also some discussion on other methods that have been employed to control the gelation rate. Finally, there is some discussion on the effects of polymer attributes to fracturing fluid performance, particularly as it relates to crosslinker efficacy.

The findings presented in the paper are supported by laboratory analyses that includes the examination of crosslinking agents by nuclear magnetic resonance (NMR) imaging, X-ray crystallography, and the rheological performance evaluation of systematically altered crosslinking agents. The authors suggest chemical structures of titanium and zirconium compounds used to crosslink polygalactomannans as supported by the findings of the analytical evaluations already mentioned.
The First Carbonate Field Application of a New Organically Crosslinked Water Shutoff Polymer System
Authors: Hardy Mary , Botermans Wouter , Hamouda Aly , Valdal Jarl , Warren John
Published: December 2007

This paper describes the chemistry and treatment design of the first field application of a recently developed, organically crosslinked polymer (OCP) system for water shutoff. The candidate for which this treatment was designed is a production well in the North Sea that was completed in naturally fractured chalk. Each of the completed intervals were acid fractured to further open the existing natural fractures and increase production.

The recommended treatment volume calculations took into account the leak-off considerations and the acid fracture volume. The method by which the leak-off requirements were calculated is described.

The placement and shut-in temperatures of the recommended treatment volume were then calculated as a function of time. These simulations used a production - operation wellbore simulator in combination with an advanced processes reservoir simulator. The fractures in the target zone were defined in the grid-block system that was used in these temperature simulations.

The results of these temperature calculations were used to formulate the chemical compositions of the stages of the OCP treatment and to calculate gel times and shut-in times. The calculations of these gel times and how they correspond to the gel times during the actual treatment are also described.
Demulsifier Effects on Interfacial Rheological Properties of Asphaltene Films Absorbed at Oil/Water Interface
Authors: Key M S. , Gutierrez S X.
Published: December 2007

The formation of stable water in oil emulsions in crude oil production is caused by the presence of resins and asphaltene which can organize and form rigid films at oil/water interface. In the demulsification process, demulsifier is considered to produce changes in interface rheological properties. This is because demulsification involves displacement of natural surfactants, such as asphaltenes and resins from the film surrounding the water drop. In this research, demulsifier effect and pH variation were evaluated considering the rheological behaviour of crude oil water/interface, and a model system of 1% aphalthene in heptol. Interface viscoelastic properties were studied by a planar rheological method using a surface rheometer at low shearing stress. Results indicate that measurements of creep compliance with pH variation show viscoelastic behaviour for both systems. pH effect on rheological parameters is evident, and elasticity and viscosity notoriously change. Demulsifier effect is noticeable in the different concentration evaluated. Also, it was found that elasticity changes with demulsifier concentration. This is an indicator that demulsifier works to destabilise the interface.
A Comparison of Freshwater- and Seawater-Based Borate-Crosslinked Fracturing Fluids
Authors: Harris Phillip C. , van Batenburg Diederik
Published: December 2007

This paper discusses the chemical factors that operators must address to successfully substitute seawater for fresh water in borate-crosslinked guar fracturing fluids. Seawater contains cations and anions that affect the performance of the fracturing fluid's components, as well as the fluid's interaction with the formation.

Because seawater has high ionic strength, it lowers the viscosity obtained from borate-crosslinked guar. High magnesium in the water consumes hydroxide ions and affects pH control, which in turn affects the equilibrium borate-ion concentration. This paper addresses these problems and provides guidelines for borate fluid formulation to offset seawater characteristics for temperatures as high as 300°F.

Borate fluids from seawater can control fluid loss (FL) as well as freshwater borate fluids. Chemical gel breakers for offshore environments have been developed to help control the viscosity reductions in fracturing fluids. Conductivity values with seawater fluids are equal to or better than freshwater fluids. The presence of divalent cations in the seawater fluid caused no harm to the FL properties or the retained conductivity with borate seawater fluids.