bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation and Control of Drilling, Completion and Workover Events with Permanent Downhole Monitoring: Applications to Maximize Production and Optimize Reservoir Management
Authors: Ballinas Javier
Published: December 2007

Permanent downhole monitoring can provide valuable information for production decisions without requiring well intervention to gather data. A permanet monitoring system can be integrated with an intelligent completion system taking advange of the downhole infrastructure and may improve reservoir management.

Greater reliability, higher temperature ratings, lower costs, a wide range of sensor types, and efficient data management and analysis allow operators to exploit the technology and extract more value from production data. Recent advances have yielded smaller, less-expensive, and more-reliable systems with higher temperature and pressure ratings. Knowledge of the reservoir is updated and used continuously to optimize field development throughout the life of the reservoir.

Permanent continuous downhole sensors are becoming more accurate and reliable. High-temperature operation and long-term reliability of permanent-downhole-monitoring systems improved with the use of sensors that do not require downhole electronics with novel data acquisition options like cases mentioned in this paper.

This paper shows examples of permanent downhole monitoring applied to artificial-lift, sand control, cementing and fracturing operations, observation wells and reservoir management applications.
Planning Extended Reach Wells for Deep Water
Authors: Cunha J. C. , Martins A. L. , Sá C. H. M. , Fernandes P. Dore
Published: December 2007

Although Extended Reach Wells (ERW) have recently reached limits that would not even be dreamed a few years ago, most of those wells were drilled from onshore locations. Even though there are some experiences offshore, they are related to wells drilled on shallow waters from fixed platforms.

In Brazil, where the major oil field producers are located in deep waters, ERW may be in some cases the only technical and economical viable solution to the development of such fields. ERW, besides minimizing problems related to fluid flow, will also diminish the cost of development in large extension fields by reducing the number of production units per field. Also it may be the mandatory option in case of development of a large field by means of using a dry completion system (a TLP for example).

To drill ERW in deep water from a floating vessel such as a semi-submersible rig or a drill ship, is much more complex than performing the same job onshore. In Campos basin, Brazil, some of the problems that may be faced when drilling ERW in deep water fields are the presence of very unstable formations and small sedimentary coverage above the reservoir.

Due to studies indicating the feasibility of the use of ERW to develop oilfields in that basin, an R&D project was created aiming to develop techniques and operational procedures to be used when drilling those wells. Main tasks of the project were: –Well planning;–Wellbore stability;–Horizontal completion and sand control;–Drilling and completion fluids;–Cuttings transport.

This paper shows which methodology was used to manage the project and also some results and benefits obtained.
Foam Cementing Controls Deepwater Shallow Flow in the East Mediterranean
Authors: Waheed Arshad , Cockram Mark , Bahr Mahdy
Published: December 2007

Deepwater drilling, though relatively new in the Nile Delta region of the Eastern Mediterranean, has increased operating water depths to over 4,000 ft within a year from a record depth of 1,900 ft in the fall of 1999. The deepwater extension of the ancient Nile delta has been divided into six major operating licenses granted by the Egyptian government. This paper will primarily focus on the knowledge gained from experience by Rashpetco (JV between BG, Edison and Egyptian General Petroleum Company) in the West Delta Deep Marine (WDDM) development block (Fig. 1).

The WDDM is no exception to the common challenges encountered in deepwater projects around the world, including shallow gas and waterflow hazards.1,2 The obvious consequence of an unexpected shallow fluid flow is an uncontrolled blowout situation with no drilling-control equipment in place. In some reported cases, even after the flow was controlled prior to running casing, fluid flow occurred after cementing the surface pipe.

To date, the shallow flows witnessed in the WDDM have not resulted in any severe loss of capital, unlike other areas where the loss of wells and templates has occurred.3,4 Nor have shallow flows in the WDDM caused a safety threat to environment, personnel, or equipment; however, in some instances, they may have contributed to non-productive time in drilling operations. Nevertheless, efforts have been made to understand the flow mechanism and control these occurrences by developing shallow flow-control contingency plans and designing cement slurries suited to the challenges of deepwater cementing. Foam cement and other lightweight, high-strength cement slurries have been used to balance cement slurry weight between the low margins of the fracture gradients and the flow potentials of the drilled section. Foam cementing especially has been effective in many cases. This paper provides case histories in the control of unexpected shallow water flows and discusses the suitability of foam cement technology in deepwater situations.
Dynamic Simulation of Offshore Salt Zone Cementing Operations
Authors: Martins A. L. , Miranda C. R. , Santos F. J. P. , Bove A.
Published: December 2007

Salt zone cementing is still today a challenging issue. This paper presents an unique theoretical and experimental research project developed to support salt zone cementing operations in Campos basin, offshore Brazil. Theoretical approach includes the development of a numerical simulator which reproduces the mass transfer phenomena involved in the displacement of a cement slurry in front of a salt formation. The formulation is based on the solution of a well known diffusion-convection equation for the flow of a fluid through an annular section, being the external wall soluble. Experimental work includes the determination of salt mass transfer rates to cement slurries flowing through a large scale flow loop where the internal wall was formed by real halite cores. Mass transfer coefficients are then fed into the computer model.

The results obtained by running the simulator allow proper slurry composition design besides the definition of hydraulic parameters required for minimizing salt dissolution. Optimum salt compositions and adequate flow rates and regimes for pumping are recommended. Both formulation and experimental data are detailed. Charts of salt concentration profiles, as well as hole enlargement prediction are also provided.
Expanding the Range of Impregnated Technology: New Performance Benchmark Set in Middle East (Et Al)
Authors: Brackin Van , Isbell Matt , Christensen Hughes , Roggeveen Arent , Mohamed Mansouri , Wingate John , Welch Bob
Published: December 2007

The range of application of new diamond impregnated drill bit technology continues to expand into lithologies normally drilled with roller cone bits. Historically, application of impregnated drill bits has been restricted to deep intervals that contain mainly hard and abrasive sandstone. Conversely, PDC bits perform best in relatively softer, non-abrasive rock. This left a very common sequence of formations, hard abrasive sandstone interbedded with soft shale, to be drilled with either roller cone or PDC bits. None of the two choices has delivered satisfactory performance in terms of penetration rate and bit life.

Working with several operators, the bit company has conducted extensive laboratory and field development tests that have resulted in a new generation of aggressive diamond impregnated bits that offer unique advantages for drilling mixed formations more economically. The authors will outline the new impregnated technology in the context of its application and give examples on how to best apply it to achieve maximum performance. The following case studies will demonstrate significant performance improvement and illustrate an expanded range of applications for impregnated diamond bits.

Oman: 8-3/8" impregnated bit set new cumulative footage record of 1130 meters drilling in two fields in central Oman. Algeria, Rhourde Nouss field: Set longest bit run through Grés de Oued Saret to Quartzites de Hamra, drilling 97 meters further than best offset and replaced 2-4 bit runs. Algeria Hassi Messaoud field: Broke country single run footage record (361 meters); doubled footage over conventional impregnated technology while achieving the best penetration rate through the interval. Venezuela: Replaced three roller cones bits relative to hole section in offset wells.
Assessment of Salt Loading on Well Casings
Authors: Willson S. M. , Fossum A. F. , Fredrich J. T.
Published: December 2007

In the next decade significant new oil field developments will be brought on-stream in the deep water Gulf of Mexico. A large number of these wells will be drilled through salt. Assuring the integrity of these wells over the life of the field is a major drilling engineering challenge, as the consequences of well failures may result in billions of dollars remedial costs and lost production.

To address these challenges for BP's deepwater developments, advanced numerical finite element analyses of salt / casing interaction were undertaken by Sandia National Laboratories using state-of-the-art computational modeling developed as part of extensive research supporting the Strategic Petroleum Reserve (SPR) and the Waste Isolation Pilot Plant (WIPP) projects.

The paper summarizes, briefly, the salient features of salt mechanical behavior of relevance to well integrity. The results of numerical modeling of casing loading are presented which focus on the importance of assessing the possibility of both uniform and non-uniform loading by the salt; and the impact that production-induced heating of the salt has on the rate and magnitude of casing loading.

Based on the findings of these analyses, strategies for minimizing the magnitude of loading on well casings are discussed. The relative merits of cementing the annulus through salt are compared with the option of leaving the annulus open in order to defer the time at which salt loading occurs.
A "Standardized" Method for Ranking of Scale Dissolver Efficiency. A Case Study from the Heidrun Field
Authors: Kotlar Hans Kr. , Selle Olav M. , Haavind Frode
Published: December 2007

A new and simple, "standardized" method was developed in order to rank efficiency of various scale dissolvers. Five different scale dissolver products were compared for performance at Heidrun related conditions with regards to their dissolving capacity and dissolution rate/kinetics (initial speed performance) on genuine field scale samples from well A-28, Heidrun.

The overall treatment and shut-in time might be considered an important factor in remediation procedures. By comparing the performance curves of the dissolvers, the product giving the highest initial dissolution kinetics could be chosen. Moreover, there are other factors that also will influence the choice of the best-suited product, like dissolution rate of contaminated field scale, cleaning procedures, environmental rating, and total dissolution capacity.

The effects of oil contamination and cleaning procedures, involving mutual solvent or surfactants, were studied. The different products varied in active cleansing power and in sensitivity for available "active" surface area, as they will contain more or less surface-active co-agents.

In complex scale compositions, typical to most field situations, the dissolution of one particular scale species could be rate limiting to the overall process. Temperature and concentration effects could also be investigated in this set up.

By implementing this new ranking method, three chemicals were given a technical qualification for use at Heidrun. So far two of the products have been field-tested. The test procedure and a comparison to the field performance in the Heidrun cases, will be presented.
Interplay of Phase Behavior and Numerical Dispersion in Finite Difference Compositional Simulation
Authors: Jessen Kristian , Stenby Erling H. , Orr Franklin M.
Published: December 2007

Compositional simulation of multicontact miscible (or near-miscible) gas injection problems is typically performed using numerical finite difference (FD) schemes. Such simulations are intrinsically affected by numerical dispersion. In this paper we propose a method to assess the sensitivity of a particular displacement calculation to the effects of numerical dispersion, for systems with realistic multicomponent fluid descriptions. We use two simple ternary systems to illustrate how dispersion and convection interact to determine displacement composition paths and to define a "dispersive distance". We show how the dispersive distance relates to displacement performance with a detailed analysis of grid size effects on the recovery predictions for 1D displacements of a CH4 – C4 – C10 system by pure N2 and mixtures of N2 and CH4. We then show that the sensitivity of multicomponent compositional simulations also correlates well with the dispersive distance. We demonstrate that quantitative difference between oil recovery predicted by coarse grid numerical simulations and values obtained from analytical solutions to the conservation equations, can be estimated well from calculating the distance between the dilution line and the composition path predicted by the method of characteristics. Finally, we apply the assessment of sensitivity to 2D displacements in a heterogeneous porous medium to demonstrate the interplay of phase behavior, adverse mobility and numerical dispersion.
Scaling of Spontaneous Imbibition in Gas-Liquid-Rock Systems
Authors: Li Kewen , Horne Roland N.
Published: December 2007

A method has been developed to scale the experimental data of spontaneous water imbibition (cocurrent) for gas-liquid-rock systems. In this method, a dimensionless time has been defined with the effects of relative permeability, wettability, and gravity included. The definition was not empirical but based on a theoretical derivation. Using this dimensionless time, experimental data from spontaneous water imbibition in different rocks with different size, porosity, permeability, initial water saturation, interfacial tension, and wettability might be scaled. The scaling model proposed in this study for gas-liquid-rock systems was verified experimentally for different rocks (Berea, chalk, and graywacke from The Geysers) with significantly different properties; it was also verified experimentally at different initial water saturations in the same rock. The scaling results from this study demonstrated that the cocurrent spontaneous water imbibition in gas-liquid-rock systems could be scaled and predicted.
A Successful Field Test of Microbial EOR Process in Fuyu Oilfield, China
Authors: Nagase K. , Zhang S. T. , Asami H. , Yazawa N. , Fujiwara K. , Enomoto H. , Hong C. X. , Liang C. X.
Published: December 2007

This field test for Microbial EOR (MEOR) has been carried out in Fuyu oilfield, China since 19961,2. Waterflooding by a patterned flood has been applied for over 20 years and various measures to decrease high water cut has been discussed for long time.

The objectives of this MEOR project are to increase oil production from a water-flooded reservoir and to evaluate ability of microorganism (CJF-002) screened in our study. CJF-002 has an ability of producing insoluble polymer metabolically feeding on nutrient. This metabolic process is considered to be useful on plugging high permeable zones to reduce water channeling.

Prior to the injection test of CJF-002 into the reservoir, core-flooding tests were carried out in order to evaluate the magnitude of permeability reduction due to plugging by the insoluble polymer. In the field tests, the following three different approaches were conducted: –Huff-n-puff test (single cycle) at production wells (1999),–First microbial treatment at injection wells (2000), and–Modified microbial treatment at injection wells (2001).

In huff-n-puff test, CJF-002 and molasses were injected into 6 production wells. Among them, 4 wells indicated oil production increase and water cut decrease4,5. Based on these positive results of huff-n-puff test, the first microbial treatments were conducted at injection wells. In these treatments, cell count of CJF-002 and concentration of insoluble polymer were measured at the injection manifold and production wells to evaluate the metabolic activity of CJF-002 by colony forming unit (CFU) method and HPLC. Moreover, well logging such as Reservoir Saturation Tool (RST) and Water Flow Logging (WFL) and tracer tests were conducted before and after the microbial treatment to evaluate the effect of insoluble polymer on injection profile modification. As a result, microbial propagation was observed, however, the effect of injection profile modification has not been developed. The major reason was considered to be that sufficient propagation of CJF-002 was prevented by predominant population of other microbes propagated in the injection pipeline. From the unsuccessful result in 2000, injection method of CJF-002 and molasses was modified to prevent a propagation of other microbes and the modified microbial treatment was carried out in 2001. As a result, oil production in the test area increased more than twice in volume and the effect of plugging the high permeable zones was suspected from the results of tracer tests and preliminary reservoir simulation study.
Coal Well Decline Behavior and Drainage Areas: Theory and Practice
Authors: Seidle John P.
Published: December 2007

Although early gas and water production rates from a coal well are often erratic, at late time these wells typically exhibit gentle declines in both gas and water. A literature review indicated time transfoms for conventional gas well decline analysis may or may not be applicable as coal wells often show exponential declines when plotted in real time. A theoretical gas decline coefficient was derived from the pressure-squared form of Darcy's Law and the Z∗ formulation of the mass balance equation. Conditions necessary for exponential decline are discussed. A theoretical water decline coefficient was developed by coupling a water mass balance equation with an expression for Estimated Ultimate Recovery. Calculated decline coefficients are compared with reported and simulated declines in the Warrior, Powder River, and San Juan basins. Reasons for differences, as well as agreements, between theoretical and actual decline coefficients and drainage areas are discussed. Practical applications of these results include prediction of the gas decline coefficient from coalbed parameters, calculation of drainage area from water decline behavior, and estimation of total water volumes to be disposed.
Successfully Pushing the Limits in Tight Gas Fracturing
Authors: Pearce K. W. , Heiken K. , Samuelson M. L. , Mueller F. , McConnell S. B.
Published: December 2007

In the past year, an optimization process has been pursued to improve production from South Texas tight gas fields. During this period an engineering study was conducted on the fracturing design process, the fracture parameters and fluids being used. From this study, several design changes to the fracture stimulation program were made to improve the created geometry and hence increase the production.

Progress has been made to improve conductivity, effective fracture length and production response from tight gas fracturing in South Texas. The progress is due to a combination of better job designs, more consistent fracture treatment placement and novel fluid chemistry. This paper discusses the design parameters necessary to ensure consistent job results for tight gas reservoirs. Results presented are from comparisons of quantitative field data based production analysis.
Advanced Open Hole Multilaterals
Authors: Durst Doug G. , Hart Shane P. , Brown W. H. Sonny
Published: December 2007

Stimulating oil production from Algeria's Hassi Messaoud oil field has proven to be a difficult proposition. Sonatrach is now achieving substantial production increases from non-producing assets with an aggressive re-entry well program. The key to success is a combination of new technologies. Some 600 of the vertically drilled wells are candidates for reentry and rework to drill horizontal laterals, however to be eligible they must meet the following basic criteria which Sonatrach have established: They must be open hole completions.They must have been shut in for a long time – effectively since being drilled.

The zone of interest is the Upper Cambrian, an extremely hard and abrasive sandstone and quartzite formation that are extremely difficult to drill. Kicking off laterals in these re-entry wells is therefore challenging and required the development of new tools in order to do so effectively. Additional challenges were posed by the requirements to be able to isolate the laterals, tie them back to the original cased hole and provide for thru tubing re-entry capabilities.

This paper addresses the milling, drilling and completion issues relevant to these wells and discusses the solutions arrived at. Using a typical well re-entry case history, it details the steps taken to create a TAML1 level 1 open hole multilateral (or a psuedo type level 3 with mechanical integrity) combined with either through tubing completion or conventional tubular completion. It will describe how a combination of liner hanger and inflatable packer technology, together with a large bore completion allowing for selective thru tubing re-entry, has led to several successful installations. Future installations will consist of level 3 multilateral junction hardware that will be utilized to provide formation support and simpler reentry and where required the addition of lateral isolation to cut off gas encroachment. An extensive gas injection program (and in some cases water injection) is utilized in the field to assist in production recovery. The use of annular casing packers in conjunction with liner or tubular plugs will allow for isolation shutoff of either lateral at some later date when gas or water influx offsets oil production gain.
Field Experience with Applying Foamed Cement Slurries in Mature Depleted Formations
Authors: Spoerker H. F. , Doschek M.
Published: December 2007

Primary cementing of production casings across multiple, mature and severely depleted reservoir horizonts represents a significant challenge vis a vis light weight cement slurries exhibiting adequate compressive strengths at reasonable cost. The paper presents experience gained with introducing the application of nitrogen-foamed cement slurries with specific gravity as low as 1.34 SG on primary cementing jobs of gas formations in the Vienna Basin, both technically as well as psychologically. Initial obstacles – both from a managerial and engineering standpoint – are presented, and ultra-sonic cement evaluation logs of the first jobs are discussed together with job problems and their representation on the logs.
Advanced Steerable Drilling System Raises Performance to New Levels
Authors: Wong Thomas , Dirksen Ron , Gaynor Tom , Chen David C-K. , Chong Adrian C. , Si-Boon Wee
Published: December 2007

Conventional positive displacement motors (PDM's) are widely used in most directional drilling jobs. Polycrystalline diamond compact (PDC) bits are often used with the PDM's because of their longer life and increased rate of penetration (ROP). But PDM's used with conventional PDC bits often create hole problems and high vibrations that result in stuck pipe, casing running problems, downhole equipment failure, and lost drilling time. A new steerable assembly has been designed with an extended gauge bit and matched motor. The main objectives are to improve hole quality, reduce vibrations, and increase ROP. This paper will describe the working principles of the new system and how it has performed for Sarawak Shell Berhad and Sabah Shell Petroleum Company (SSB/SSPC) wells in offshore Malaysia.
A Study Reveals: Gravity and Carelessness are #1 Causes of Accidents
Authors: Buettner Kurt , Kinzel Holger , Pichl Wolfgang
Published: December 2007

The analysis of accidents over the past 20 years reveals the reasons why accidents happen and give valuable indications on how to prevent accidents in the future.

In a 20 year history, collection and evaluation of accidents which happened to employees of Weatherford Oil Tool GmbH, Germany, depending on the German legislation only "Lost Time Accidents" are recorded. "Non Lost Time" - and "Near Miss Incidents" will be mentioned at the end of this study.

Our goal is of course to reduce the number of accidents to zero. The way will still be difficult, steep and slippery but many reasons count to make our utmost efforts to achieve that goal.
Sustaining Surface Casing Integrity In A Saline Environment
Authors: Fanoiki J. B.
Published: December 2007

The bulk of Nigeria’s oil and gas production come from the Niger Delta area of the country. The environment is generally susceptible to high salinity, which influences quick set in of external corrosion on metallic products.

The surface casing of wells located mostly in the swamps of the Niger Delta are prone to external corrosion attack at the splash zone around the wellhead region. The effect of this corrosion ultimately results in loss of load bearing capacity of the wellhead when the severity is very high. At rig based well reentry, collapse of the surface casing had occurred under the weight of the Blow Out Preventer (BOP) during its installation. Repair of such failure at the wellhead is mostly unplanned and can be expensive.

The external corrosion at the wellhead region is influenced by the oxygenation of rainwater retained in the annular space between the conductor pipe and the surface casing. Similarly, the cement micro annulus that emanates behind the surface casing tend to retain some relatively small amount of water which invariably do cause an invisible, slow but steady development of corrosion on the surface casing.

The proposed paper will proffer solutions to incidence of external corrosion on the surface casing with a view to enhancing production life, safety and reducing operating cost.
The Exploitation Enigma
Authors: Etherington John R. , Leach Patrick E. , Slaght David H.
Published: December 2007

Evaluation of exploitation drilling programs raises unique issues around risking logic plus estimated ultimate recoverable (EUR) and project economic uncertainties. Clarification of these issues will assist in managing portfolios of exploration, exploitation, and development investment opportunities.

Under USA accounting rules, all wells drilled outside the area of proved reserves are classified as "exploratory wells" for computation of cost of finding. However, companies typically segregate wells into Exploration (targeting prospective resources in undiscovered accumulations) and Exploitation (targeting probable and possible reserves in and around discovered fields).

Classification as "discovered" signifies a high degree of confidence that the accumulation's EUR exceeds an internal economic threshold for development. However, there remains significant risk of drilling a dry well within the projected field limits. At the field level, the non-proven area is part of the uncertainty distribution for discovered reserves. At the exploitation well level, risk of failure and success case volume uncertainty both come into play. This multiple level view of risk and uncertainty gives rise to the "exploitation enigma".

Exploitation well results change the field/reservoir model, the EUR uncertainty profile and associated cash flow projections. Successful wells not only develop reserves within a drainage area but also modify the total field volume uncertainty distribution. Results redefine the remaining proved undeveloped, probable, and possible reserve volumes and their associated confidence levels. Dry exploitation wells also

change the EUR distribution and increase investment costs without an increase in forecast production.

This paper compares alternative approaches to the evaluation of exploitation programs. It concludes that the economic analysis to support exploitation drilling decisions should not be based solely on the individual well's anticipated results, but rather on its risk-weighted, incremental effect on the overall project value.
Ceiba Completion Optimization: A Fast-Track Approach to Success
Authors: Claiborne E. B. , Malone B. P , Marshall J. C.
Published: December 2007

Triton Energy Ltd. (Triton) (acquired by Amerada Hess Corporation in August 2001) and Energy Africa (15% WI), set a benchmark for the oil industry by discovering and developing a deepwater Equatorial Guinea, West Africa field and establishing production to a FPSO in less than 14 months. The fast-track development project operated by Triton commenced in October 1999 following the Ceiba-2 confirmation well. The completion strategy and its success played a major role in realizing this world record achievement and continually improving well performance in the Ceiba field.1

As with any new field, development of the optimum completion strategy evolved based on lessons learned. Eight (8) producers, one (1) sidetrack and three (3) water injection wells have been completed to-date. The initial five (5) production wells (Phase I), utilized cased-hole completions. Four of these five wells employed single-trip perforating and gravel pack (STPGP) completion techniques. These completions produced upwards of 18,000 bopd with moderate skins. The fifth cased hole production well was completed using a single-trip perforating, gravel pack technique in conjunction with a hydraulic fracture treatment (STPFP). This resulted in an improved skin factor and Productivity Index (PI). The remaining three (3) producers were completed as open hole gravel packs using mineral oil based mud (MOBM) as the reservoir drill-in fluid (RDF). Three seawater injection wells have also been completed to date. Two (2) were performed as STPGP's and one (1) as a STPFP. These recent changes of methodology have proven successful in further enhancing productivity index and reducing skins.

The versatility and flexibility required to successfully incorporate the required strategy changes in such a short time frame, reflects the weighted risk taking approach and aggressive management style of the operating company and a strong commitment of the service sector.

Major Contributors to Project Success
Drilling Fluid Sweeps: Their Evaluation, Timing, and Applications
Authors: Hemphill Terry , Rojas Juan Carlos
Published: December 2007

Drilling fluid sweeps are commonly run in the field to help clean the borehole of cuttings that have not been removed with normal fluid circulation. Typically, these sweeps are used in vertical and deviated drilling operations. In high angle or extended reach wells, their use can be helpful in removing cuttings that have accumulated in sections where hole cleaning is not optimized. Sweep types usually fall into the following categories:

High-viscosity High-density Low-viscosity Combinations of any 2 of the above Tandem (one type followed by another)

Their effectiveness in the field is often quite spotty, often due to the application of a certain sweep type in the wrong drilling situation. Heretofore, there has been lacking a rigorous method of evaluating the effectiveness of sweeps at the rig site. Usually sweeps have been evaluated in the field based on observed or perceived quantities of cuttings coming over the shakers, a methodology that can be very subjective.

In this paper, a rigorous method of evaluating drilling fluids sweep efficiency is proposed. Here, information from pressure-while-drilling (PWD) tools and measured drilling fluid and sweep fluid properties is used to determine a mathematical prediction of "cuttings out". In short, the method relies on the difference between "mass in" and "mass out". Examples from field applications are given to illustrate the usefulness of this methodology.

With a more rigorous evaluation of drilling fluid sweep efficiency in hand, users can objectively determine the type and frequency of application of drilling fluid sweeps and rig time spent circulating out ineffective sweeps can be minimized.
Mechanisms of Bubble Formation by Pressure Decline in Porous Media: A Critical Review
Authors: Bauget F. , Lenormand R.
Published: December 2007

The modeling of primary production of heavy oils by solution gas drive is an active area of research. All the models, either written at Darcy scale or at pore scale (capillary network, population balance), account for the following mechanisms: bubble formation, bubble growth and gas flow. The first stage of bubble formation, also called bubble nucleation, is still controversial. In this paper, we discuss the existing nucleation models and demonstrate that the preexistence of bubbles is the only theory that is justified physically and can explain the ensemble of experimental observations. The preexisting bubbles are stabilized either by surfactants (models used for cavitation studies) or capillarity in crevices (models used in boiling). In both models, a given number of bubbles are activated at a given pressure drop. The only adjustable parameter is the distribution of diameters of the preexisting bubbles. This distribution is a property of the rock/fluid system that can be experimentally determined.

The other models used in literature are based on the formation of a stable nucleus by thermal fluctuations. They lead to the notion of nucleation rate that is in contradiction with experimental results.

We also discuss the terminology used in recent papers. Especially the terms of "instantaneous nucleation" and "progressive nucleation" are irrelevant if a mechanism of preexisting bubbles is assumed. They are also misleading since they lump the mechanism for bubble formation (statistics or preexistence) and the mechanism for pressure decline (either step or constant rate).
Investigation of the Relationship Between the Dimensionless and Dimensional Analytic Transient Well Performance Solutions in Low-Permeability Gas Reservoirs
Authors: Poe B. D. , Marhaendrajana T.
Published: December 2007

This paper presents the results of an investigation into the relationship between the dimensionless and dimensional pressure and rate-transient solutions of wells completed in low-permeability gas reservoirs. Solutions of the linear diffusivity equation are commonly used to model the performance of gas reservoirs using the pseudopressure and pseudotime integral transformations to account for the nonlinear fluid properties in the system and to effectively linearize the problem so that linear solutions can be utilized in the analyses.

Transient analysis techniques have been developed that improve the accuracy in estimating values of the pseudotime integral transformation, thus improving the accuracy of evaluating the reservoir and well properties from the production performance of low-permeability gas reservoirs, using analysis models based on analytic solutions of the linear diffusivity equation.
Interactions Between Drilling Fluid and Reservoir Fluid
Authors: Bureau N. , de Hemptinne J. C. , Audibert A. , Herzhaft B.
Published: December 2007

Severe environmental regulations lead to the use of biodegradable base oils such as heavy esters of fatty acids from natural origin for drilling applications. An appropriate knowledge of the gas solubility within the fluid in the well is essential for preventing risk of gas kick and gas hydrate formation whatever the pressure and temperature conditions. No relevant literature data exist for such long and polar alkyl chains in interaction with hydrocarbons coming from the reservoir. For this purpose, our study focuses on experimental data acquisition and modelling of both bubble pressures and densities for gas – oil mixtures i.e. ester – toluene – methane mixtures.

Bubble pressures are measured at 323.15, 363.15 and 393.15 K and densities at different pressures for each temperature.

Model compounds have been first used in order to allow the development of a predictive method. For validation purposes, measurements have been performed on a real reservoir fluid with an ester phase. Water and an emulsifier have been then added in order to evaluate their effect.

In a second step focused on modelling, high pressure phase equilibria are described using an equation of state. However, the classical cubic equations do not perform well since they don't take into account the possible molecular associations. Another equation has therefore been tested.

The chosen model is based on the Elliott-Suresh-Donohue equation of state; it uses the classical mixing rule and contains a term for association between molecules. The pure component parameters are calculated from the corresponding states principle, with the Somayajulu critical parameters. It allows an encouraging predictive description of the experimental results.

In order to improve the gas – oil equilibrium prediction, we propose correlations for binary interaction coefficients between methane and esters, and between methane and aromatic molecules.

Similarly, the description of the densities is improved by using a correlation for the volume translation.

Both of these correlations are dependent on the temperature and the molecular weight of the mixture components.

With this model, it is now possible to describe the phase equilibria of methane – heavy esters systems in a totally predictive way, with an accuracy of 16% (maximum 50 bar error) and to reproduce the volumetric properties with an error of 6%.

The final aim of this work is the study of a real oil based mud taking into account the presence of brine in our systems.

These systems will also be investigated at low temperature in order to describe the deep offshore conditions.
Design, Calibration, Characterization, and Field Experience of New High-Temperature, Azimuthal, and Spectral Gamma Ray Logging-While-Drilling Tools
Authors: Mickael M. , Phelps D. , Jones D.
Published: December 2007

Two new gamma ray tools have been developed, one provides high temperature total gamma ray measurements, and another delivers spectral gamma ray measurements while drilling. The high-temperature gamma ray tool can operate at temperatures up to 356°F (180°C) and survive to 392°F (200°C). It uses multiple two-detector banks of Geiger Muller Tubes. Five banks are used in the 4.75" tool and eight banks are used in the 6.75" and 8" tools. The tubes are arranged symmetrically to provide azimuthal measurements while rotating and/or sliding. The new spectral azimuthal gamma ray tool (SAGR) employs three high-efficiency scintillation detectors symmetrically arranged around the center bore of the drill collar. This design provides a superior total gamma ray measurement and spectral capability that has equivalent accuracy to a wireline spectral gamma ray tool.

Calibration of LWD gamma ray tools has always been problematic because the main gamma ray calibration facility at the University of Houston has a smaller borehole than the collar size of the majority of LWD tools. A procedure was developed to calibrate LWD gamma ray tools when the collar size exceeded 4.75" and could not be conventionally lowered into the API pit. Measurements were made with a 4.75" LWD tool in the University of Houston gamma ray formation to obtain an absolute reference standard. The tool was then used to create two secondary standards with larger boreholes to be able to calibrate larger-size tools. Comprehensive computer modeling was performed to validate the API measurements and develop environmental corrections.

The new spectral gamma ray sensor provides real-time K, U, and Th measurements. The spectral data of the three detectors are first aligned to a standard spectrum to compensate for gain changes due to temperature and electronics drift. The count rates are then summed and a full-spectrum least squares fit to K, U, and Th reference standards is applied to determine the K, U, and Th contents of the formation. The measurement is calibrated to the KUTh API standards at the University of Houston.

Details of the calibration, processing, and correction algorithms are presented. Field examples are presented to illustrate the applications, accuracy, and repeatability of the measurements.
Increasing Separation Capacity with New and Proven Technologies
Authors: Chin R. W. , Stanbridge D. I. , Schook R.
Published: December 2007

Compact separation has been a "buzz" word in design of new facilities for many years now as more reserves are being located in deeper waters. However, upgrading existing facilities to handle more production is also important. Third party processing, under-estimated reserves, or recently located nearby reserves result in higher rates. Space then becomes a premium especially in the deep water facilities where extra space may have been minimal in the design. This paper will discuss some new and proven technology not only for compact separation, but also for increasing gas/liquid separation capacities of existing vessels. Applications of the technologies will also be presented.
Rheology and Special Requirements on the Flow System and Equipment for Large Scale Injection, Production and Gathering of Viscous-Elastic Polymer Fluids in Chemical Floods and Methods to Solve the Problems that Emerge
Authors: Wang Demin , Youlin Jiang , Wang Yan , Gong Xiaohong , Wang Gang
Published: December 2007

Most flow systems and equipment for the injection, production and gathering of large amounts of fluid are designed for Newtonian fluids. Now, an increasing number of oil fields are on viscous-elastic flooding (for example, Daqing Oil Field alone injects and produces more than 70 million m3 of viscous-elastic fluid containing polyacrylamide [PAM] per year). After flooding by PAM fluids, besides an increase in recovery (in Daqing, the recovery increases more than 12% OOIP [original oil in place]), decrease in water cut (from more than 90% to about 70%), increase in production (in year 2001, Daqing produced about 9.8 million tons of oil by PAM flooding), it was seen that the flow of this type of fluid in production and surface systems and equipment has its special characteristics which in turn require special designs for the equipment and flow process. Otherwise, the efficiency and service life of each equipment and system will be low, energy consumption and mechanical degradation of polymer fluid high and vibration in the whole system serious. Sometimes, normal operation cannot be maintained.

This paper introduces the actual performance of the production and surface flow systems and equipment, points out the influence that the special rheologic characteristics, especially the viscous-elastic nature of the fluid, has on the system and the modification made. For example, there is a normal force acting on the beam pump sucker rods that cause pronounced eccentric mechanical wear on one side of the sucker rods and thereby very short service life span of beam pump wells; this normal force significantly lowers the efficiency of centrifugal pumps; increases the vibration and mechanical degradation in triplex pumps and the whole system; lowers the efficiency of maturing tanks and static mixers etc.

The modifications on the system and equipment and its results are shown. For example, the service life of beam pumps more than doubled; mechanical degradation of polymer in the system and triplex pumps decreased more than 50% and 70% respectively; and the energy consumption of mixing equipment decreased 80% etc.

The above should be of value to oil fields preparing to use large amounts of viscous-elastic fluids to increase oil recovery.
Modeling Reservoir/Tubing/Pump Interaction Identifies Best Candidates for Multiphase Pumping
Authors: Martin A. M. , Scott S. L.
Published: December 2007

Multiphase production systems are being considered as a development option for many fields on a worldwide basis. Engineers are faced with the challenge of selecting the best candidates to take full advantage of this novel technology. A review of the literature reveals that no guidelines have yet been published regarding this issue. This paper utilizes classical reservoir engineering methods to model the interaction of a surface installed multiphase pump with the reservoir and tubing. A derivative analysis of the backpressure equation is used to show the difference in incremental production among wells with different backpressure coefficients and exponents. A method was developed which combines well deliverability and decline data to forecast the impact of a multiphase pump on reserves, i.e. ultimate recovery. The results of this study indicate that: 1) wells exhibiting a low wellhead backpressure coefficient (n) make poor candidates for multiphase pumping; 2) plotting the derivative of the wellhead backpressure equation provides a means of defining a threshold, which must be reached before a multiphase pump, would provide value; 3) liquid loaded wells may yield the best response to a surface installed multiphase pump; and, 4) reduction of the backpressure on a well, through use of a multiphase pump, acts to increase the ultimate recovery for a well or field.
An Integrated Reservoir Characterization Study Matching Production Data and 4D Seismic
Authors: Kretz Vincent , Le Ravalec-Dupin Mickaële , Roggero Frederic
Published: December 2007

Our purpose is to evaluate the benefit of using time-lapse seismic in addition to production history for reservoir characterization. A new inversion methodology, based on the gradual deformation method, has been developed to integrate simultaneously different sources of information like 4D seismic related data and production data. This methodology was successfully validated on a geologically realistic 3D synthetic reservoir model.

An optimization procedure was developed to identify reservoir models consistent both with a first 8 year period of production data and 4D seismic related data. It is based upon two complementary numerical tools developed at the IFP: the FFT-MA generator and the gradual deformation method. The first one generates stochastic realizations for the reservoir model. The second one allows us for perturbing the realizations from a small number of parameters while preserving the spatial variability model. The optimization process was repeated starting from different initial reservoir models. The predictive quality of the constrained reservoir models was estimated comparing the simulated forecasts and the reference data for a second 8 year period of production data.

The proposed inversion method proved its efficiency for constraining geostatistical reservoir models to different sources of data. It is shown that conditioning reservoir models to saturation changes in addition to production data allows for improving significantly the reliability in the production forecasts.
Effects on Well Test Analysis of Pressure and Flowrate Noise
Authors: Archer R. A. , Merad M. B. , Blasingame T. A.
Published: December 2007

We have utilized sets of simulated well tests in an example well/reservoir model with an unfractured vertical well or a vertical well with a finite-conductivity (vertical) fracture to demonstrate the dependence of the estimated parameters and their confidence intervals on noise in the pressure and flowrate data. Uniformly distributed random noise is introduced into the pressure data and the resulting well parameter estimates are obtained using conventional means (analysis/history matching).

For the cases of a pressure buildup test in an unfractured well and the pressure drawdown cases performed on a fractured well, the estimated parameters are almost without bias — and the confidence intervals grow linearly with the magnitude of the noise. For the cases of pressure buildup tests performed on the fractured well, the estimated parameters are insensitive to the noise — which suggests that this case may not be well-posed for analysis.

Gauge drift and flowrate noises were also considered and the analysis results from the example well tests demonstrate that both of these kinds of noise are handled robustly by conventional well test analysis techniques.