bluuebunny/crossref_metadata_2025 huggingface dataset:
Rock Structure Characterisation Through Imaging Techniques Integration
Authors: Radaelli F. , Balzarini M. , Nicula S. , Ortenzi A.
Published: December 2007

Imaging techniques are widely used in the oil industry, but their integration is much less common.

Here we present the relevance, in rock structure characterisation, of the integration of Magnetic Resonance Imaging (MRI), X-ray Computed Tomography (X-ray CT) and Scanning Electron Microscopy (SEM), based on different physical principles and investigating different rock volumes.

A set of experimental studies on various fields with different lithologies (chalk, brecciated dolostone, limestone, calcarenite and conglomerate) is presented.

The results of these applications demonstrate that the integration of different approaches greatly improves the characterisation of internal rock structure.

P. 23
Realistic Fault Modelling of Stacked Reservoir Sands in the Niger Delta
Authors: Onyeagoro U.O.
Published: December 2007

Hydrocarbon bearing fields in the Niger Delta typically comprise multiple reservoirs stacked over intervals of 10,000ft thickness. Listric faulting is prevalent in these fields causing problems in generating accurate representation of structural geometries. In SPDC Nigeria a study was initiated to develop a route to incorporate realistic structural geometries in static and dynamic reservoir modelling. This was applied to the Soku field using the 3D structural modelling program Earth Vision and Shell's proprietary 3D reservoir modelling package GEOCAP. The field, covering an area of approximately 112km2, was discovered in 1957. In-place volumes are estimated at 900 MMstb of oil and 5000 MMMscf of gas. The results of this study are used mainly in the current infill drilling campaign and will in future be used to support dynamic reservoir simulation studies. In Earth Vision, a complex fault tree diagram was used to describe the arrangement of the faults in an hierarchical order. A structural model with a thickness of 4000ft was constructed consisting of 20 realistic faults and 25 fault- blocks. This initial fault framework was then exported to the GEOCAP reservoir modelling system for integration with well planning and reservoir engineering software. Subsequently, the internal reservoir architecture was modelled integrating 3D seismic, sedimentological, petrophysical and reservoir engineering information, honouring all available well data. The GEOCAP well planner was used within this realistic fault model to plan for infill drilling locations. The first of these wells was recently completed and successfully tested to 100 MMscf/d gas and some 7,000 b/d condensate. The procedure for representing realistic faults was instrumental to the success of the well and is recommended as a routine for future well planning and reservoir studies in the Niger Delta.

P. 79
Slim-Hole Sidetrack Cuts Costs by 50%
Authors: Scott I.J. , Black F.J.
Published: December 2007

The Shell/Esso Brent Field contains many small pockets of oil; 0.5 to 1.5 million barrels that are uneconomic to develop using conventional sidetrack techniques. The sidetrack of Brent Bravo well BB-08 takes advantage of the latest slim- hole through tubing technology reducing the well costs by 50% over a conventional sidetrack. The operation was carried out with a conventional rig utilising a slim-hole drillstring to exploit an expected 1.5 million barrel target and also provide a technical comparison with a coiled tubing sidetrack. The entire operation was carried out through the existing xmas tree and completion string.

The original perforations were isolated then a through tubing whipstock was used to exit through the existing 7" liner and 9-5/8" casing strings. A 1500 ft 3-7/8" hole section was drilled with a steerable BHA, which gave an average dogleg of 9 deg/100 ft in the build section. The mud weight required for hole stability meant high over-balance pressures through the reservoir section. The hole was logged with a wireline conveyed resistivity tool. A 2-7/8" liner was run and cemented in place with a liner top production packer to provide well integrity. Wireline access into the 2-7/8" liner was not possible due to debris and therefore the well had to be cleaned out with coiled tubing before perforating.

This paper describes the planning process, the operations (from abandonment to perforations), lessons learned and the teamwork which made it all possible.

P. 111
Field Data vs. Theoretical Model to Quantify Drilling Efficiency and Disruption
Authors: Putot C.J.M. , Perreau P.J. , Constantinescu A.
Published: December 2007

Mechanical and kinematics data at the bit have been collected during drilling operations and organized to identify optimal drilling efficiency. Transitional conditions towards abnormal behavior have been distinguished. Normal drilling is usually characterized by regular linear relationships between global control variables at the bit, which approximately correspond to an up scaling of a local Mohr Coulomb type failure mechanism of the rock. Most of our experimental data confirm this classical disposition. However, considerable departure from these relationships is noted, especially when there is BHA resonance or when there is partial balling at the bit. The field tests presented here allows us to verify classical theory and to draw up new guidelines for behavior in non- optimal or dangerous, evolving operating conditions, such as those that occur under poor cleaning conditions. The main features of a mechanical structuring model involving transition towards low efficiency conditions are presented, and it is shown how this model confirms our interpretation of field data. The model couples the drillability of rock and the general dynamics of the bit in an original and synthetic way. It makes it possible to understand and test the sensitivity of bit response to variables such as "weight on hook", torque on the drillstring and flow rate of the fluid.

P. 119
Cost-Effectiveness and Flexibility Through the Brent Gas-Lift Insert String Completions
Authors: Brakel J.D. , Taggart I. , Yahia Z. Bin
Published: December 2007

The Brent field, developed as an oil producing field in the mid 70's, is now approaching the end of its economic life. However, the large quantity of remaining oil, although only 40% of initial reserves, and the high Gas-Oil ratio of the oil allow extended production from the field by reducing the reservoir pressure. The de-pressurisation will add some 10-15 year of economic life to the field.

The de-pressurisation project, unique in the world due to the size and complexity of the Brent field, brings many uncertainties. The well completion design is key in the management of these uncertainties. Cost-effective reservoir management (zonal solation) is a pre-requisite and the choosen completion design should accommodate sand, scale and even H2S management. Furthermore certain wells will require artificial (gas) lift, although the number and location of these wells will be largely unknown up front.

The adopted monobore completion design combines maximum flexibility and cost-effectiveness with simplicity and is readily adaptable to gas lift installation. The Brent monobore completion design has reduced cost by 30% and installation time by 65% as opposed to the Multi-Straddle Assembly completion run previously in Brent. Key features of the completion and retrofit gas lift installation are described in this paper.

P. 169
DeepLook: A Progress Report on Collaboration and Funded Research
Authors: McCaffery Frank G.
Published: December 2007

This paper provides a progress report on the DeepLook Fluid Imaging Collaboration during its second year of formal operation. Its mission is to create a significant and fundamental improvement in the oil industry's ability to measure reservoir fluid and rock properties, and monitor fluid movement, at distances of 10 to 200 meters from existing wells. This challenge is being approached through identification and sponsorship of promising breakthrough technologies primarily developed for applications outside of the oil industry, from what is termed "Far Market" high-technology providers.

Discussion is concentrated on the following subjects:

Objectives and start-up actions of the collaboration - A brief history of DeepLook's organization, current participants and funding, and the roles and activities of the three technical teams charged with developing R&D projects in the areas of Detection, Monitoring, and Prediction. Efforts leading to sponsorship of R&D efforts on a new downhole sensor for fluid characterization - This topic is chosen for more detailed review due to the author's involvement in leading the Monitoring team that identified and guides the project. The sensor was originally designed for chemical weapons treaty verification and nonproliferation work. Our project seeks to evaluate its use for detecting fluid type in a flowing well, as well as for monitoring fluid saturation changes in reservoir rock when placed in open or cased wellbores, including microboreholes. Brief review of other DeepLook R&D projects - Five other projects are underway besides the downhole sensor effort. These include studies being performed by researchers at several U.S. National Laboratories and a NASA facility. The current projects are structured as feasibility or scoping studies, with a built-in deliverable of defining follow-up work if initial demonstrations from the first phase are successful. Approval of proposed project extensions will be made in competition with new investment opportunities that have been identified, and according to available funds. 4.Challenges and lessons learned affecting the ultimate success of the collaboration - A collaboration as complex as this one is expected to encounter growing pains. Issues faced by DeepLook are discussed, and next steps are noted.

P. 219
Field Test Results and Processing Methods for Remote Acoustic Sensing of Stratigraphic Bed Boundaries
Authors: Leggett J.V. , Dubinsky V. , Bolshakov A. , Nakken E.I.
Published: December 2007

Determining the position, above and below a deviated wellbore, relative to key drilling markers and stratigraphic features such as fluid contacts, geological markers and reservoir target boundaries has been a major goal for "Tieing-in" to a reservoir model while drilling. Acquiring, processing raw data, and identifying these features in real time, at ranges to 20 meters, in a measurement while drilling (MWD) tool has not been possible with existing MWD Formation Evaluation and geo-steering systems.

An experimental pipe conveyed field prototype acoustic tool was run to echo range for identification of certain stratigraphic features and to make Sonic measurements (acoustic velocity/slowness). The Sonic measurements were used to insure accurate formation velocity since a combined measurement was essential in determining the correct distance to the feature. The experiment was run with a wireline and wet-connector inside the pipe for rapid two-way communication, thus enabling a quick view and analysis of the large amount of data recorded. A set of data analysis techniques was developed to emulate real-time downhole data processing. These techniques also are reviewed in the paper. Additionally, this paper presents the field test results relating to stratigraphic positioning, with comments for other key applications benefits such as reservoir navigation, formation dip estimation, coring point selection, seismic correlation, and high resolution near wellbore reservoir imaging.

P. 225
Economics of Downhole Oil-Water Separation: A Case History and Implications for the North Sea
Authors: Shaw Chris , Fox Mike
Published: December 2007

This paper describes a system used for the separation of oil and water in the far reaches of the wellbore where the separated produced water is re-injected into a zone accessible from the same wellbore. Successful application of this technology in low risk wells has been achieved and documented1. Risk is defined here as a function of workover cost and deferred oil production; high risk therefore being a prolific well with high workover costs. Application of this separation technology in high risk wells can only occur when the issues of the technology, cost and reliability have been defined. The more sophisticated completions that will be required for high risk wells will be more reliable, while the prolific nature of the wells gives a rapid return on the investment.

This paper outlines the factors that make up the economic decision whether to install such a system and, using a low risk case history, demonstrates the favorable economics of installing a separator system in a given application. Using the low risk example, it is shown how the ideas can be extrapolated to a typical North sea well where, although higher risk, the potential reward is also far higher.
Water Shut-Off: Simulation and Laboratory Evaluation
Authors: Surguchev Leonid M.
Published: December 2007

Many North Sea reservoirs are produced under waterflooding. With time the production wells start to experience water breakthrough problems due to incorformance of flood, gravity underride, presence of high permeable thief zones. The most common water shut off methods today are polymer gel treatment, cement squeeze and mechanical isolation. The polymer gel systems have several important advantages in comparison with other methods:

– The polymer system is injected as a solution and can penetrate deep in the reservoir and reduce permeability in the near wellbore area. – The injected solution can move up and down the outside well bore, sealing cracks and existing microannuli especially in poorly cemented high permeable sands. – Gel left in the well bore can be cleaned out by jetting via coiled tubing with either a mild acid or water. – Not expensive due to reduced crew and rig time.

During recent years polymer gel systems with Disproportional Permeability Reduction (DPR) effect were developed and successfully tested in the laboratories for North Sea reservoir conditions. Selective gels preferentially blocking water phase in the reservoir make well treatments more attractive, especially for advanced wells with complicated completion design (deviated, horizontal, multilateral). In spite of relatively small volume of chemicals involved in well treatments, evaluation of potential and possible benefits of near well treatments remain an important issue. Accurate near well model is required to simulate production of the well and effects of chemical treatment in the near well bore. Correct modelling of inflow is as important as representative modelling of gel generation process. Fine grid radial models allow to account more accurately for near well reservoir properties based on available log, core and production data. Template well models were established and used for screening of potential candidate wells for treatments. They proved to be useful in history matching and evaluating treatment effect in several field pilots in the North Sea.

The paper will discuss the mechanism of water shut off, recent laboratory studies and screening results, give simulation and field evaluation examples for North Sea wells.

P. 447
Water Shut-Off Using an Inflatable Composite Sleeve Polymerised In-Situ. A Case History on Forties Delta
Authors: Leighton J. , Saltel J.L. , Morrison J. , Welch R. , Pilla J.
Published: December 2007

An expandable composite patch, run on electric wireline, was used to shut-off water producing perforations for the first time on Forties Delta. This is a new technology, based on using insitu polymerisation to exploit both the deformability of a flexible composite and the mechanical characteristics of a polymerised composite. The results of this operation have shown an inflatable composite sleeve can be used as an efficient and cost effective solution for reducing unwanted water production.

P. 455
Microbial Clarification for Treating Reinjected Oilfield Brine
Authors: Philippovich N. , Winter J.
Published: December 2007

Ever rising water volumes and processing costs in the oil field have spurred OMV to look for alternatives to traditional water processing. Despite an elaborate central multistep water treating system, increasing injection pressures, water fouling in the pipelines and reservoir souring were noticed.

A comprehensive water analysis program was instrumental to understanding that available oxygen, nutrients and the recycling of water promoted the growth of bacteria in the large distribution system. Since, on the long run, no biocide proved effective, a soft strategy was adopted: by removing key components (sulfate, biodegradable carbon) essential for bacterial growth, the population could be starved and the injection water quality stabilized.

The feasibility of this concept was tested in a laboratory clarification apparatus that helped establish critical parameters, optimise additives and define performance limits. After due accommodation time, bacteria recovered from a refinery waste treatment plant could eliminate >90% of BOD and the effluent water was biologically inert. At the same time, a field pilot plant was installed that now has been injecting biologically processed water since fall of 1996. On- site core experiments demonstrate superior injectivity compared to normal brine. Other parameters (COD, TOC, turbidity, membrane filterability) support these findings.

A revamp of the whole water conditioning system is now underway. So far, benefits of the new strategy have been considerable savings in biocide expenditures, reduced injection pressures, and a lower H2S production.

P. 477
Natural, Downhole Separation and its Impact on Production Performance
Authors: Asheim H.
Published: December 2007

Gravity and viscosity differences will cause gas-liquid separation already along the completed interval. For wells completed over longer intervals, the heavier liquid will accumulate and may build up sufficient static pressure to seep back to lower layers of the reservoir.

The model developed computes production performance with two-phase inflow, two-phase flow along the completed interval and possible back-seepage of accumulated liquid. From the results follow that both the apparent inflow performance and the gas-liquid ratio observed at surface are affected.

It is shown that downhole separation may be constrained by either back-seepage to the reservoir, or counter-current flooding along the wellbore. The liquid backflow rate limit due to flooding has been derived explicitly, providing a design parameter for downhole separation devices.

P. 497
Well Log Preprocessing and Modelling for Quantitative Seismic Interpretation
Authors: Olotu S.O. , Olukayode A.O.
Published: December 2007

Critical to quantitative seismic interpretation (QSI) is a good well to seismic calibration (WTSC). The technical challenge in the calibration of seismic and well datasets is accounting for various data-impacting effects prior to merging of these two sources of information. These effects are inherently introduced by method(s) employed for accessing and acquiring (drilling and well logging) data from the subsurface.

In the past, it was common practices to correct for effects such as drilling, fluid invasion, washout and other wellbore effects. Experience has shown that corrections now have to be made for inadequacies of tools in certain geologic settings (thinbed, soft or hard shales) that may lead to erroneous interpretation.

The petrophysical modelling necessary for the correction of the aforementioned effects require interpretative editing and subsequent generation of correct logs in zones that are giving spurious readings.

This paper demonstrates with two case studies for the essential data b and t.

In the case of b - Borehole geometry, fluid invasion and residual virgin formation porefill effects affect nuclear porosity tools such that relatively high porosities (and hence low b) are interpreted across shales compared to sands. These effects are also manifested across sands particularly when HC bearing.

In the case of t - Washouts, residual virgin formation porefill and possible formation alteration result in spurious slow travel time.

Combining the b and t data would normally result in erroneous WTSC and the interpretation of acoustically soft environment. This will be conflicting with the acoustically hard environment indications from the resistivity and where the hole conditions are good - b and t.

The correction and petrophysical modelling were achieved by concomitant interpretation of all available log data with the various responses referenced to known lithology, porefill and compaction trend(s). Consistency in stacking patterns is recognised from log data combining shallow and deep readings. as well as varying vertical resolutions. This approach has given better result in WTSC and rock property modelling which subsequently has improved QSI immeasurably.

P. 511
Steady-State Upscaling: From Lamina-Scale to Full-Field Model
Authors: Pickup Gillian E.
Published: December 2007

In recent years, the impact of small-scale permeability structure on hydrocarbon recovery has been demonstrated, and upscaling procedures, such as the Geopseudo Method, have been developed to scale-up from the lamina scale, using the hierarchy of geological length scales. However, upscaling is very time consuming, so many engineers still input rock curves into large-scale simulations,

In this study, we show how the process may be speeded up using steady-state methods for calculating the pseudo functions. A three-stage scale-up of a fluvio-aeolian reservoir was carried out. Capillary equilibrium was assumed for the first two stages, and viscous-dominated steady-state for the third stage. Two different wettability cases were examined - water-wet and intermediate-wet. The effect of using the small-scale pseudo relative permeabilities depends on both nature of the heterogeneities and on the wettability. In this study the recovery was reduced, especially in the water-wet case.

P. 527
Core-Log Integrated Approach to Seeding Reservoir Models with Physically Consistent Porosity, Permeability, and Saturation Data
Authors: Olukayode A.O. , Ahonsi B.
Published: December 2007

Essential to hydrocarbon reservoir modeling are input data of porosity, permeability, and saturation. These inputs are derivable from different sources that may not be linked, thereby giving room for inconsistency in interpretation of the reservoir.

A case study from the Niger Delta shows that when all three data sets are coupled into a cap-curve based saturation function, this problem is resolved. Using a generalized form of a cap-curve equation, interpreted porosity and permeability were used to estimate saturation profiles across hydrocarbon reservoirs.

The hydrocarbon saturation calculated by the capillary pressure curves demonstrated good agreement with the Waxman-Smits log derived saturation. In all reservoirs studied to date, good log-to-cap-curve derived saturation calibrations were observed to depend on the accuracy and precision inherent in the generalized synthetic cap-curve equation.

Improved predictions of hydrocarbon saturation from cap- curves were achieved through the use of flow zone indicator (FZIT) as fitting parameter, where FZIT combines both porosity and permeability in these relationships.

Base case deterministic STOIIP from models exceeded previous expectation values by 20%. Further, the value adding calibrated permeability and bulk hydrocarbon distributions ensure that ultimate recoveries, and hence field economics, can be better estimated.

NMR technology presents opportunity to extend the generalized synthetic cap-curve equation and data calibration methodology to other reservoirs / environments with minimal resource investment.

P. 537
Modern Reservoir Modelling for Rehabilitation of a Giant Oil Field
Authors: Bolotnik D.N. , Sarkisov G.G. , Sharifullin F.A.
Published: December 2007

More than 400 wells segment of Giant Russian oil field, having long term production history, was modelled using modem 3D geological and flow simulation software. Complex reservoir geology, large volume and low quality of geological/production historyr data were complicating field modelling with standard (2D) software tools. The geological models obtained with standard 2D geological software tools were not detailed enough, did not allowed fast detection of input data errors, so it was impossible to achieve history match of production data.

Solution of these problems was found by using modern mapping and 3D geological modelling software algorithms. Fine 3D geological model allowed to integrate all the geological data and was detailed enough to describe the real field geology. Modern upscaling tools were used to upscale the model from fine geological grid to the coarse simulation grid with minimum loss of heterogeneity details. 3D visualisation tools were useful in quality checking of input data and error detection.

Simulation model with a large number of grid blocks was handled by modem efficient simulation software and allowed to history match this large segment in a very short time by using limited hardware resources.

P. 45
A Global Perspective on Sand Control Treatments
Authors: Sherlock-Willis Terri M. , Morales R.H. , Price P.
Published: December 2007

Sand control treatments are typically in the form of gravel- packs (slurried-pack or water-pack), frac-packs or horizontal completions using screens only. When selecting a sand control method, it is necessary first to understand the formation sanding mechanism(s), including the response to pressure depletion and drawdown, and second, to select the most appropriate sand control completion. However, because of economical limitations, traditional practices and/or lack of sufficient data, the selected sand control completion is not always the best one. Alternately, the success of the completion maybe compromised.

The success of a sand control treatment can be described in terms of operations and well performance. In recent years, significant progress has been made to improve well performance, by focusing on proppant carrier fluids, placement methods, pumping/blending technique and downhole completion hardware. In addition, sand control software simulators have been evolving rapidly to meet the demands of improving the well's productivity. This paper summarizes regional sand control preferences, highlights advances in new teclmology and offers solutions to common problems in various completions techniques.

The industry will gain benefits from lessons learned from the various sectors of the world. We identify possible causes for failure; i.e., improperly designed treatments typically result in inefficiently packed annulus and perforation tunnels, sand bridges, and ultimately, premature screenouts. Additionally, general recommendations and guidelines are given based on the evaluation of the relevant treatments.

P. 201
Interpretation of Falloff Tests on Fractured Wells of the Barsukov Oil Field in Western Siberia
Authors: Dros A.N.P. , Kuznetsov A.M. , Hagoort J.
Published: December 2007

The Barsukov field is a large oil field in Western Siberia that is being developed by waterflooding. The field has some 700 production wells and over 100 injection wells. In most of the injection wells water is being injected above the formation parting pressure, and as a consequence waterflood hydraulic fractures extend from the wells into the reservoir.

The injectors are regularly tested by means of fall-off tests. We have interpreted about 250 falloff tests in 80 different wells using the conventional graphical analysis methods for transient pressure tests, i.e. pressure-derivative analysis for flow regime identification, analysis of early-time fracture storage flow, and analysis of the linear and radial flow regimes.

A large number of the tests show pronounced storage effects, which can be attributed to fracture closing. Fracture size estimated from the storage period correlates well with the fracture size derived from the linear and radial flow regimes. Falloff tests are excellent tools for estimating the size of waterflood induced fractures.

P. 363
Industrial Application of Vortex Tube Separation Technology Utilizing the Ranque-Hilsch Effect
Authors: Lorey Manfred , Steinle Jurgen , Thomas Keith
Published: December 2007

A major processing step when treating gas is the removal of components such as heavy hydrocarbons or water. This is done either to recover saleable liquids or prevent hindsance during gas transportation (e.g. hydrate formation or two-phase flow). The Vortex tube device provides a novel and useful addition to the range of equipment available for this application. Vortex tube equipment has been used for improved separation in comparison with a Joule-Thomson system, without entering into the cost and complexity of a true is entropic system such as a turbo-expander unit. The relative advantage of the vortex tube is dependent upon the inlet conditions of the gas and available pressure drop. An optimum pressure drop of 25 - 35 % of the inlet gas pressure has been confirmed in practice. It is expected that future applications of vortex tube units will be concentrated where performance improvements over Joule-Thomson units, at low capital cost, are required.

P. 471
An Assessment Of The Cost Of Geothermal Power
Authors: Sapre Ashok R. , Schoeppel Roger J.
Published: December 2007

A technoeconomic model has been developed to assess the economic feasibility of generating electric power from the lower temperature gradient geothermal reservoirs. The cost evaluation in the numerical model is based primarily on three factors:the choice of the conversion system,the design of the production and transportation system, andthe natural surroundings in the area.The model is shown to be capable of evaluating the cost of geothermal power under varying technoeconomic and environmental conditions.

Introduction

The availability of domestic energy resources to meet future energy demands appears to be in doubt, especially if attention is restricted to only the conventional sources of energy such as natural gas, liquid petroleums coal, and uranium. Natural gas and petroleum may be resource petroleums coal, and uranium. Natural gas and petroleum may be resource limited while coal and uranium face many technological, environmental, and socioeconomic problems.

The energy supply situation is especially critical for the electric power industry. Whereas the demand for all energy resources has been power industry. Whereas the demand for all energy resources has been doubling every 15 years, electric power requirements are doubling in less than 10 years. The growth of the power industry is expected to be even faster than it has been, since electricity is perhaps the most versatile and cleanest form of end use energy.

In these circumstances, it appears prudent to consider supplemental domestic sources of energy especially for use in power generation.
Quantitative Interpretation of Temperature Logs
Authors: Keller H.H.
Published: December 2007

A mathematical model has been developed that can be used to determine fluid injection profiles by matching measured temperature logs. profiles by matching measured temperature logs. The method consists of assuming a fluid injection profile and calculating a temperature profile for the time of the measured log. The profile for the time of the measured log. The assumed injection profile is adjusted by the user until a suitable match of the calculated and measured temperature profiles is obtained.

Introduction

Temperature logs have been used to determine qualitatively the distribution of injected fluids in a formation. There has been recent interest in the theory of temperature logging, seeking meaningful quantitative interpretations.

A mathematical model has been developed that describes the thermal behavior of an injection well, the surrounding earth, and the formation receiving the fluids. A description of this model and an example of its use are presented in this paper. Although written presented in this paper. Although written specifically for the injection of acid into a formation, the model can also be used to interpret logs run after injection of any nonreactive, noncondensing fluid. It is also useful for predicting formation temperature distributions during fluid injection.

DESCRIPTION OF THE MODEL

The physical system consists of a radially symmetrical cylinder surrounding a wellbore, as shown in Fig. 1. This region is initially at the undisturbed geothermal temperature distribution. Fluid injection at known rates for a specified period of time occurs. This fluid enters a permeable formation with some unknown distribution. The fluids flowing down the injection pipe exchange heat with the surroundings and enter the formation at an unknown and, likely, varying temperature. The fluid flow into the formation causes a disturbance in the initial temperature distribution, which is dependent on the volume of fluid injected. This disturbance is then recorded on a temperature log run soon after the termination of fluid injection. The distribution of fluids into the formation may then be inferred from this log. To describe this sequence of events, the following mathematical model was developed.

Assuming radial symmetry, an energy balance in the region exterior to the wellbore gives the equation:

......................(1)
Numerical and Analytical Well Test Analysis: A Case History
Authors: Lee W. John , Spivey John P.
Published: December 2007

In this paper, we present a case history of integrating numerical and analytical well test analysis methods to interpret the pressure and production history of a complex, multilayer, multiphase reservoir. Some engineers believe that recent improvements in analytical models have made numerical modeling for well test interpretation all but obsolete. Others believe just as strongly that numerical models should be used for routine well test interpretation. Still others believe that both tools are useful, and that a combination of the two approaches provides the best general strategy for reservoir characterization.

This field case focuses on the Gas Research Institute (GRI) Staged Field Experiment (SFE) No. 2. This well was hydraulically fractured. A variety of different analysis techniques were applied in order to evaluate the consistency between reservoir and fracture properties estimated by the different methods of analysis.

Analysis methods applied to the flow and buildup tests performed on this well include type curve matching using analytical solutions, numerical modeling with single-phase, multi-layer radial and Cartesian grids, and numerical modeling with multi-phase, multi-layer radial and Cartesian grids. The simpler models were able to match segments of the production and pressure history; only the full multiphase, multilayer model was able to satisfactorily match the complete production and pressure history.

We have found that an approach combining analytical and numerical models has been the most successful strategy in our work. As in this field case, analysis begins with the simple models and proceeds through more complex models as necessary to match the reservoir behavior in the desired detail.
Wellbore Liquid Blockage in Gas-Condensate Reservoirs
Authors: Ahmed Tarek , Evans John , Kwan Reggie , Vivian Tom
Published: December 2007

Gas condensate reservoirs have long presented production problems when the pressure around the well bore drops below the dewpoint pressure. The formation of the condensate around the well bore can be thought of as an additional "skin" that causes a reduction in the gas flow rates. Many processes have been used successfully to prevent or reduce the formation of liquids within the entire reservoir, such as pressure maintenance schemes and gas cycling processes. The pressure maintenance scheme is designed to keep the reservoir pressure at or above the dewpoint pressure while the gas cycling process is intended to reduce the liquid dropout by vaporization.

Often times the pressure in the near-wellbore region of the reservoir falls below the dewpoint pressure, while the pressure in the reservoir remains higher than the dewpoint pressure. As the near–wellbore pressure drops below the dewpoint pressure, retrograde condensation occurs leading to the formation and then the mobilization of the condensate phase towards the producing wells. The liquid phase accumulates in the near wellbore region, forming a ring, which progressively reduces the gas deliverability.

This study is designed to provide an insight into the mechanism of gas injection process in reducing gas-well productivity losses due to condensate blocking in the near wellbore region. The effectiveness of lean gas, N2, and CO2 Huff ‘n’ Puff injection technique in removing the liquid dropout accumulation in and around the wellbore is evaluated. Results of the study show the importance of selecting the optimum injection volume and pressure for the successful use of the Huff ‘n’ Puff process in gas condensate reservoirs.
Novel Application of Nondamaging Polymer Plugs with Coiled Tubing Improves Efficiency of Temporary Well Isolation Projects
Authors: Beall Brian B. , Suhy Thomas E.
Published: December 2007

Temporary well isolation projects have been successfully performed using a non-formation damaging polymer plug and coiled tubing. Previously used conventional kill muds can cause severe formation damage, reducing productivity once the well is put back into production. Other concerns while performing workover operations include the stability of casing in older wells to support inflatable plugs and the entry size to expansion diameter required to set the packer in each well. Use of a crosslinked polymer plug in conjunction with coiled tubing achieved accurate placement while avoiding the problem of overdisplacement. The crosslinked polymer plug protected the formation while supporting the kill fluid allowing for multiple casing string top joints to be cut and welded, along with wellhead replacement to be accomplished.

A second application of this non-damaging temporary isolation plug has been to control sloughing shales. These shale fragments tend to bridge off on ledges located above gauge hole sections causing problems running and setting production casing through the caving area. The crosslinked polymer plug has been used to suspend the shale fragments allowing the casing packer to be un-set and lowered through the problem area without any problems.
Real-Time Pressure Diagnostics Used To Improve Pre-Treatment Frac Design: Case Studies in the Antrim Shale
Authors: Dozier G. C. , Sutton T.
Published: December 2007

Over thousands of fracture treatments have been performed in the Antrim Shale of Northern Michigan. Very few have been altered significantly based on pressure data acquired from each preceding treatment. In essence, there has been very little evolution in how operators stimulate the Antrim. Primarily, this is due to the inability to accurately model (fracture) the effect of natural fractures in the Antrim Shale. Nevertheless, it is possible to use these models to analyze pre-treatment pressure responses to produce a more efficient frac design and improve the resulting frac conductivity. As the industry moves away from the "cookie cutter" frac design towards one specifically design, with minimal additional time and effort, for the well, a mere 10 mcf/d/well increase in production over a period of 10-15 yrs becomes very economical.

This paper will illustrate simple diagnostic tests that can be performed prior to each fracturing treatment to give good indication of fluid efficiency localized rock stress. Under real-time circumstances, a 10-15min injection test followed by a complete fall-off can yield an abundance of information regarding the viability of a particular fracturing treatment.

In the Antrim Shales on Northern Michigan, these diagnostic techniques have been used successfully to determine leak-off, closure, fracture extension and various other parameters essential in designing a fracturing treatment. In addition, pre-treatment results have been linked with the success or premature screen-out of particular wells in the Antrim. Through case studies, this paper will show a logical progression of data analysis based on diagnostic results.

Resultantly, a fracturing treatment can be designed or altered on location based on actual reservoir response and measured stresses. In turn, operators can regain a measure of predictability in controlling fractured behavior by tailoring a unique solution for each well without excessive time or added cost.
A New Approach to Predict Bit Life Based on Tooth or Bearing Failures
Authors: Bilgesu H. L. , Altmis U. , Ameri S. , Mohaghegh S. , Aminian K.
Published: December 2007

This paper presents a new methodology to predict the wear for three-cone bits under varying operating conditions. In this approach, six variables (weight on bit, rotary speed, pump rate, formation hardness, bit type, and torque) were studied over a range of values. A simulator was used to generate drlling data to eliminate arrors coherent to field measurements. The data generated was used to establish the relationship between complex patterns.

A three-layer artificial neural network was designed and trained with measured data. This method incorporates computational intelligence to define the relationship between the variables. Further, it can be used to estimate the rate of penetration and formation characteristics.

The new model was successful in predicting the condition of the bit. In this study, the value of 0.997 was obtained by the model as the correlation coefficient between the predicted and measured bearing wear and tooth wear values. The validity of the model was demonstrated with data from an existing field.
Prediction of Frictional Drag and Transmission of Slack-off Force in Horizontal Wells Using Neural Networks
Authors: Sadiq Tanvir , Gharbi Ridha
Published: December 2007

The use of mud motors and other tools to accomplish forward motion of the bit in extended reach and horizontal wells allows avoiding large amounts of torque caused by rotation of the whole drill string. The forward motion of the drill string, however, is resisted by excessive amount of friction. In the presence of large compressive axial loads, the drill pipe or coiled tubing tends to buckle into a helix in horizontal boreholes. This will cause additional frictional drag resisting the transmission of slack-off force to the bit. As the magnitude of the frictional drag increases, a buckled pipe can become "locked-up" making it almost impossible to drill further. In case of packers, the frictional drag may inhibit the transmission of set-up load to the packer. A prior knowledge of the magnitude of frictional drag for a given axial force and radial clearance can help avoid lock-up conditions and costly failure of the tubular.

In this study, we present a neural network model for the prediction of frictional drag and slack-off load transmission in horizontal wells. Several neural networks with different architecture were designed and tested to obtain the most accurate prediction of these parameters. After cross-validation of the neural network, a two-hidden layer model was chosen for simultaneous prediction of frictional drag and slack-off load transmission.
History and Potential Future of Improved Oil Recovery in the Appalachian Basin
Authors: Blomberg John R.
Published: December 2007

Although many concepts of Improved Oil Recovery (IOR) were first developed in the Appalachian Basin, early IOR methods were often inefficient and the quantity of oil in place in the various fields was small in comparison to many of the reservoirs found later in other states and countries. For these reasons, a lot of IOR investment money and expertise was not directed to the Appalachian Basin (Basin). This paper generally reviews the IOR methods used and crude oil recoveries in the five oil producing states in the Basin. A discussion is then presented of producing zones and IOR methods that might be successful in the future. Other aspects that could influence IOR development activity such as oil price and domestic demand are also discussed.

While 1998 oil prices do not encourage IOR development in comparatively low recovery oil fields as generally found in the Basin, this paper could serve as a starting point for operators looking for future IOR prospects. This interest could be stimulated by a world oil crisis that demanded an increased development of domestic crude oil production or by higher crude oil prices generated through any number of reasons.
Methods for Estimating Deliverability After Massive Fracture Completions in Tight Formations
Authors: Eilerts C. Kenneth
Published: December 2007

Three examples are provided for a desk calculation of the future deliverability of a gas well in a tight formation following massive hydraulic-fracture or nuclear-explosion stimulation. Methods of solution include a transient one that provides reservoir pressures at selected distances from the recovery well for a given recovery rate and well backpressure, and an arbitrary future stage of reservoir depletion. Steady-state equations have been devised to represent the effect of the improvement in permeability within the fractured area. permeability within the fractured area. A motive for developing the methods was to encourage the evaluation of fracturing prospects by persons who are not familiar with programmed computing.

Introduction

The practicability of extensive fracturing as a means of improving the deliverability of gas wells in low-permeability formations has been under investigation by the Bureau of Mines since 1963. A prediction was made of the benefits of nuclear stimulation for Project Gasbuggy in 1967. Following the stimulation, actual recovery data obtained by flowing the well in the chimney were analyzed by Lemon and Patel with results that substantiated much of Patel with results that substantiated much of the preshot estimate. Both investigations were made with the aid of programmed computing.

In view of the current widespread interest in methods for recovering natural. gas from the extensive low-permeability reservoirs of some western states, this present research was initiated to provide simple but dependable mathematical tools for appraising reservoir prospects. A progress report of the Natural Gas prospects. A progress report of the Natural Gas Technology Task Force provided background information for developing a set of equations to calculate deliverability of a well after massive fracturing. Most of the individual equations in this report have been used by engineers and scientists for many years, and it would be difficult to trace their origins.

In general, the treatment of problems has been to calculate the most deliverability that can be expected from a stimulated well. The result of a desk calculated analysis is intended to be as accurate as the approximations will permit, but is always an upper bound on the permit, but is always an upper bound on the deliverability to be expected. Approximations have been used to simplify procedures and to minimize the effort required for analysis. If a reservoir prospect is marginal or favorable, it should be reassessed by use of complete computing programs that give effect to variable properties and full consideration to all factors properties and full consideration to all factors that affect material balance. If a prospect is unfavorable, it can be rejected.

The equations required for calculating deliverability are described in the Appendix.