bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrating Dynamic Data Into High-Resolution Reservoir Models Using Streamline-Based Analytic Sensitivity Coefficients
Authors: Vasco D.W. , Yoon S. , Datta-Gupta A.
Published: December 2007

One of the outstanding challenges in reservoir characterization is to build high resolution reservoir models that satisfy static as well as dynamic data. However, integration of dynamic data typically requires the solution of an inverse problem that can be computationally intensive and becomes practically infeasible for fine-scale reservoir models. A critical issue here is computation of sensitivity coefficients, the derivatives of dynamic production history with respect to model parameters such as permeability and porosity.

We propose a new analytic technique that has several advantages over existing approaches. First, the method utilizes an extremely efficient three-dimensional multiphase streamline simulator as a forward model. Second, the parameter sensitivities are formulated in terms of one- dimensional integrals of analytic functions along the streamlines. Thus, the computation of sensitivities for all model parameters requires only a single simulation run to construct the velocity field and generate the streamlines. The integration of dynamic data is then performed using a two-step iterative inversion that involves (i) 'lining-up' the break through times at the producing wells and then (ii) matching the production history. Our approach follows from an analogy between streamlines and ray tracing in seismology. The inverse method is analogous to seismic waveform inversion and thus, allows us to utilize efficient methods from geophysical imaging.

The feasibility of our proposed approach for large-scale field applications has been demonstrated by integrating production response directly into three dimensional reservoir models consisting of 31500 grid blocks in less than 3 hours in a Silicon Graphics without any artificial reduction of parameter space, for example, through the use of 'pilot points'. Use of 'pilot points' will allow us to substantially increase the model size without any significant increase in computation time.

P. 189
Successful Application of a Novel Fracturing Fluid in the Wasatch Formation in Eastern
Authors: Dawson Jeff C. , Le Hoang V. , Cramer Dave
Published: December 2007

Hydraulic fracturing of wells drilled in the Wasatch formation is a viable method of enhancing productivity. The Wasatch is a low porosity and low permeability, gas producing formation. It was deposited during the lower Tertiary period in eastern Utah and is composed of a fluvial sandstone and shale. This formation is routinely fractured as a completion method and generally requires crosslinked fracturing fluids that are not excessively viscous but are able to carry moderate to high amounts of proppant. As with most fracturing treatments, fracture clean-up and high conductivity are essential.

A novel fracturing fluid, utilizing ultra low polymer loadings was successfully applied to this formation. This fracturing fluid is based on polymer loadings ranging from 12 to 25 ppt (1.47 to 3.06 kg/m3) with the 25 ppt (3.06 kg/m3) reserved for temperatures ranging from 200 to 250 F (93 to 121 C). Most treatments under 200 F (93 C) utilize 15 ppt (1.83 kg/m3) of polymer. The fluid viscosity is enhanced by crosslinking the polymer with a metal based crosslinker. This fluid is ideally suited for the Wasatch formation because the viscosity development is restricted to about 400 cP at 100 sec. The limited viscosity allows the treatments to generate lengthy, thin fractures rather than short, thick fractures associated with borate based gels. Although the viscosity is relatively low, the proppant suspension characteristics are ideally suited to carry relatively high amounts of proppant. Most treatments have carried six to eight pounds per gallon with the highest loading being twelve pounds.

The fluid also causes minimal impairment to the sand pack. Most fracture conductivity enhancement has been traditionally directed toward improving the breakers. Although the breakers are able to efficiently degrade the polymer's molecular weight thus reducing the fluid viscosity, the fracture still contains an equivalent weight of polymer as the fragments that impair the conductivity and clean-up. The new fluid, having ultra low polymer loadings, together with today's efficient breakers, is able to clean-up better and minimize sand pack impairment caused by the degraded polymer fragments.

Case histories using the fluid, including quality control measures and problems, in the Wasatch formation will be presented.

P. 275
Qualifying Hydraulic Fracturing Effectiveness in Tight, Naturally Fractured Reservoirs by Combining Three-Dimensional Fracturing and Reservoir Simulators
Authors: Johnson Raymond L. , Dunn Kevin P. , Bastian Peter A. , Hopkins Chris W. , Conway Michael W.
Published: December 2007

Hydraulic fracturing in tight, naturally fractured reservoirs is a difficult process and qualifying effectiveness in such an environment is complicated. Through evaluation of naturally fractured shale and naturally fractured sandstone case studies, we will show how hydraulic fracturing effectiveness in naturally fractured reservoirs can be qualified. For this evaluation, we will use lumped and fully three-dimensional (3D) hydraulic fracturing models, analytic bottomhole treating pressure analysis techniques, analytical reservoir models, and finite-difference reservoir simulation. When used together, these techniques can characterize negative effects that can occur to the natural fracture system during the hydraulic fracturing process. These effects relate to the extent of natural fracturing, permeability anisotropy, pressure dependent leakoff, and natural fracture damage.
Formation Fines Stabilization Using Surface Adsorption Polymerization
Authors: Maberry L.J. , Ali Syed A. , McConnell S.B. , Hinkel J.J.
Published: December 2007

Formation fines are ubiquitous in oil- and gas-bearing sandstones. Formation damage resulting from dispersion and migration of fines is a major concern in producing wells. These fines are mineralogically diverse and become a problem when they detach from pore walls, migrate with flowing fluids and choke off pore throats. The formation damage resulting from fines migration causes a reduction in well performance. A treatment that will inhibit the migration of fines will improve long-term well production. This paper presents the results of a laboratory evaluation and field case histories of fines control treatments in sandstone.

P. 461
Case History: Gullfaks C-36AT3, A Multipurpose Oil-Production Gas-Injection Well in the North Sea
Authors: Austigard Arild , Erichsen Leif , Vikra Stale
Published: December 2007

Statoil has recently drilled and completed a multipurpose oil production/gas injection well on the Gullfaks field. The well was drilled from the Gullfaks C platform as well C-36AT3.

The objectives of the well were to produce oil followed by gas injection in three different reservoir segments. Commingled production from the three segments was not feasible. Differences in reserves and production life required sequential production/injection. Accelerating production/injection from one of the segments would increase the wells net present value substantially.

To obtain this, a completion consisting of regular tubing production from the deepest zones, in combination with annulus production from the shallowest zone was selected.

By choosing this completion configuration, the question of an annulus barrier arouse. A new concept for annulus mechanical barrier was developed and installed in the well.

The reservoir section was planned drilled in one section, which meant drilling a 2300 m horizontal section penetrating sands and shales. Maintaining good hole stability as well as keeping the hole clean, thus minimizing the wear on the 13 3/8" casing were of major concern.

The reservoir consisted of unconsolidated rock, and sandcontrol was required. Open hole gravel packs combined with screens in open hole, run as an integrated part of the liner was chosen.

The well is producing independently from both the tubing and the annulus. The well is currently producing at an oil rate of 1385 Sm3/D (8700 bopd) with a water cut of 54%.

P. 505
Using Downhole Annular Pressure Measurements to Anticipate Drilling Problems
Authors: Hutchinson Mark , Rezmer-Cooper Iain
Published: December 2007

Downhole annular pressure is becoming a standard measurement in all drilling environments. When monitored in the context of other drilling parameters, and with a fundamental understanding of hydraulics principles it is possible to identify undesirable drilling conditions, suggest remedial procedures, and help prevent serious problems from developing. For wells with only a small difference between fracture gradient and pore pressure, drilling without realtime downhole annular pressure information may not be possible. Indeed, this is particularly true for extended reach wells, for high temperature / high pressure (HTHP) wells, and in deep water environments where large flowing friction pressure losses or very narrow pressure margins can exist.

Previous publications have discussed how with realtime downhole annular pressure measurements a driller can more effectively maintain the equivalent circulating density (ECD) and equivalent static density (ESD- when not circulating) within a desired range in order to prevent lost circulation and maintain borehole integrity (including managing swab, surge and gel breakdown effects). Annular pressure data are used to evaluate the effects of flow and pipe rotation on the ECD, and to evaluate formation integrity tests. With accurate downhole data the driller can apply conventional drilling practices more effectively to reduce both rig time and potentially also the number of required casing strings.

In order to interpret annular pressure measurements it is important to first understand the physical hydrodynamic principles. It is also important to analyze pressure data in the context of all downhole and surface drilling parameters.

Recent experiences with downhole pressure data have demonstrated how ECD trends can be used to anticipate drilling problems before they develop into serious events. Even with the ECD within its desired range, drilling problems not apparent from conventional procedures can be anticipated.

We present three case histories. The first is from an extended reach drilling project where the annular pressure data gave advanced warning of high cuttings loading, and helped avoid a potential lost circulation or stuck pipe event. This example also illustrates the significant flowing pressure losses that can occur along an extended reach wellbore. A second case history demonstrates the importance of using annular pressure measurements in deep water environments both to establish and maintain safe pressure margins. Downhole pressure data can also be used to evaluate kill procedures. The final example was from an extended reach well where the drilling fluid had sagged during a bit trip, and shows how by evaluating downhole annular pressure measurements, safer and more efficient tripping practices can be developed.

P. 535
Pilot Study Results to Convert Oil Field Produced Water to Drinking Water or Reuse
Authors: Doran Glenn F. , Williams Kimberly L. , Drago Joseph A. , Huang Sunny S. , Leong Lawrence Y.C.
Published: December 2007

The project goal is to convert a currently unusable by-product of oil production, produced water, into a valuable drinking water resource. Results from a 10 gpm pilot study were used for a conceptual design and cost estimate for a 44,000 bpd treatment facility. Generally, the pilot study demonstrated that by altering operating conditions, the treated water could meet industrial, irrigation, and drinking water quality standards. Four scenarios were evaluated, 2 industrial and one each for irrigation and drinking water. The total project cost estimates, with an accuracy of approximately -15 to +30 percent, ranged in capital cost from $3.1 to $12.3 million with an O&M cost ranging from 4.5-23.4 c/bbl of water treated.

P. 403
Yme, A Marginal Field Development in the North Sea
Authors: Apeland Odd J. , Flaate Svein , Skoglunn Tom
Published: December 2007

The small Yme oil field offshore Norway was discovered in 1987, but the Plan for Development and Operation (PDO) was first submitted in 1993 due to the field's marginal character. The recoverable oil reserves as basis for the PDO were only 3,4 mill. Sm3. With the field located far from infrastructure, the development decision required a dedicated effort from the license owners.

Focus was put on increasing and firming up the reserves basis while maintaining acceptable production costs. Accordingly, a jack-up drilling rig was leased and modified for simultaneous drilling and production. An oil tanker was leased for storage and field off-loading. The time from contract awards to first oil from the main structure, Yme Gamma Vest, in February 1996 was only 13 months.

An important part of the development strategy in order to improve profitability was active exploration of mapped prospects in the license area in parallel with field development activities and production. The first subsea satellite development, Yme Beta Ost, was put on production in June 1996. This was only nine months alter submitting the PDO to the authorities and three months after production start for the main field. During the production phase three more exploration wells have been drilled. Overall, these have increased the reserves basis and prolonged the field lifetime.

The Yme reservoirs comprise several challenges such as low reservoir pressure and solution gas content, special fluid properties such as high salinity of the formation water with dissolved solids of 190.000 ppm, and high asphaltene content of the oil. Artificial lift using ESPs and subsea gas lift was installed from the start. A compact water injection unit contributes to improved oil recovery. Barefoot open hole multilateral horizontal completions and hydraulic fracturing of vertical wells have also been used to improve drainage from the reservoir which has large permeability contrasts.

The Yme field development shows how a marginal offshore field development can be initiated and improved using decision making under risk and application of unconventional techniques.

P. 447
Drilling Applications of a New Logging-While-Drilling Slim Sonic Tool: Two Case Studies
Authors: Tepper R. , Boonen P. , Bean C. , Hollon D.
Published: December 2007

A logging-while-drilling (LWD) slim compensated long-spaced sonic tool that can be run in boreholes as small as 5 3/4 in. has been found to have useful drilling applications in the Gulf of Mexico. The 4-3/4-in.-OD tool features a two-transmitter, four-receiver acoustic array. Alternate firings of the two transmitters yield two sets of four waveforms that are processed downhole with a semblance correlation technique to compute compressional and shear slowness ranging from 40 to 180 microseconds/ft. The waveforms are stored in memory for advanced processing at surface. Applications of the sonic information include real-time processing of synthetic seismograms, prediction of pore pressure, computation of acoustic porosity from compressional and shear slowness, and determination of rock mechanical properties for borehole stability analysis. The first of the two studies underscores the accuracy of the LWD slim sonic slowness measurements in predicting pore pressure and detecting the top of supernormal pressure. An LWD slim resistivity tool was run simultaneously with the LWD slim sonic tool, and the resulting resistivity data verified that the slowness measurements indeed served as valid pore-pressure predictors. Operationally, the LWD slim sonic device can be positioned close to the bit, and the measured slowness values can be pulsed uphole in real time during drilling. To enhance drilling efficiency and safety, pore-pressure software at the rig calculates formation pressure and an equivalent mud weight. The second study presents an unusual case in which LWD slim sonic data were used to confirm that a 190-ft section of casing, believed to be cemented in place, slid 90 ft down the wellbore.
Pressure-Transient Analysis for Perforated Wells
Authors: Yildiz Turhan , Ozkan Erdal
Published: December 2007

This study presents a 3D analytical model to analyze the transient flow into perforated vertical wells. The model considers arbitrary phasing angle, non-uniform perforation size and length, and formation damage around perforations. The characteristics of transient pressure and derivative responses of perforated wells are investigated and the flow regimes are documented. Asymptotic approximations for each flow regime are provided. A sensitivity study is carried out to identify the impact of various reservoir and completion parameters on the transient pressure and derivative responses as well as the productivity of the well. It is observed that convergent flow into perforations significantly influences the early-time and intermediate-time pressure responses. A pseudoskin expression to be used to estimate the inflow performance of perforated vertical wells is also presented.
Incorporating Seismic Data of Intermediate Vertical Resolution Into 3D Reservoir Models
Authors: Behrens Ronald A. , Tran Thomas T.
Published: December 2007

Three-dimensional (3D) earth models are best created with a combination of well logs and seismic data. Seismic data have good lateral resolution but poor vertical resolution compared to wells. The seismic resolution depends on seismic acquisition and reservoir parameters, and is incorporated into the 3D earth model with different techniques depending on this resolution relative to that of the 3D model. Good vertical resolution of the seismic data may warrant integrating it as a continuous vertical variable informing local reservoir properties, whereas poor resolution warrants using only a single map representing vertically averaged reservoir properties. The first case best applies to thick reservoirs and/or high-frequency seismic data in soft rock and is usually handled using a cokriging-type approach. The second case represents the low end of the seismic resolution spectrum, where the seismic map can now be treated by methods such as block kriging, simulated annealing, or Bayesian techniques. We introduce a new multiple map Bayesian technique with variable weights for the important middle ground where a single seismic map cannot effectively represent the entire reservoir.

This new technique extends a previous Bayesian technique by incorporating multiple seismic property maps and also allowing vertically varying weighting functions for each map. This vertical weighting flexibility is physically important because the seismic maps represent reflected wave averages from rock property contrasts such as at the top and base of the reservoir. Depending on the seismic acquisition and reservoir properties, the seismic maps are physically represented by simple but non-constant weights in the new 3D earth modeling technique.

Two field examples are shown where two seismic maps are incorporated in each 3D earth model. The benefit of using multiple maps is illustrated with the geostatistical concept of probability of exceedance. Finally a postmortem is presented showing well path trajectories of a successful and unsuccessful horizontal well that are explained by model results based on data existing before the wells were drilled.
Simulation of a CO2 Flood in the Slaughter Field with Geostatistical Reservoir Characterization
Authors: Prieditis J. , Yang A.P.
Published: December 2007

Texaco has been operating a CO2 flood in the Sundown Slaughter Unit in Hockley County, Texas since January of 1994. The CO2 flood was originally justified by analogy with an adjacent CO2 flood. A CO2 flood simulation was later done to predict and optimize the performance of the flood. With actual production data from the CO2 flood available, the simulation forecast was redone and updated. Specific objectives of this new, revised simulation study were to use geostatistical reservoir characterization to improve the representation of reservoir heterogeneity and to use more representative relative permeability curves and residual saturation values.

A team was formed for the new simulation study which included both geologists and engineers with members both from the operating division and Texaco's research organization. Four new geostatistical reservoir models were developed, each with a different level of effective heterogeneity. The basic idea was to adjust the reservoir characterization to improve the CO2 flood match and forecast. All the new models as well as the old model could be used to match the waterflood history equally well with moderate adjustments in the water-oil relative permeability curves. The correct level of reservoir heterogeneity was not needed to do a waterflood match. However, all the models were not equally valid in matching and predicting CO2 flood performance. The predicted CO2 flood performance was substantially different for these models and indicates that a good waterflood history match is not sufficient for a good CO2 flood prediction.

Having actual CO2 flood production response data proved to be the key factor in choosing a model with the correct level of heteogeneity and generating an improved CO2 flood forecast. A successful match of the actual CO2 flood response could not be obtained with the original model but could be with two of the new geostatistical models. The reservoir heterogeneity in a model must be substantially correct for a successful CO2 flood match. The predicted CO2 flood production response was initially fairly close to the actual for these two models, but the match was improved with adjustments of the gas relative permeability curve. In addition, adjusting the gas relative permeability curves to match the initial CO2 flood response brought the ultimate tertiary oil and CO2 production forecasts much closer than they had been initially. Adjusting the gas relative permeability curve for a CO2 flood history match can compensate for moderate, but not large, errors in the reservoir heterogeneity.

This paper describes the methods used for conducting the waterflood and CO2 flood history matches, for making the CO2 flood forecast, and for evaluating the different geostatistic realizations. In addition, the important sensitivities of a tertiary CO2 flood forecast to the reservoir description and the gas relative permeability are discussed and quantified.

P. 487
Enhanced Mechanistic Model and Field Application Design of Gas-Liquid Cylindrical
Authors: Gomez L.E. , Mohan R.S. , Shoham O. , Kouba G.E.
Published: December 2007

An existing mechanistic model for prediction of the hydrodynamic flow behavior in a Gas-Liquid Cylindrical Cyclone (GLCC) separator has been enhanced. The main enhancement incorporated is a flow pattern dependent nozzle analysis for the GLCC inlet for the prediction of the gas and liquid tangential velocities at the GLCC entrance. A state-of- the-art computer simulator, with appropriate graphical user interface, has been developed based on the enhanced model. The code, in an Excel-Visual Basic platform, can be used as a design tool. Four typical field GLCC systems have been designed for actual industrial applications. These include multiphase metering loop with both single-phase and multi phase flow meters, and pre-separation and full separation configurations. The field applications demonstrate the GLCC capabilities and its potential impact in the petroleum industry.

P. 533
Dynamic Simulation and Control System Design for Gas-Liquid Cylindrical Cyclone Separators
Authors: Wang S. , Mohan R.S. , Shoham O. , Kouba G.E.
Published: December 2007

Gas-Liquid Cylindrical Cyclone (GLCC) separator performance can be considerably improved by adopting a suitable control strategy to reduce liquid carry-over into the gas stream or gas carry-under into the liquid stream. A dynamic model for control of GLCC liquid level and pressure using classical control techniques is developed in this paper for the first time. Detailed analysis of the GLCC control system stability and transient response indicates that liquid level control could be achieved effectively by a control valve in the liquid outlet for gas dominated systems or by a control valve in the gas outlet for liquid dominated systems. Based on the proposed linear control system model, the system performance is simulated using a suitable software design tool. The novel control system design approach presented in this paper forms a framework for the GLCC active control system optimization.

P. 545
The Impact of Production Sharing and Other Non-Traditional Agreements on Investment Community Performance Statistics
Authors: Young E.D. , McMichael C.L.
Published: December 2007

Hydrocarbon reserves and the ability to product them profitably are the lifeblood of the upstream petroleum industry. Aggressive competition, ever sharpening scrutiny by the investment community, and volatile product prices drive companies to search for attractive new exploration and producing venture opportunities that will add the greatest value for a given investment. Production sharing and other related non-traditional agreement types have become popular given the flexibility they provide the host country in tailoring fiscal terms to fit their sovereign needs. However, actual agreement terms, including those that relate to royalty payments, cost recovery, profit sharing and taxes, can have a significant impact on the statistics that the investment community utilizes to access and rank the performance of a petroleum company. This paper examines the impact these terms and product price volatility on investment community performance statistics such as reserves replacement, unit exploration, development, and operating costs and earnings. Representative examples are utilized to demonstrate the variation in these performance statistics with variations in product price. Limitations in the various indicators are highlighted as part of the discussion.

P. 575
Application of Downhole Electric Heat Trace System in Arctic Completions
Authors: Fox James B. , Earsley Joseph D.
Published: December 2007

Approximately 30 downhole electrical heat trace systems are currently being utilized for the purpose of; freeze protection, mitigation of hydrate and heavy hydrocarbon accumulation in tubing strings, and viscosity reduction in the completions producing from the Schrader Bluff formation in the Milne Point field. To accomplish the intended objectives the current system utilizes a self-limiting heat trace cable strapped to outside of the tubing to a depth of 2260′. These systems have become an integral part of the completion design for production from these shallow, relatively viscous oil formations under arctic conditions. As the field progresses towards higher hole angles and new types of electric submersible pumping (ESP) systems the utilization of these systems become more critical. Electrical impedance heating systems, recirculation of heated side stream, periodic hot oiling, chemical treating, and mechanical scraping have been utilized as alternatives but the heat trace system has operationally been the most effective method for these purposes.
Downhole Tiltmeter Fracture Mapping: A New Tool for Directly Measuring Hydraulic Fracture Dimensions
Authors: Wright C.A. , Davis E.J. , Weijers L. , Golich G.M. , Ward J.F. , Demetrius S.L. , Minner W.A.
Published: December 2007

A new fracture diagnostic technology for mapping hydraulic fracture dimensions is introduced: downhole tiltmeter fracture mapping. Downhole tilt fracture mapping involves deploying wireline-conveyed tiltmeter arrays in offset wellbores to measure hydraulic fracture growth versus time. This technology has been employed to map over 100 fracture treatments in the last eighteen months. Allowing, for the first time, the gathering of statistically significant data-sets on how hydraulic fractures actually do grow - albeit, within only a few fields so far. In addition to providing fracture diagnostic data (fracture length, height, width and asymmetry), this new capability allows enhanced utilization of hydraulic fracture models because model predictions can be "calibrated" with insitu observations of fracture growth.

The mapping concept is quite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping involves measuring the fracture-induced deformation in a nearby offset well(s) versus time and depth and inverting the data to obtain the created fracture dimensions. The principles are the same as for surface tiltmeter mapping, but the different array geometry make it very sensitive to fracture dimensions and less sensitive to fracture orientation - just the reverse of surface tiltmeter mapping. This paper will explain the fundamental concepts, the implementation strategy (wireline arrays, processing and modeling), present three field case studies, and briefly discuss the implications on fracture modeling.

P. 585
Carthage Cotton Valley Fracture Imaging Project - Imaging Methodology and Implications
Authors: Walker R.N. , Zinno R.J. , Gibson J.B. , Urbancic Ted , Rutledge Jim
Published: December 2007

SPE Paper 38577 introduced the Carthage Cotton Valley Hydraulic Fracture Imaging Project and described the initial imaging work. This paper describes the most recent methodology and implications of imaging hydraulic fractures utilizing microseisms recorded by extensive sensor arrays. Initial imaging work utilized a forward modeling approach. This paper will report further on confirmation of the event locations by inversion methods and by using decimation studies. A source parameter analysis will also be presented. Cotton Valley fracture treatments were performed at depths near 10,000 ft and imaged with arrays cemented in offset wells approximately 1300' away. Several techniques are utilized in both event location analysis and in analyzing certain characteristics of the events. These methodologies provide interpretations of the actual fractures and therefore have implications in the design and modeling of fractures. This paper will also point out and verify the need for development of an economical and commercial service to image fractures in real time. Decimation studies utilizing fewer optimally spaced receptors will determine the ability to develop a commercial service.

Imaging of the hydraulic fractures at the Cotton Valley test site provides conclusions not easily accepted. Issues such as asymmetry, dimensions of the fracture and growth characteristics all prove to be substantially different than expected. Findings such as these will affect modeling techniques, design parameters, and eventually well spacing and development plans. Accurate mapping of a fracture will provide conclusive information that can be utilized to develop optimized and efficient fracture treatments. More effective fracture treatments will result in reduced well costs which allow field extension and expansion opportunities.

Any operator or service company should apply lessons learned and presented in this paper. Imaging of the fracture and analysis of the actual failure mechanisms will provide a basis from which to design and model fractures in the Cotton Valley formation. Ideas for technology and completion strategies could be applicable to tight gas sand completions in other areas. This paper will show technical contributions such as:State of the art technologies utilized for mapping of the fractures.Analysis techniques that will be paramount in the future development of a commercial fracture mapping technology.Event parameter analysis yielding deductions concerning actual failure types in the rock.

These analyses will have a major impact on fracture design and modeling.

P. 599
Correlation Between Oil Composition and Paraffin Inhibitors Activity
Authors: Garcia M.C. , Carbognani L. , Urbina A. , Orea M.
Published: December 2007

Highly paraffinic crudes were characterized by means of physico-chemical analysis (pour point, cloud point and API gravity) and hydrocarbon analysis (wax content, paraffin class-type separation, gel permeation chromatography and high temperature simulated distillation). Although all the studied samples were typical light crudes (32 - 43 API), their high paraffin content was responsible for solidification even above room temperature (33 - 48 C). Several commercial paraffin inhibitors were evaluated with these crudes, being pour point depression the selected activity criteria. Some products evidenced good activity when added to three of the crudes under study, while others induced insignificant changes in the pour point under similar dosages. Correlations between crude oil composition and paraffin inhibitors activity were assessed. The normal / cyclo+iso-paraffins ratio of the crudes that were not affected by the paraffin inhibitors was found higher. The molecular weight distribution (GPC) of the crudes sensitive to additives showed a bimodal character. Additionally, the Concentration of components with more than 24 carbon atoms was found lower than 39 % wt, as determined by simulated distillation. On the other hand, the crudes insensitive to the action of inhibitors displayed monomodal molecular weight distributions with larger contributions of heavy components (more than 52 % wt). Doping experiments carried out with Cl 3-C20 and C20-C44 paraffin extracts and using polarized light microscopy for cloud point determinations, supported the previous findings and permitted to assess the inefficiency of commercial paraffin inhibitors for crudes rich in C24+ alkanes.

P. 681
Development of Gas Tight Seal for Tool Joint
Authors: Bailey Edmond I. , Petrella Jim , Smith Jackie E.
Published: December 2007

A tool joint for 4-1/2 inch drill pipe has been developed that will seal 12,500 psi gas pressure. Pipe with this tool joint can be used for the drilling program and for tasks normally done with a work string. This paper includes the description of the applications for which the tool joint was developed, the development process, the results of the finite element analysis of the tool joint and seal, the performance characteristics of tool joint and the testing that was done.

P. 613
Why Internally Coated Piping Is Used for the World's Largest Seawater Injection System
Authors: Chen E.Y. , Ahmed T.
Published: December 2007

Since Saudi Aramco's seawater injection system was commissioned in 1978, it has undergone a series of expansions and modifications. The system is unique, not only in its size (7 million barrels per day capacity), but also in its complicated piping network. While the original piping system was completely made of bare carbon steel, the new system is made of pipe which is internally coated with fusion bonded epoxy (FBE).

Saudi Aramco's field experience in the past ten years with its seawater injection system has demonstrated the benefits of internally coated pipe. This paper explains why Saudi Aramco decided to use internally coated pipe, which is not a standard practice in the oil industry. Saudi Aramco has two objectives: minimizing water quality deterioration and controlling internal corrosion. First, despite the stringent solids and oxygen removal processes at the intake, water quality always deteriorates as it travels through the pipe. This water, upon arrival at some remote injection wells 250 to 300 kilometers away and 36 hours later, could cause excessive injectivity decline of the wells. Second, internal corrosion generally has not been a problem for uncoated lines, if they are regularly scraped and treated with bactericide for control of microbiologically influenced corrosion. However, uncoated lines which are unscrapable and untreatable require extra corrosion protection.

This paper also discusses the technical challenges concerning coating applications, particularly for coating girth-weld areas in the field. It also discusses scraping requirements for internally coated pipelines, which remains a controversial topic.

P. 721
Case Study of Gas BTU Control For Operational Strategy and Inert Gas Injection Planning
Authors: Lebon M. , Nabil R. , Lehuen P.
Published: December 2007

The aquifer gas storage of Gournay-sur-Aronde (France) has been in operation since 1976. There was a few months of low Btu gas injection, followed by ten years with high Btu gas injection. A gas sweeping was achieved in 1986 to convert the reservoir to a low Btu value gas storage. The cushion gas is therefore a mixture of low and high Btu value gases. The average Btu value during withdrawal periods since 1986 is occasionally very close to the maximum allowed value, potentially raising operational difficulties. For the next ten years, additional wells and surface facilities will be gradually added to increase the working gas and the peak flow rate capacities. This paper describes how a history matching of gas Btu content is performed for the first time using a full field in-house reservoir simulator. In fact, a model was matched the conventional way, then the detailed Btu value history was added. The results of the model in terms of energy and nitrogen content during withdrawal periods have accurately reproduced the actual behavior of the gas storage. This confirms as correct the previous history matching of the reservoir pressure and saturation.

By calculating the evolution of Btu values within the storage, the model proves very efficient in assisting the engineer to define the best strategy for injection and withdrawal periods in order to meet the customers required gas Btu value. Therefore emissibility problems can be avoided by choosing the most suitable wells.

It has been possible to optimize inert gas injection planning by evaluating, under various operational scenarios, the influence of gas mixing on the withdrawn gas Btu values.

P. 563
Analysis of Interference and Pulse Tests in Heterogeneous Naturally Fractured Reservoirs
Authors: Araujo Hugo N. , Andina S.A. , Gilman J.R. , Kazemi H.
Published: December 2007

A geological model of a heterogeneous naturally fractured reservoir was constructed using geostatistical techniques. Single-well, interference and pulse tests were numerically simulated in this reservoir. The purpose was to compare the result obtained from conventional interpretation techniques with the properties of the geologic model in the drainage areas of the wells tested. Relevance of this work is shown by application to an actual field interference test.

The following were concluded in this study:Conventional interpretation of simulated single well tests in heterogeneous naturally fractured reservoirs results in an effective permeability (ke) close to the arithmetic average of the effective permeability distribution in the drainage area of the wells,Conventional pulse and interference test interpretations in naturally fractured reservoirs, in general, yield permeabilities larger than average reservoir permeability in the drainage areas of the wells. These results are consistent with our experience with actual field tests.Single-well test transmissivity (keh/u) can be used in conventional single-porosity pulse and interference interpretation (e.g., PD vs. tD type-curve analysis) to obtain an approximate fracture storativity (ofctfh). Storativity in turn can be used to estimate fracture porosity in the drainage area.

P. 619
Polymeric Damage and a Cost Effective Method for Damage Removal from Wells
Authors: DeVine C. S. , Tjon-Joe-Pin R. M. , Rickards A. R. , Carr M.
Published: December 2007

Polymeric damage is due to inconsistent breaks of stimulation fluids as well as to dynamically formed filter cakes. Fluid viscosity reduction is commonly used to gauge polymer degradation, and, although viscosity reduction indicates polymer degradation, reduced viscosity does not necessarily equate to improved fracture conductivity or retained formation permeability. Polymer fragments which contribute to fluid viscosity are not a measure of residual polymer damage.

Historically, several methods have been employed to remove polymeric damage and increase well productivity. Prior treatments to remove polymeric damage include bleach (sodium hypochlorite) and acids. In cases of horizontal wells with slotted liners or screens, bleach or acids are not preferred. Additional expensive trips have become mandatory, when coiled tubing or drill-pipe are utilized for spotting the treatment. Additionally, some formations are acid sensitive.

Laboratory evaluations of the effects of various gel breakers on linear and crosslinked, guar-based fracturing fluids from room temperature to 210°F, based on the size distribution of generated polymeric fragments, have been previously discussed. Additional studies have demonstrated that a correlation exists between formation rock permeability and the degree of damage resulting from residual polymer fragment deposition - the greater the formation rock permeability, the greater the degree of damage to the formation.

The development of a treatment which could effectively reduce polymeric damage in fracture stimulated wells has been a subject of recent research. Core flow and regained conductivity testing have shown that multi-fold improvements can be achieved, even at elevated temperatures exceeding 250°F, and over a wide pH range.

Results of extensive core flow and fracture conductivity testing, performed in an effort to correlate cleanup effectiveness to original rock permeability using near neutral and high pH cross-linked frac fluids, have been conducted. In general, a greater percentage of regained permeability was noted for more severely damaged (i.e. permeable) rocks. Rocks tested in this study exhibited permeabilities from 3 md to 2 darcies. Conductivity proppant pack baseline ranges were 250 to 500 darcies. Detailed analyses of the data are provided. Several field case histories of wells which were suffering from polymeric damage are presented.
Monitoring Casing Offset Damage Using Ultrasonic Measurements
Authors: Morris C. W. , Gwinn R. L. , Rambow F. H. K. , Mitzel D. P.
Published: December 2007

Many reservoirs are located in tectonically active areas, experience formation subsidence, or have salt formations which can result in the wellbore casing being mechanically damaged by the relative movement of a formation layer interface. The casing is forcibly ‘offset’ in the horizontal direction through a short vertical depth interval of less than 10 feet. The offset increases with time until there is complete collapse and/or shearing of the casing. Many casing inspection tools can measure the inside radius of a casing joint with various degrees of accuracy and resolution, and some tools can measure the casing thickness. However, casing offset monitoring requires an accurate determination of the casing distortion in the vertical dimension also. Measuring this offset is difficult unless the entire tool position within the wellbore can be defined.

Because of the unique measurement capabilities of the ultrasonic cement evaluation tool, it is now possible to monitor casing offset conditions accurately and to use these results to predict casing failure. The ultrasonic tool can measure the casing offset across a short interval, the inside radius, the thickness, and the external cement conditions in one operation. Thus, all of the information needed to evaluate the potential mechanical failure of a casing joint is known as the situation develops at the formation layer interface.

Ultrasonic imaging data from over ten wells were evaluated using this new monitoring technique. Multiple logging trips over a period of nearly one year showed the progressive casing damage in these wells. The monitoring technique and resulting measurements will be illustrated. Also, the casing was pulled from one well for surface inspection and the actual casing dimension data from the damaged interval was compared with the log results. This well validated the use of the technique for casing monitoring throughout the area. The new casing inspection technique provides for better well and reservoir management information in a difficult production environment.
Planning for Successful Window Milling Operation
Authors: Dewey Charles H. , Childers Ronald D.
Published: December 2007

Historically, the applications of window milling tools and methods were limited to remedial operations. The main bore would be sidetracked only in the event of irretrievable fish, collapsed casing, depleted reservoir, etc. In recent years however, the re-entry drilling has become an increasingly popular option for production optimization as a result of advanced developments in the milling, drilling and measurement tools and technology.

One of the important aspects of re-entry drilling is to mill a window in the existing casing and sidetrack the well bore. Past experience shows that inadequate planning for a window milling project has resulted in either an aborted attempt or premature failure in the hole.

In order to achieve a successful window milling operation, the following ten (10) points must be addressed and situations resolved prior to commencing with the casing exit operation; (1) Selection of best place to set and to orient the whip-stock, (2) Hole angle, (3) Radius of curvature (build, drop, left or right tum) in the vicinity of casing exit, (4) Whip face orientation methods (MWD, gyros), (5) Flexure characteristics of the bottom hole assembly and resulting dogleg severity, (6) Length of sidetracking assembly, (7) Depth of rat hole to facilitate drilling objective (short, medium or long radius) after milling window, (8) Casing conditions, (9) Formation types, and (10) Retrievability of whip-stock assembly.

This paper will discuss the above points in detail using data from actual field runs. The field runs will be selected from a large database of window milling jobs maintained over the last 10 years. Additionally, the paper will present recommendations and guidelines for planning a successful window-milling project.
On The Choice of Current Profiles for Deep-Water Riser Design
Authors: Adams A.J. , Thorogood J.L.
Published: December 2007

The paper describes the present state-of-the-art in fatigue analysis for vortex-induced vibration (VIV) of ultra-deep water unfaired drilling risers (1000 m water depth and above) in steady currents. It complements an earlier work on the broader issues of deep-water riser design and management.

To date, strength and VIV fatigue life analyses have always been based on the enveloping current profile, i.e., the locus of predicted extreme speeds for the various current meter depths. For most offshore structures, this is a conservative approach, and it was believed that this was also true of deepwater risers. However, recent work for BP Norway has shown that this is not the case, and that analysis for the mean concurrent profile (i.e., the current at any given instant in time) gives predicted fatigue lives an order of magnitude lower. It is thought that this was not previously known to the industry.

Techniques are presented for the selection of concurrent design profiles, and the analysis methods and assumptions for VIV response prediction and fatigue damage calculation are described. Fatigue life results are presented for five deep-water wells, all in the Atlantic Margin area (West of Shetland, the Rockall Trough and the Voring Plateau). Riser safety management via monitoring of predicted damage is discussed, and cumulative damage results are given for a recent well.

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