bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Study: Evaluation and Remediation of High-GOR Horizontal Wells
Authors: Frankenburg Amy , Hupp Douglas
Published: December 2007

This paper describes the integration of openhole well logs and memory production logging data to aid the evaluation and remediation of a horizontal well by understanding reservoir fluid contact.

This paper includes a case study of the techniques used to acquire and interpret three-phase flow in a North Slope horizontal well, procedures used to remediate the well, and their results. The example well was shut in as a result of the high gas production rate and uncompetitive gas/oil ratio (GOR) shortly after completion. The production logging data acquired with memory was utilized in combination with openhole log data to refine the reservoir fluid contact estimates. A refinement of the near-wellbore fluid picture (gas/oil/water) reduced the risk involved with the various remediation options enough to proceed. The remediation action chosen was a program to add perforations. This program was economically successful and resulted in the well being placed back on production as a competitive full-time producer with substantially reduced GOR and increased oil rates.

To fully evaluate the downhole flow contribution of the various zones within the reservoir, it was necessary to evaluate the three-phase flow in this horizontal well. Traditionally, this had been accomplished with coiled electric line. In the wells described in this case study, memory production sensors recorded both gas holdup (through optical probes) and distributed water holdup. These measurements allowed accurate identification of entry points of all three phases.

The techniques described in this paper have wide application for remediation of horizontal wells in mature fields.
Case History of Using an Integrated Asset Model for Depletion Planning of a Tight Gas Reservoir, Northeast Thompsonville Field, Jim Hogg and Webb Counties, Texas
Authors: Schott David W. , Abacioglu Yafes , Moran Mark J. , Stein Michael H. , Scattergood Joseph
Published: December 2007

This paper describes the results of a gas field development study that involved the integration of various technologies to determine how to lower field abandonment pressure, increase rate and reserves, improve profitability, and how to better manage the natural decline of the gas field. Subsurface and surface technologies were integrated. Part of the integration involved employing an integrated asset model. The integrated asset model (IAM) tool included a surface pipeline network simulator, coupled to wellbore models, reservoir inflow models, and material balance models for the entire field. This application addresses modeling of tight gas reservoirs with nodal analysis models in a manner that incorporates the transient aspects in the nodal analysis. The reservoir in this study had a high temperature, and thus water vapor was accounted for in the pressure drop calculations of both the wellbores and the surface pipelines. The modeling of compressors in the surface pipeline network model is also addressed. Modeling compressors with low suction pressure was found to be extremely challenging. Limitations and areas for improvement are discussed.

Facility modifications to increase gas production, profitability, and gas reserves were identified. Better management of individual wells routed to particular compressors is expected to increase gas recovery by lowering overall field abandonment pressure.
Integrated Seismic-Guided Characterization of a Carbonate Reservoir in Abu Dhabi, U.A.E.
Authors: Abbaszadeh Maghsood , Takahashi Isao , Suzuki Koichi
Published: December 2007

This paper presents a novel methodology for seismic-guided integrated reservoir characterization of a thinly bedded stratified heterogeneous carbonate reservoir, located offshore Abu Dhabi, U.A.E. The data sources include high-resolution log- and core-scale porosity, well test-calibrated layer permeability, and seismic attributes of AI (acoustic impedance) and Vp/Vs (ratio of P-wave to S-wave velocity), extracted from high-resolution 3D seismic data. A robust multivariate Gaussian approach is used to integrate these data types for improved 3D distributions of porosity, permeability, enhanced permeability and reduced uncertainty. It is shown that permeability can be tied to seismic Vp/Vs, based on a sound rock physics investigation.

Geostatistical conditional sequential simulations collocated with the seismic attributes and combined with a deterministic geological trend model are utilized to generate multiple realizations of porosity and permeability at both zone-scale and thinly bedded layer-scale. Porosity is modeled in 3D conditioned to seismic data, while permeability is modeled on layer-by-layer basis as a series of 2D stochastic distributions conditioned to seismic and collocated with porosity distributions. Permeability enhancement distributions are constructed from incremental ?kh over core-derived flow capacity (kh) at wells integrated with seismic attributes.

Comprehensive cross validation analyses at both reservoir zone-scale and layer-scale are performed with and without seismic to assess uncertainty in reservoir characterizations, and evaluate the value of seismic in improving reservoirs descriptions. The results indicate that overall uncertainty in porosity and permeability are reduced by 50% and 30%, respectively, when seismic information is integrated.
Design and Execution of a Successful Well Kill on the World's Longest-Running Blow-out
Authors: Bellis Chris J. , Bothwell Paul D. , Burke Lyle H. , Grace Robert D. , MacDonald Ron R. , McLellan Pat J.
Published: December 2007

This paper reviews the history of the world's largest running blowout as well as the integrated engineering based approach taken to define the blow-out mechanism and to ultimately kill and abandon the wells.

During 1916 cable tool drilling operations, Peace River Oils No.1 encountered an uncontrolled flow of salt water and gas at 345 m depth. The flow was estimated at over 30,000 bbls/d, ultimately the rig collapsed into the sinkhole and temporarily killed the surface flow. The rig was rebuilt in 1917, recovered the production casing, but again a blow-out could not be controlled and the well was left to flow 30,000 bbls/day of salt water into the Peace River. At the time of the project initiation, there was one relief well (1955), one attempted relief well (1982) and a lost well (1916).

The defacto well operator, the Alberta Energy and Utilities Board contracted an integrated team of professionals including well control engineers; geologists, drilling and completion engineers, geomechanics specialists and well operations specialists to evaluate the potential of effecting a permanent kill solution. This led to a primary recommendation to re-enter the 1916 wellbore via a flowing well operation to reach total depth and conduct a well kill.

The kill operation was complicated by having no production casing within the 1916 wellbore, shallow underground flows with multiple break-outs around the three wells, collapsed and parted casing in the 1955 well and entrained sour gas. The uncertainty of achieving access to the various wells to total depth and preparing for a wide range of potential well kill volumes and rates, were primary concern, as were the environmental constraints of operating on the unstable banks of the nearby Peace River.
Coiled-Tubing Deployment of Hydrajet-Fracturing Technique Enhances Safety and Flexibility, Reduces Job Time
Authors: McDaniel B. W. , Willett Ron , East Loyd , Rosato Jeff , Surjaatmadja Jim
Published: December 2007

Hydrajet fracturing, a relatively new stimulation technology for horizontal completions, has already proven successful in oil and gas wells across three continents. This multistage fracture stimulation method has primarily used jointed pipe to achieve hydraulic fracturing injection rates. The recent introduction of large OD coiled-tubing (CT) to the process has improved operating flexibility, reduced job time, and significantly enhanced health, safety, and environmental (HSE) performance. For some operations, it can also provide cost savings.

Before 2003, most CT-conveyed applications of this process typically were limited to hydrajet-assisted acid-squeeze injections, with only a few low-rate acid-frac treatments performed. By using larger-OD coiled tubing, operators have placed propped fracture treatments to approximately 8,000 ft measured depth (MD) at treating rates up to 10 bbl/min.

The use of a combined workstring consisting of jointed pipe connected to a surface string of CT can enable these multi-stage treatments to be placed in much deeper reservoirs, effectively doubling or tripling the depth capability of a CT-deployed treatment. For many applications this capability would provide the flexibility, speed, and safety inherent to coiled-tubing operations with a spool of only a few thousand feet, and jointed pipe would not be exposed to high treating pressures at the surface.

This paper reviews several field applications where coiled tubing was used to deploy hydraulic jet fracture treatments. One field case is compared directly to an earlier treatment in the same reservoir, which had been pumped through jointed pipe.
Saturation and Viscosity from Multidimensional Nuclear Magnetic Resonance Logging
Authors: Heaton N. J. , Minh C. Cao , Kovats J. , Guru U.
Published: December 2007

The last decade of nuclear magnetic resonance (NMR) logging has been dominated by T2 measurements and sparse sampling of polarization (differential spectrum) or diffusion (shifted spectrum) effects. Recent literature has expanded on the utility of NMR logging using T1 measurements to provide information on long time constants that are difficult or impossible to derive from T2 measurements using gradient tools. NMR logging modes have typically been designed to focus on a single specific NMR response, either very fast or very slow diffusion, or long T1 times, to identify either oil or gas. However, fluid properties can vary widely and often unpredictably downhole. A small number of NMR measurements that focus on just one NMR parameter may not provide sufficient information to identify and quantify fluid volumes, particularly when several different fluids are present. Achieving accurate fluid properties often requires data acquisition that simultaneously measures T1, T2, and diffusion contrasts. Inversion is most effective when all three NMR properties, T1, T2 and D, are obtained. We review the relative merits of T1, T2, and diffusion-based measurements in the light of petrophysics and instrumentation limitations. The relative merits of forward-model inversion and model-free analysis are discussed with reference to data sets recorded in a broad range of environments.
Utilizing Statistical Process Control Tools to Test Free Cycle Plunger's Potential on Tight Gas Wells
Authors: McWilliams Jay Paul
Published: December 2007

The free cycle plunger is a relatively new means of removing wellbore fluids. As gas reservoir pressures are depleted and production rates decline, liquid loading becomes a greater problem. When flow rates fall below minimum lift, liquid accumulates in the wellbore, causing additional backpressure on the formation, which reduces production rates.

A free cycle plunger is designed to increase daily plunger cycles as compared to a conventional plunger lift system. This increase reduces the slug size, requiring less energy to lift the plunger to the surface. The plunger design allows it to fall while the well is flowing, permitting more daily flow time and increased natural gas production. Recently, several types of one-piece and two-piece free cycle plungers have been introduced to the market.

This paper discusses the results of a 45-well pilot of the free cycle plunger in the San Juan Basin. The pilot's objective was two-fold: to test the hypothesis that installing the free cycle plunger would reduce slug sizes, increase daily flowing time, and increase overall production and to establish better criteria for future installations. To accomplish the second objective, it was necessary to analyze the positive and negative responses to the free cycle plunger and determine the factors that led to each response. The data was then analyzed [CP1]using statistical modeling tools to determine the most important factors affecting the response variable increased production (uplift). This paper will discuss the results of a regression model and response surface methodology (RSM) analysis. The regression model was built to determine the significance of several factors and to predict the production response from installing the system. The response surface methodology analysis was used to determine the best candidates for the installation of the system.

The concepts of Statistical Process Control (SPC), the application of statistical techniques to control a process1, were used to implement and evaluate the pilot. To most efficiently and accurately test new artificial lift technologies, it is essential to implement a controlled test of the technology and to use proper statistical methods to evaluate the results.
Optimization of Horizontal Well Completion Design
Authors: Furui K. , Zhu D. , Hill A. D. , Davis E. R. , Buck B. R.
Published: December 2007

A well completion is a critical interface between the productive formation and the wellbore. An effective completion must maintain mechanical integrity of the borehole without creating any significant restrictions in the flow capacity of the well. In this paper, we outline a process to design optimal completions for horizontal wells by applying comprehensive skin factor models that include damage and turbulence effects for all common types of completions.

Slotted or perforated liner, cased and perforated completions, or gravel pack completions have been used in horizontal wells for borehole stability and sand control purposes. However, these completions may have lower productivity (as characterized by a positive skin) relative to an equivalent openhole completion because the convergent flow to perforations or slots increases fluid velocity in the near-well vicinity. In addition, any reduced permeability zones (formation damage caused by drilling, completion, or other processes) magnify the convergent flow effects, and hence, may result in severe skin factors. Compound effects of formation damage around the well completion, a crushed zone due to perforating, the plugging of slots, and turbulent flow, as well as interactions among these effects are included in the model.

We first illustrate how to use the skin factor models to screen the available completion types for different applications. This screening approach considers reservoir permeability, permeability anisotropy, fluid properties, formation damage effects, and rock mechanical characteristics as the key parameters. The types of completions that yield the most productive well performance for this matrix of properties are presented.

A more detailed completion design is then illustrated by showing the use of the skin factor models for selection of liner completions for viscous oil reservoirs on the North Slope of Alaska. Application of the slotted or perforated liner models to the readily available liners showed that the completion skin factor can vary by as much as 40%, depending on the detailed characteristics of the slots or perforations in the liner (slot or perforation size, density, and distribution). This showed how analyzing the performance of the completion design can greatly increase well productivity at little or no cost.
Productivity of Selectively Perforated Horizontal Wells
Authors: Yildiz Turhan
Published: December 2007

This paper investigates the effect of selective perforating on horizontal well performance. Theoretical investigation is based on a general 3D analytical IPR model that was published previously. For a given perforation design, the changes in flow rate, pseudo-steady state productivity, and cumulative production can be computed using the solution. The investigation shows that the ratio of total perforated length to the drilled well length is the most dominant parameter controlling the long term performance of the selectively perforated horizontal wells. The other important parameters are the degree of formation and perforating damage.

We additionally examined the effect of the so-called oriented perforating on the horizontal well performance in isotropic and anisotropic formations. Our research shows that accurately oriented perforating could significantly improve the well productivity in anisotropic formations.
Experimental Investigation of Various Methods of Tertiary Gas Injection
Authors: Kulkarni M. M. , Rao D. N.
Published: December 2007

Water alternating gas (WAG) injection is widely practiced for improved light oil recoveries. In this experimental study, we compare the WAG process against the continuous gas injection (CGI) process by conducting tertiary mode miscible and immiscible corefloods.

Inferences resulting from performance evaluations using ‘conventional’ tertiary recovery plots were found inappropriate. Therefore, a new parameter ‘Tertiary Recovery Factor’ (the oil recovery per unit volume of gas injected) was defined, and used in conjunction with the CO2 utilization factor, for the evaluation of tertiary coreflood recoveries. The definition of TRF not only helped to demonstrate experimentally that miscibility development has a positive effect on oil recovery, but also showed that the WAG mode of injection is better than Continuous Gas Injection (CGI) when overall performances are considered. The WAG floods demonstrated continual increase in the TRF throughout the life of the flood, however, for CGI miscible flood, TRF crested at about 0.6 PV injection and later declined with increasing gas injection. These plots demonstrate that the WAG process has better CO2 utilization efficiency compared to CGI. These results indicate that optimum performance could be obtained by a combination of CGI and WAG modes of gas injection. This paper provides conceptual analysis and experimental demonstration of WAG, CGI and their combination at reservoir conditions.
Reservoir Description and Numerical Simulation of Neocomian Gas-Condensate and Oil Reservoirs, Western Siberian Basin, Russia
Authors: Jenkins C. D. , Richmond P. L. , Wolcott D. S.
Published: December 2007

Integrated studies were recently completed for two gas-condensate fields with associated oil rims in the Western Siberian Basin of Russia. The two fields contain almost 500 billion cubic meters of gas and 700 million cubic meters of oil in large, low relief structures. The studies used seismic, core, log, fluid property and well test data from 118 wells to conduct petrophysical analyses, build geocellular models and conduct reservoir simulation. The reservoir description work identified controls on fluid flow, captured these in the geocellular models, and estimated hydrocarbons-in-place. After upscaling, full-field and mechanistic compositional models were constructed to investigate depletion strategies including volumetric depletion and improved recovery via lean gas injection. The results showed that high-graded well locations, zone commingling, hydraulic fracture treatments, horizontal drilling, and compression installation will be required to optimize development.
Flow Properties of Alaskan Heavy-Oil Emulsions
Authors: Singh Probjot , Thomason William H. , Gharfeh Samir , Nathanson Louis D. , Blumer David J.
Published: December 2007

Technical investigation to economically produce heavy oil in Alaska began in the 1980's. Since then a significant progress has been made in the production technology (multilateral drilling, artificial lift such as Electrical Submersible Pumps (ESP) and hydrolift Jet Pumps, etc.) to facilitate the production of the heavy oil. Still, a major challenge in the heavy oil production in the Alaskan arctic region is the formation of strong emulsions. The viscosity of these stable emulsions can be 2-3 orders of magnitude higher than the dry oil viscosity at the low ambient temperatures. The viscosities of these emulsions in the surface facilities are needed to predict the hydraulics in the fluid handling systems. Oil wet solid fines tend to further stabilize the emulsion and lower the separation efficiency. The stability of the emulsion can be gauged from the fact that oil external emulsion exists even up to 90% brine fraction and has the consistency of the peanut butter (highly viscous >2x104 cP at room temperature). Laboratory titration experiments with alkanes indicate that the asphaltenes are stable in the crude oil. A Haake RS150 rheometer and a Brookfield DV-III viscometer were used to measure the viscosity of the live and dead emulsions containing various brine fractions at different temperature. The viscosity estimation by matching the pressure drop data from the field pipeline correlated well with the laboratory results. The viscosity of the emulsion decreases with temperature as predicted by the Arrhenius law. Heating the emulsion above 60°C causes partial destabilization of the emulsion resulting in slight deviation from the Arrhenius predictions. Emulsion breakers were found to be effective in reducing the viscosity of the emulsion even though they did not cause any physical separation of the brine. Based on these results, viscosity correlations have been developed to predict the viscosity of both live and dead oil-brine emulsions as a function of brine fraction, temperature, and shear rate. Viscosity correlations for emulsions presented by Barnea and Mizrahi showed excellent fit to the measured data. It was proposed to incorporate these correlations in the Pipesim, steady-state multiphase flow simulator for oil and gas production.
Material Balance Reservoir Model for CO2 Sequestration in Depleted Gas Reservoirs
Authors: Lawal Akanni S. , Frailey Scott M.
Published: December 2007

A depleted gas and gas condensate reservoir can store significantly more gas than a depleted oil reservoir with identical HCPV due to the fact that gas is more compressible than oil and the ultimate gas recovery in reservoir is typically higher than that of oil reservoirs. Also geologic CO2 storage in retrograde gas reservoirs can re-vaporize condensates and thus re-pressurized the reservoir which consequently leads to greater liquid condensate recovery.

A material balance equation for CO2 sequestration in gas reservoirs was developed to predict CO2 sequestration volume and survey CO2 sequestration operations during injection. Implications of dry, wet, and retrograde gas reservoirs on the P/Z plot usage are presented.
Practical Considerations for Pressure-Rate Deconvolution of Well Test Data
Authors: Levitan Michael M. , Crawford Gary E. , Hardwick Andrew
Published: December 2007

Pressure-rate deconvolution provides equivalent representation of variable-rate well test data in the form of characteristic constant rate drawdown system response. Deconvolution allows one to develop additional insights into pressure transient behavior and extract more information from well test data than is possible by using conventional analysis methods. In some cases it is possible to interpret the same test data in terms of larger radius of investigation.

There are a number of specific issues one has to be aware when using pressure-rate deconvolution. In this paper, we identify and discuss these issues, and provide practical considerations and recommendations on how to produce correct deconvolution results. We also demonstrate reliable use of deconvolution on a number of real test examples.
Managing the Tradeoffs: Similarities Between Managing New Product Development and Managing a Well Drilling/Completion Project
Authors: Shaw B. S. , Morris T. G.
Published: December 2007

To move and take action as quickly as possible, a development team must have a clear path and direction. It needs the best tools for the job and the ability to use them effectively. And it needs positive motivation to finish the work on schedule while achieving acceptable performance and quality goals. One of the potential "chokes" to the speedy delivery of both new products and new oil/gas wells is the decision-making process – the on-going debate between various interested and influential parties within the organization as to which aspects of the end product are most important. Multiple or conflicting priorities are often overlooked by planning teams when developing project schedules, budgets, performance objectives, and milestones. This frequently causes frustration, delays, and disappointments during and after the execution of the project.

The authors draw on their own experience in new product development (downhole tools) and subsea well delivery. The roles and responsibilities of a cross-functional new product development team are similar to those of an operator's on-shore support and offshore operations teams. For both types of development project, risk mitigation and project execution are best achieved by utilizing the skills and experience of a highly competent multi-disciplinary team using a well-planned and documented decision-making process. These teams benefit by inclusion of key supplier technical experts as full- or part-time contributing members. The ability of the project execution team to consistently make value-added decisions rapidly, under pressure, is a key element of their success. Specific examples from a supplier's new product development process and from a recent major deepwater development project are used to illustrate the key concepts.
Compact In-line Separation Project
Authors: Okimoto Fred T. , Klaver Theo , Verschoof Karel , Stanbridge David
Published: December 2007

Shell Global Solutions International (SGSI), CDS Engineering and Petroleum Development Oman LLC (PDO) are jointly field testing a new gas/oil/water in-line separation system (ILS) as part of the Smart Facilities Solutions portfolio of technologies. PDO has a requirement to have water injection facilities at the Al Huwaisah South West production site for reservoir support. Since start of production in 1971, the water cut has gradually increased to 85 – 90 % and is expected to increase further. This paper will describe the joint effort of Smart Facilities Solutions and CDS in applying new in-line separator equipment: a degasser, dewaterer, and hydrocyclone.

The Al Huwaisah field has been producing since 1971 with current gross production about 45,000 m3/d (see Figure 1). To improve oil recovery water injection (as well as infill drilling and exploitation of undeveloped areas) new facilities are planned. The project is to develop the South West Area by installing a facility to treat the SW production fluid to provide injection quality water for the water injection wells in the SW area. Presently, the SW area has only wells with a Multi-port Selector Valve (MSV) feeding a 12 inch GRE line to Al Huwaisah gathering station. Over the years the water cut has gradually increased to 85+% and is expected to increase further. The facilities will separate water, oil and gas. The compact inline separation system is designed to separate water, oil and gas. The ILS system is described in the next section. Water is locally injected. Gas and oil and any excess water is combined and sent to the central gathering station through an existing 12 inch GRE pipeline with gas and crude exported to Yibal. The compact inline separation system is a joint effort of SGSI and CDS.

The ILS was seen as an important technology, so SGSI went out into the market for competitive tendering based on the specific criterias of the ILS. CDS Engineering was selected as most suitable for the requirements needed for Al Huwaisah SW project.
Maximizing Fracture Conductivity with Proppant Partial Monolayers: Theoretical Curiosity or Highly Productive Reality?
Authors: Brannon Harold D. , Malone Mark R. , Rickards Allan R. , Wood William D. , Edgeman J. Randall , Bryant Josh L.
Published: December 2007

Hydraulic fracturing practitioners have long theorized that maximized fracture conductivity could be achieved by creation of fractures with partial monolayers of proppant. Fracturing mechanics and design experts have lamented that fractures filled with partial monolayers of proppant, while highly desirable, were "virtually impossible to achieve". The expert's reasoning was expressed as due to the inability to obtain uniform and complete coverage of the fracture with a partial monolayer, insufficient proppant strength to support the load, loss of fracture width due to proppant embedment and, potentially deleterious non-Darcy flow effects in the relatively narrow propped fracture. Many innovative fracturing products and design techniques have recently been developed and introduced to cost efficiently enhance well productivity. Evaluation of case histories of several wells recently treated utilizing some of these innovations have led to the consideration that perhaps the experts were a bit too hasty.

Slickwater fracturing has enjoyed a recent renaissance, in large part, due to the favorable treatment cost economics for the well stimulation benefit achieved using such non-damaging, low viscosity fluids. Slickwater fracturing treatments have historically been typified by pumping large volumes of slickened water at high rate to deploy relatively small volumes of frac sand. A potential shortcoming of slickwater fracturing treatments is the tendency for fracture propagation out of zone due to the high treating rates and, proppant settling below the target zone due to the poor transport properties afforded by the low viscosity treating fluid. Optimization of slickwater fracturing treatments employing recently developed ultra-lightweight proppants to facilitate proppant placement throughout the entire created fracture area has found success. Wells treated with the new proppants using refined placement techniques have been observed to experience extraordinary stimulation increases which are indicative of production through a partial monolayer proppant pack. The observed increases are resulting in payouts in a few weeks or months compared to the years experienced historically with previous methods.

The focus of this effort will be a review of case histories of wells treated with new products and placement techniques. Discussion of slickwater treatment design optimization and laboratory evaluation of the ultra-lightweight proppant partial monolayer conductivity and transportability is also provided. Results demonstrate how merging new technologies with old techniques can produce modern, high value results.
A Case History Of Optimizing Casing-Conveyed Perforating and Completion Systems in Tight Gas Reservoirs, Kenai Gas Field, Alaska
Authors: Garner J. Jay , Thompson Jim , Mack David J. , Devine Carolyn
Published: December 2007

Nine (9) wells have been successfully drilled, cemented and fracture stimulated in the tight gas sands of four (4) separate fields on the Kenai Peninsula, Alaska utilizing an industry unique Casing-Conveyed Perforating System (CCPS). For this nine (9) well program, 124 CCPS modules have been run, cemented in place, detonated and fracture stimulated. Of the nine (9) wells the initial five (5) wells were stimulated with an oil-based fluid while the most recent four (4) have utilized a water-based system. While the project has been an overall success, the drilling and completion team continues to utilize new and innovative technologies to optimize well performance and economics.

The normally-pressured middle and lower Beluga sands in the Kenai Gas (KG) and Beaver Creek (BC) areas exhibit significant vertical sections frequently exceeding 1,700 ft. The vertical pay quality is quite variable and consists of stacked fluvial sandstones 5 ft to 30 ft thick. The mineralogical composition of the sands is complex including a high percentage of quartz, clays, volcanics, coals, and fines with permeability ranging from 0.01 to 3 millidarcies. The sandstone packages are bounded by discontinuous shale, siltstone, and coal beds and present a challenging fracture stimulation environment. Produced gas is lean with a specific gravity of 0.56 with no condensate.

As mentioned above one of the most robust changes to the project has been a shift from a crosslinked oil-based (diesel) fracturing fluid to a "new-generation" aqueous based guar-borate system. This step change was made at the conclusion of extensive laboratory studies on core sections and has provided significant improvement with HSE, completion operations, well performance and ROI.

This case history paper reviews the revolutionary casing-conveyed perforating system, provides an overview of the nine (9) wells completed to date and describes the laboratory test procedures and results used to validate the use of a water-based fracturing fluid. Project cost savings are also discussed pertaining to the Total Cost of Service (TCS) differences between hydrocarbon and water-based fracturing fluids in a cold weather environment.
Drilling Optimization Using Bit Selection Expert System and ROP Prediction Algorithm Improves Drilling Performance and Enhances Operational Decision Making by Reducing Performance Uncertainties
Authors: Bjornsson E. , Hucik B. , Szutiak G. , Brown L. A. , Evans H. , Curry D. , Perry P.
Published: December 2007

A rule based drill bit selection expert software system and Rate of Penetration (ROP) prediction algorithm has been recently applied in the optimization process of a 4500 m vertical foothills well in Western Canada. Post well analysis shows that when the expert system recommendations were followed by the operator, increases in ROP and run length over the local pacesetter well were experienced in each hole section. ROP increases of 15% in the 311.1mm section, 52% in the 215.9mm section and 60% in the 142.9mm section were achieved, as well as bit life increases up to 33% with TCI bits. Although the operator did not follow all of the expert system recommendations through the entire well, these increases did contribute to savings in drilling time below AFE of 15 days over the entire well. Comparison with the actual drilling performance showed close agreement in trend to the predicted ROP through most lithological intervals, which helped to confirm the accuracy of the process of geological / pore pressure predictions and the ROP prediction algorithm.

The expert system is a rule based bit selection system that uses a detailed description of the drilling environment, including meter based lithology, synthetic wireline logs, predicted pore pressures and anticipated operating parameters of the well or hole interval being analyzed to produce a bit selection recommendation including IADC bit type and bit features. The ROP algorithm has been developed as a drilling optimization tool and attempts to model the technical limit ROP that can be expected through a given hole interval. The ROP algorithm uses as its inputs detailed lithological descriptions of the anticipated formations, hole size, mud weight, predicted pore pressure, bit type, and anticipated operating parameters to calculate an accurate meter based ROP prediction. The ROP algorithm has been applied in several drilling environments worldwide and comparisons with actual drilling performance have been used to modify the calculations and improve predictions.

The ROP algorithm improves drilling decisions, and provides performance analysis while guiding financial planning. The ROP algorithm can be applied in the planning phase of a project to develop time curves based on expected performance and to compare and contrast potential bit/BHA types based on performance predictions. Furthermore, the ROP algorithm can be used in post-well analysis to identify areas where potential drilling performance was not achieved, and help in identifying improvements for future projects.
Reducing Well Cost by Gravel Packing in Nonaqueous Fluid
Authors: Hecker Michael T. , Barry Michael D. , Martin Thomas B.
Published: December 2007

As operators continue to develop prospects in expensive, deep water environments, delivery of high rate, high capacity, long life wells become essential for economic success. Often, operators are drilling high angle, open hole wells to maximize production by capturing reserves from several sand packages in one wellbore. In many of today's deepwater applications, hole stability and shale inhibition are keys to a successful open hole completion. Nonaqueous fluid (NAF) is the preferred fluid system to optimize drilling of the open hole section, but hole stability can be problematic during displacement operations prior to gravel packing. This paper describes a gravel packing technique that allows the operator to run the gravel pack screens in NAF, gravel pack the well and displace the casing to brine, all in one trip. Running the screens in NAF significantly increases the probability of successful screen installation and the end result is consistent, cost effective delivery of high rate, low skin completions.
Monobore Completion Using Interventionless Technology in Offshore Horizontal Gas-Injection Wells
Authors: Etuhoko Michael O. , Lewis Proctor
Published: December 2007

The Amenam/Kpono field is located eastern offshore of Nigeria in a water depth of 43m and about 35km away from the coast. The field development has been challenging in so many ways: Deep reservoir targets (3600m to 4300m TVD/SL)High temperatures (130 -150 degree Celsius)High pressures (370 to 500 bar)High- reach departures up to 3km in certain wellbores, giving rise to highly deviated and deep wells (up to 6600m MD/RT)Reservoir fluid containing 3% by weight paraffinReservoir fluid containing 3% carbon dioxide contentCritical reservoir fluids (bubble point pressure is very close to the reservoir pressure in the main reservoir). This necessitates the requirement for the early and efficient pressure support for the reservoir

In order to deliver wells under the above challenging environment and circumstances such as to ensure field life production, a lot of emphasis is placed on completions optimization. Hence, completion technology was taken beyond the conventional limit and an innovative, reliable and cost effective approach applied through complete integration of the service companies.

The main interest was to reduce the operational risks with diverse and enhanced completion equipment in order to reach the plateau as quickly as possible. Hence, a Monobore completion design with Interventionless technology was embraced in this offshore field development. The total budget for the first phase of the development is $1.5 billion (U.S.) and it covers drilling, completion, construction and production installations.

This paper will discuss the well completion designs, material selection, manufacturing, preparation, execution and evaluation of the Amenam/Kpono well completion. The paper will focus more on how new technologies (Reservoir drilling fluid, fluid spring-operated valve, gravel-pack packer, tubing-tester flapper valve, production packer, permanent gauge, etc) are integrated in all the wells, and especially, in the challenging horizontal gas injectors.

By using these technologies, completion efficiency was increased, safety performance was improved, and rig cost was reduced by 50 hours per well.
Trinidad and Tobago's Deepwater Drilling Saga
Authors: Rajnauth Jerome , Boodoo Craig
Published: December 2007

Trinidad and Tobago is endowed with abundant oil and gas reserves both onshore and offshore. Most of the reserves offshore have been found in the shallow water shelf area. Over the last couple of years exploring the deep waters beyond the shelf (>1000 meters) has been looked at with much anticipation. However, the eight (8) wells drilled thus far have not found hydrocarbons in commercial quantities. It is important to note however, that many geo-scientists believe the exploration work in the deepwater proved the existence of a working hydrocarbon system.

The drilling phase of the exploration activities in the deepwater blocks (i.e Blocks 25(a), 25(b), 26 and 27) produced many challenges. This paper will look at the major problems, risks and uncertainties encountered during the drilling of these wells and highlight key learnings that would be useful for further drilling in the deep and ultra deep waters off Trinidad and Tobago. The major well objectives will be perused to determine if these were actually attained.

Results showed that some of the wells were unable to reach their technical objectives. As a result the actual number of days and cost for some wells were less than originally planned.
Solid Expandable Tubular Technology: The Value of Planned Installation vs. Contingency
Authors: Rivenbark Mark , Demong Karl , Mulhem Sami S. , Olivera Glen
Published: December 2007

From deepwater exploration to onshore producing wells, solid expandable tubular technology can provide substantial savings in total well cost. Operators considering new options in well design have discovered the potential and practicality of these expandable systems. Land wells are being planned using the technology to slim wellbore design. Offshore wells have coupled the slimming well-design concept with a surface stack to enhance the drilling process.

Limitations associated with using a surface stack frequently result in well depth targets being missed. Solid expandable tubular technology provides casing design alternatives that allow access to these previously out-of-reach targets. Simply put, employing expandable technology in the surface stack process allows wells to be drilled deeper at less cost.

Early deepwater surface stack technology was limited to a four-casing string well design (13-3/8 in., 11-3/4 in., 9-5/8 in., and 7 in.). Shallower reservoirs proved to be within reach of this four-string well design, prompting identification of prospects in deeper reservoirs. These subsequent reservoirs pushed the targets to depths unreachable using the conventional four-string well design. Solid expandable tubular systems provided the technology to reach the targets by incorporating two additional casing strings (9-5/8 × 11-3/4 in. and 7-5/8 in. × 9-3/8 in.) while still maintaining hole size. Deepwater surface stack technology is evolving to a five-casing string conventional well design capability (16 in., 13-3/8 in., 11-3/4 in., 9-5/8 in. and 7 in.) with the option of incorporating three solid expandable tubular strings (13-3/8 × 16 in., 9-5/8 × 11-3/4 in., and 7-5/8 × 9-3/8 in.). Drilling wells using solid expandable tubulars with a surface stack translates into savings in wellheads and risers, mud, cement, and cuttings removal.

Solid expandable tubulars are proving to be just as adaptable and cost efficient in land well construction. Onshore wells with four-string casing designs are being slimmed so that an entire 7,000 ft well can be drilled with no hole section larger than 12-1/4 in., eliminating traditional 22 or 17-1/2 in. hole sizes. The smaller hole also increases the rate of penetration (ROP)

This paper will discuss the unique challenges of casing systems associated with both deepwater and onshore exploration. The process of identifying, planning, and executing the integration of solid expandable tubulars with surface stack drilling will be analyzed and evaluated. Diverse case histories will illustrate how these technologies can overcome the limitations of conventional technology, and do so in a cost-effective way.
Transition Time of Cement Slurries, Definitions and Misconceptions, Related to Annular Fluid Migration
Authors: Rogers Murray J. , Dillenbeck Robert L. , Eid Ramy N.
Published: December 2007

Transition time of cement slurries is a term that has been used throughout the oil industry for many years. During this time, the term has been defined, redefined and misused to cover a wide range of cementing topics. This has led to numerous misconceptions and confusion as to what transition time really means. For many years, this term has been directly tied to the term right-angle-set, which relates to the speed in which slurries undergoing continuous shear go from a pumpable to a non-pumpable state. Once pumping is stopped, the profile of how cement transition from a liquid, to a gel, to a set cement changes. These changes can directly affect the performance of cement slurries to control fluid migration.

With the advent of the Ultrasonic Cement Analyzer (UCA), the term "transition time" of cement slurries was redefined. UCA&s have developed into an essential piece of equipment. Not only can they achieve compressive strength information, but the apparatus can also provide a continuous measurement of how cement sets in static state. This information has shortened wait on cement (WOC) time, and provides an excellent profile on how fast cement develops strength. However, the transducers in a standard UCA only provide information after the cement develops a compressive strength set. With improvement in computerization and transducers, a more sensitive evaluation of gel strength development can be studied.

Another definition for transition time is the use of a static gel strength (SGS) analyzer to measure the time from which cement goes from 100 lbf/100 sq. ft (48 Pa) to 500 lbf/100 sq.ft (240 Pa). It has become an industry standard that once cement slurries reach an SGS of 500 lbf/100 sq. ft (240 Pa)., gas or other fluids cannot be transmitted through the cement. The faster that you achieve this optimum SGS, the less likely that the cement will transmit gas.

This paper will establish a definition for cement transition time and discuss the misconception of only using gel strength development to control gas migration. Test data that exhibits gas tight slurries with long transition and those with short transition that allowed gas influx will be shown. Also discussed in the paper will be the advantages of cements with a short transition in controlling high-pressure water flows.
Crosslinking of Guar and Guar Derivatives
Authors: Lei Cuiyue , Clark P. E.
Published: December 2007

Crosslinking of guar and guar derivatives has played a major role in improving stimulation of oil and gas wells. While crosslinking has been used for a number of years, many facets of crosslinked systems are still not well understood. Part of the problem is that the traditional methods of determining the properties of crosslinked fluids work well for obtaining the data necessary for treatment design, but yield little information about nature of the crosslinked system. A good example of this is found in the development of low polymer concentration crosslinked gels. These gels are important because they lower costs and help to minimize formation damage. In this paper, methods for predicting crosslinkability at low concentrations will be examined.

The polymer literature is filled with methods of characterizing polymer solutions almost none of which find wide use in the development of crosslinked fracturing fluids. Dawson, et. al.,1 first reported that the concentration at which a polymer solution transitions from dilute to semidilute could be used as a method for determining the potential for low concentration crosslinking in a guar or guar derivative solutions. This finding was controversial, to say the least. To test this assertion, we have conducted a series of experiments that not only show that the transition concentration is an important indicator, but also present a framework for exploring the potential of other crosslinked systems. Interestingly, polymers that crosslink well at low concentrations do not always produce the best crosslinked gel at higher concentrations. Based on our experiments, we will present an explanation for this finding. This emphasizes the importance of understanding the crosslinking process in order to optimize the selection of a polymer for a particular application.

This paper examines guar and guar derivative systems used in the industry and reports on a new guar that can be successfully crosslinked at low concentrations. It also provides a outline for studying crosslinking at low concentrations and presents insights into the crosslinking process.