bluuebunny/crossref_metadata_2025 huggingface dataset:
Colorado E&P Storage Tank Emission Factor Development
Authors: Smith Ty J. , Wonstolen Ken
Published: December 2007

A simple, cost effective methodology was sought to calculate storage tank emissions for exploration and production (E&P) operators in Colorado. This effort was prompted by a proposed regulatory change that would eliminate the exemption of crude oil and condensate storage tanks from emission reporting/permitting requirements. Due to the potential economic impact to the producers of over 14,000 existing wells across the state, the Colorado Oil and Gas Association (COGA) proposed a study to characterize the emissions from these E&P storage tanks to the Colorado Air Pollution Control Division (APCD).

COGA, with the involvement of the APCD, contracted Lesair Environmental to conduct the emission study. Using existing data from the Oil and Gas Conservation Commission, a sampling strategy based on applicable producing areas was developed and implemented. Sample analysis results were then used to calculate theoretical tank flash emissions using two different process simulation software packages, E&P Tank v2.0 and PROSIM 98.3. The resulting emissions from each sample were compared using several parameters.

Upon completion, the study results were presented to the APCD. In a cooperative effort, statewide and specific producing area emission factors were developed for both volatile organic compounds and individual hazardous air pollutants. Use of these factors allows an E&P operator to need only an annual tank throughput to estimate the emissions from the storage tank. In addition to the benefits derived from this simple, cost effective emission estimation methodology, COGA was able to help the APCD understand some of the unique issues associated with regulating air quality emissions from E&P operations.
Reducing Well Delivery Unit Technical Cost Using Expandable Sand Screens ESS With Medium Radius Technology On Sidetrack Wells
Authors: Oluwatosin A. O. , Adegborioye A. M. , Anya S. O.
Published: December 2007

The drive for continuous reduction in the Unit Technical Cost of oil production led to the kick-off of a Medium to Intermediate radius Horizontal Sidetrack Campaign in 1999. This campaign planned to deliver 18 wells and increase production by sidetracking existing wells and landing them at horizontal with 12 - 45°/100ft dogleg severity. The plan was to increase production by 33MBOPD with an average cost of $1.5m per well over the 18 well campaign, resulting into a UTC of 3.2 $/bbls; See Table 1& Appendix D.

The availability of technology for medium radius trajectory drilling in combination with the successful deployment of Expandable Sand Screen (ESS) in Shell Petroleum Development Company Nigeria (SPDC) provided a trial opportunity for the campaign to reduce cost and increase production in it's 3rd well. This was to provide the option of ESS implementation in the subsequent horizontal sidetrack campaign wells.

The ESS was deployed at doglegs up to 18°/100ft proving the efficacy of the integration of ESS technology with medium radius applications. The introduction of the Expandable Sand Screen (ESS) technology in the 3rd well of the campaign led to an increase in production of 2,000 BOPD with a corresponding reduction in UTC of 63%. This integration of ESS technology with medium radius well technology has increased the toolbox options for brown field development in Nigeria and the world at large.

This paper focuses on the challenges involved in the planning and execution of the wells using medium radius and ESS technology. It emphasizes the well design issues and the ESS deployment design challenges. Finally, it reviews the milestones achieved and the high impact on overall well economics.
Stimulation of High-Temperature Sandstone Wells in Steam Drive and SAGD Areas
Authors: Henderson Greg J. , Nokonechny Stacey , Meyer Russ
Published: December 2007

Steam drive and SAGD (Steam Assisted Gravity Drainage) are common methods of producing heavy oil in many areas of the world. Feedstock water is taken from a local water source, converted to steam and pumped down an injector well. The steam heats the fluids in the formation reducing the native bitumen viscosity allowing it to flow to a nearby producing well. This process has the potential to produce several damage scenarios including carbonate and/or silicate scales, asphaltene deposition or formation fines migration. A procedure has been developed to remove formation damage and provide matrix stimulation in the shallow, extremely high BHT (200°C), sandstone wells in producing Steam Drive and SAGD wells.

The producer's wells covered in this paper are located in the heavy oil region of Bolney, which is northeast of Lloydminster, Alberta, Canada. In many cases, the horizontal section of the producing wells are completed using slotted liners consisting of alternating blank and slotted sections. The slotted liner helps prevent sand production and maintain wellbore integrity while still allowing fluid inflow to occur. In addition to the original liners, most of the Bolney producers had additional screens put inside the liners that provided a smaller slot size. This was done to help with fine sand production problems the field experienced after initial completion. This completion configuration presents challenges in stimulating the ‘behind’ pipe formation which also includes the space between the slotted liner and open hole and the near wellbore region.

The acid treatment involves various pre-flush fluids and a unique retarded hydrofluoric acid system that results in the slow release of hydrofluoric acid in the formation to yield deep penetration into high temperature sandstone reservoirs. Not only is the reaction with fines and clays retarded, the retardation chemistry stabilize reaction products in spent acid to help control precipitation damage.

Over a time period of five years, information from various analyses was obtained which confirmed some of the damage mechanisms that can be present in the producing wells. Two particular wells, which are presented in detail, have been treated on three occasions over these five years and on each treatment, a different volume of stimulation fluid and a separate application technique has been utilized. Each treatment produced a markedly different production profile. The production increase can be correlated to the treatment type and volume of fluid used. Presented in this paper is the evolution of the process where multiple wells where stimulated utilizing various treatment types and volumes and the resulting production analyzed to optimize the process.
Multiple Precision Hydraulic Fractures of Low-Permeability Horizontal Openhole Sandstone Wells
Authors: Hoch Ottmar , Stromquist Marty , Love Gordon , Argan John
Published: December 2007

Many horizontal wells with openhole completions have been drilled in low-permeability sandstone formations. The Cardium formation in west-central Alberta, Canada is one such case. Many of these wells perform below predicted rates with uneconomical gas production. Until recently, no method existed to effectively fracture stimulate this type of wellbore to optimize production.

Possible reasons for low production rates in these wells include vertical heterogeneity of the sandstone, low horizontal permeability, and much lower vertical permeability. The heterogeneities in the sandstone can act as barriers to vertical flow. Near wellbore damage is another possible reason for low production. One way to neutralize the effect of these barriers or damage is to hydraulically fracture the formation, effectively connecting the full porous height of the formation to the wellbore through a propped vertical fracture. Nevertheless, if only one hydraulic fracture is placed, the horizontal wellbore may not produce more than a vertical well. A new hydrajet-fracturing technique, however, now exists whereby many propped hydraulic fractures can be placed individually at strategically selected locations along an openhole wellbore. The resulting horizontal wellbore with multiple propped fractures can potentially produce gas at rates higher than those of a vertical well.

This paper briefly describes the hydrajet-fracturing process and documents two case histories from the Cardium formation in which this system was applied. Both wells were hydraulically proppant fractured at multiple locations precisely placed along their openhole horizontal wellbores.
A Step Change in Collaborative Decision Making - Onshore Drilling Center as the New Work Space
Authors: Herbert Mike , Pedersen Jarle , Pedersen Terje
Published: December 2007

For years, offshore shuttling to accommodate insufficient bed-space has invoked a safety risk for offshore workers. A North Sea operator has overcome this by implementing tools to dramatically change the normal work flow in decision making.

Since 1999, the mudlogging crew on the Ekofisk Platform in the North Sea has been performing well monitoring from the operator's onshore office in Tananger, Norway. The deployment of a fiber optic network in this area of the North Sea has provided the means for a reliable workflow with the benfit of reduced travel to the rig and improved integration between onshore and offshore teams.

Building on these experiences, a concept was developed to take a "Step Change In Collaborative Decision Making" by building a completely new Onshore Drilling Centre (ODC) and real time data monitoring system. Project planning started in February 2002 and the center was opened and functional by 6 November 2002.

A visualization, telecommunication and data-sharing network and well monitoring system has been developed and installed to assist the offshore operations on a twenty four hours, seven days a week basis

In addition to reducing offshore travel, the objective of the ODC is to reduce the number of iterations in well trajectory planning, reduce drilling cost, improve geosteering decisions and improve integration between drilling and geology, hence reducing unwanted safety incidents while drilling.

This paper describes the technology, people and processes employed to build the ODC. The new work flow in well planning and execution of drilling complex ERD and horizontal wells from the ODC is described. Preliminary results from these new collaborative work processes will be outlined.
Underbalanced Drilling with Casing Evolution in the South Texas Vicksburg
Authors: Gordon Doug , Billa Rich , Weissman Mike , Hou Fu
Published: December 2007

Drilling with production casing while underbalanced is improving the drilling performance dramatically in South Texas fields. This approach allows drilling of depleted and high pressure sands intermingled within one hole section, resulting in significantly less expensive well plans. Drilling cost reductions of 30% have been realized. Smaller reserve targets are viable, a key advantage in the mature South Texas Vicksburg play.
Comparison of Minimum Miscibility Pressures Determined from Gas-Oil Interfacial Tension Measurements with Equation of State Calculations
Authors: Ayirala S. C. , Rao D. N. , Casteel Jerry
Published: December 2007

Miscible gas injection has been widely used as the most popular enhanced oil recovery process for light oil reservoirs. For technical and economic success of miscible gas injection projects, an accurate laboratory measurement of minimum miscibility pressure at reservoir temperature is essential. In addition to the existing laboratory techniques of measuring MMP namely slim-tube and rising bubble, recently a new technique of measurement called vanishing interfacial tension (VIT) has been developed. This new technique enables rapid and cost-effective determination of MMP. Hence, the objective of this study is to compare the minimum miscibility pressures determined from gas-oil interfacial tension measurements with those obtained from phase behavior calculations based on equations of state (EOS). For this purpose, two commercial crude oils namely Rainbow Keg River (RKR) and Terra Nova have been used, since the PVT data necessary for EOS calculations and the experimental values of MMP were available for these two reservoir cases. Peng-Robinson (PR) equation of state within a commercial software package has been used. The effects of tuning and non-tuning the equation of state on MMP calculations have been examined.

For the two reservoir cases considered in our study, tuned PR-EOS yielded significant differences between MMPs from EOS calculations and VIT measurements, while untuned PREOS yielded reasonable match with experiments. In the case of RKR crude oil, the untuned EOS predictions were consistently higher by about 3.0-5.0 MPa than the experimental MMP from the VIT technique. For Terra Nova crude oil, in three out of five cases studied, the visible MMPs from the VIT experiments reasonably matched with untuned EOS calculations. Therefore, these comparisons of VIT results with EOS predictions clearly demonstrate that this new technique of vanishing interfacial tension is quite promising and reliable.
An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive
Authors: Tang G. -Q. , Leung T. , Castanier L. M. , Sahni A. , Gadelle F. , Kumar M. , Kovscek A. R.
Published: December 2007

Solution-gas drive has been implemented successfully for some heavy-oil reservoirs in Canada and Venezuela since the 1980's. Nevertheless, the mechanisms of heavy oil-solution gas drive remain unclear. The objective of this study is to probe the phenomenon experimentally. To this end, a series of depletion experiments were conducted that employ heavy crude oils from two different fields in Venezuela and two viscous mineral oils. The experiments were conducted at reservoir temperatures for crude oils and room temperature for mineral oils with similar viscosity. The sandpack is made up of Ottawa sands with a porosity of about 20-30% and permeability of roughly 2.7-5 Darcy. The sandpack is placed in a specially designed aluminum coreholder that allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell with a window size of 5 x 40 x 0.05 mm (width × length × thickness) was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior versus pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation versus pressure. Importantly, these results help us to understand the gas flow pattern inside the sandpack.

Results show that solution gas-drive is effective even at reservoir temperatures as high as 80°C. Oil recovery ranges from 12-30% OOIP; the higher the depletion rate, the greater the recovery rate. Secondly, both depletion rate and oil composition affect the size of mobile bubbles observed. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however foam-like flow behavior is still found for the more viscous crude oil during the early and middle periods of gas and oil production. No foam-like flow is observed for the mineral oils. Third, intermittent gas-bubble flow causes the produced gas-oil ratio (GOR) to fluctuate over time. Fourth, CT images show that the gas saturation distribution along the sandpack is not uniform at our test conditions; high gas saturation at the outlet is observed for virtually all oils. Away from the outlet, gas saturation is also heterogeneous and apparently related to heterogeneities within the pack. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow.
Experimental Investigation of Oil Drainage Rates in the Vapex Process for Heavy Oil and Bitumen Reservoirs
Authors: Karmaker Kulada , Maini Brij B.
Published: December 2007

Vapor extraction (Vapex) process is an emerging technology for viscous oil recovery that has gained much attention in the oil industry, as it appears to be superior to the currently used thermal based recovery methods. The process has potential to succeed even in some problematic scenarios, such as reservoirs with an overlying gas cap, bottom water table, high water saturation, low thermal conductivity, thin pay zone, etc. However, the oil production rates in the field as predicted by previous researchers are too low to make this process attractive for field implementation. Their predictions are based on the results from physical model experiments and the scaling-up method that hypothesizes that the oil recovery rate in the Vapex process should be proportional to the square root of the reservoir transmissibility. This scaling-up theory ignores the role of dispersional mixing between solvent vapors and in-situ oil during the gravity drainage process in porous media.

The objective of this study was to reinvestigate the oil drainage rates and thereby examine the scale-up method in the Vapex process. An extensive experimental study was carried out with three different physical models of varying sizes that were partially scaled. These models were packed with the sand-grains of three different size distributions. The Vapex experiments were carried out to investigate the effects of laboratory model size and sand-grain size on the observed performance of the Vapex process. The results show that much higher oil rates in field processes are possible compared to those predicted by previous investigators based on the results from Hele-Shaw cell experiments and the available scale-up procedure.
A New Planning Tool for Smart Fields Evaluation
Authors: Lund Bjørnar , Kolnes Øyvind , Michelsen Finn Are , Halvorsen Ivar J , Nyhavn Fridtjof
Published: December 2007

Downhole Instrumentation And Control Systems enable optimization of Production and Reservoir Management. This paper focuses short-term Production Optimization of a well pair (injector and producer) with expected sand production problems. Simulations show that profit could be gained.

The simulations are based on simplified models (assures high speed computations, a requirement in stochastic numerical uncertainty handling) for flow through wells and reservoir, and a volumetric sand production model. Although no stochastic uncertainty simulations are reported here, the effort of simplifying models is motivated by this. Cases with and without optimization are compared. Additionally, one case with a stuck valve indicates the sensitivity of equipment failures. We also discuss interactive use of the software as a learning tool for improved understanding of reservoir properties and behavior.
Production Diagnostic Analyses with Incomplete or No Pressure Records
Authors: Poe B. D.
Published: December 2007

This paper discusses the use of quantitative production diagnostic analyses for unfractured vertical wells and finite-conductivity vertically fractured wells that have partial or entirely absent well flowing pressure records corresponding to the flow rate data. The production rate data are almost always available for a production performance analysis of a well, since the hydrocarbon production relates directly to the revenue from the well and often the water production data is available since it is a production or operating cost. However, the corresponding flowing pressure data are often incomplete, or in the case of artificially lifted wells, the flowing pressure data are generally not available.

The diagnostic analyses considered in this paper are complimentary to the decline curve analysis matching procedure reported in an earlier publication that utilized an effective convolution analysis that does not require that the flowing pressures be known for each of the production data points in the production history of a well. The use of diagnostic analyses procedures in conjunction with the log-log production decline curve analyses can dramatically reduce the uniqueness problems often encountered in production decline analysis type curve matching procedures using the effective convolution analysis methodology.
Stochastic Sensitivity Analysis: Or What Happened to my Tornado Plot?
Authors: Mudford Brett , Kuch Suzanne
Published: December 2007

As the upstream E&P industry moves into riskier environments and the competition for capital becomes tighter there is an increasing push to carry out more sophisticated analysis that includes the effects of uncertainty and risk. Traditionally, much economic analysis has focused on a mean case, or few cases that capture high, medium, low and failure outcomes. Sensitivity analysis is then used to assess the impact on economic value as the inputs, such as recoverable volumes, production rates, operating expense and capital are varied independently of one another. The results from this type of analysis are often displayed as a tornado diagram showing the variation in output as a function of variation in the input. The standard tornado diagram provides a good characterization of project drivers, provided the inputs are independent. For most realistic projects the fundamental assumption of independence between inputs is violated, and the conclusions that are drawn from the standard sensitivity analysis may be incorrect.

In this paper we will carry out a detailed sensitivity analysis of a typical deepwater Angola project. Many of the geoscience and engineering inputs for the economic analysis of this project have distributions, and there are also a large number of dependencies between the various inputs in the model. We will derive stochastic tornado plots that are equivalent to the familiar tornado plots described above. In addition, we will show how stochastic spider plots can be developed that provide a great deal of information on project drivers and sensitivities. In this paper we will set out a range of techniques and tools that can be used to analyze stochastic models to determine economic drivers under conditions of uncertainty and dependency, without having to make unrealistic assumptions of independence between project inputs, as is common today.
Development and First Application of Bistable Expandable Sand Screen
Authors: Hackworth Matthew , Johnson Craig , Heiland Juliane , McClurkin Joel , Eubank Don , Kemp Martin , Schetky L. M. , Smith Philip S.
Published: December 2007

Sand control in an open hole typically results in risky completions, especially in weak or unconsolidated formations. Stand-alone screen completions present the risk of wellbore collapse and screen erosion, while gravel packing involves time-consuming and complicated pumping operations. Although expandable sand screens have recently become available to provide the best of both worlds, fast installation and wellbore support, design constraints limit their application. Wellbore conformance, expansion loads, and connection integrity have been critical issues with these types of screens. Where successful applications have been found, improved production with lowered drawdown have been typical.

Extensive research and finite element analysis have led to the development of bistable expansion cells. These cells have minimal plastic deformation during expansion and exhibit a hysteresis -like behavior. The specific cut pattern can open with relatively low expansion force, and then resist higher-level collapse loads. Due to the low plastic strain levels, bistable cells are compatible with any common oilfield material, achieving expansion ratios as high as 1.6 times the original screen diameter. This paper will cover the design, development, and testing of an expandable sand screen using bistable cell technology. In addition, the design and development of the proprietary expandable connection will be presented. The testing presented covers a wide range of structural integrity, expansion, sand retention, mudflow, and geomechanical tests performed on the screen, base pipe, and connection.

In late 2002, the first bistable expandable sand screen was deployed in a 4,400-ft water injection well in west Texas. The compliant expansion tool deployed the screen in one trip at speeds exceeding 1,800 feet per hour with set-down loads of less than 20,000 pounds.
Prediction of and Effective Preventative Solution for Annular Fluid Pressure Buildup on Subsea Completed Wells-Case Study
Authors: Loder Toni , Evans Jason H. , Griffith James E.
Published: December 2007

Trapped fluid commonly occurs in subsea completed wells when casing annuli attains a closed volume; for example, a subsea wellhead set and cement top inside the previous casing shoe. When the well is placed on production and wellhead temperature increases, the trapped fluid, usually drilling mud and spacer, expands. This thermal expansion significantly increases the annular pressure. Depending on the initial wellhead conditions, the trapped fluid's temperature could increase in excess of 83ºC (150º F) over ambient conditions. Laboratory testing indicates that trapped water- or synthetic oil-based fluids can increase in pressure (greater than 69 MPa or 10,000 psi) well above the casing collapse pressure if the well experiences such a differential temperature cycle.

An effective solution offered in previous literature is the incorporation of a compressible spacer in the cementing process. The compressible spacer is trapped in the closed annulus and can greatly reduce the pressure buildup if fluid expansion occurs. Deepwater operators have used this solution in a casual manner because the margin for error is somewhat large. However, in shallower subsea completed wells (less than 300m or 1,000 ft water depth), the margin of error is greatly reduced. This reduction motivates the need to find the optimal compressible spacer volume based on lower final hydrostatic pressures and appropriate volume to compensate for fluid expansion. Operationally, finding these optimal volumes helps reduce the chance of a kick condition or compressible fluid being circulated into the riser system.

This paper presents a method for calculating the optimal amount of compressible spacer to be trapped in a well's annulus. The calculations consider the expansion of the trapped fluid based on annular volume and fluid type(s). The paper also presents previously published data on various water and synthetic oil-based fluids and an example of the calculations in well conditions for an east-coast Canadian subsea well.
The Economic Analysis of a Two-Rig Approach to Drill in Deepwater Gulf of Mexico Using Dual Gradient Pumping Technology
Authors: Hariharan P. R. , Judge Robert A.
Published: December 2007

Drilling the upper hole section of wells in deepwater is conventionally done riserless with returns taken to the seabed in a process known as "pump and dump". The depth to which a hole can be drilled using this method is limited by the presence of drilling hazards (shallow water/gas) as well as the economics of not recovering drilling fluids. Using pumps developed for dual gradient drilling operations and taking the mud returns along with the drilled cuttings to the rig rather than at the seafloor can have significant impact on the costs of drilling the well. Additionally, utilizing a mud pump at the sea floor creates possibilities for managing the bottom hole pressure by varying the inlet pressure of the subsea pump. The ability to vary annular pressure allows management of potential shallow water flow situations, creating opportunities to drill through such zones and set the conductor casing, typically 20″ in the Gulf of Mexico (GOM), deeper. Setting the conductor casing deeper can significantly impact well economics, ranging from the saving of a complete size of casing string to larger final borehole completions.

To assess the viability of a solution based on using subsea mud pumps to drill the upper hole sections, an economic study and analysis of the costs of drilling deepwater wells in the GOM was carried out. This paper discusses the results and the economic benefits based on a probabilistic risk-based cost analysis comparing cost data of actual wells drilled in the Gulf of Mexico to wells that were modeled using the alternate drilling method. In the modeled wells, two rigs were used, one to drill and set the conductor casing only, followed by another rig to complete the well. For this paper, the drilling costs for the 2-rig approach are compared to the costs of conventionally drilling the same well. Details of the analysis, the modeling process and the assumptions are discussed. The analysis showed that significant savings in well costs are possible, and on a conservative basis varied from 6 – 25% of the total well cost. The analysis also showed that apart from cost savings, using such a 2-rig arrangement could also aid in mitigation of risk while deploying new technologies by transferring the risk to the first rig used solely for drilling the upper hole sections.
Accounting for Interpreted Well Test Pore Volumes in Reservoir Modeling
Authors: Zhang Linan , Cunha Luciane B. , Deutsch Clayton V.
Published: December 2007

Optimal reservoir management requires reliable reservoir performance forecasts with as little uncertainty as possible. There is a need for improved techniques for dynamic data intergration to construct realistic reservoir models by using geostatistical techniques. This paper gives a method to create porosity models that honor interpreted pore volumes from well test data. Well porosity data, seismic data and well test results are integrated in sequential simulation. Seismic data is modified iteratively until the co-simulated porosity matches the interpreted well test pore volume. A number of examples are shown.
Effect of Scale Up and Aggregation on the Analysis of Interference Tests
Authors: Rajagopal Raghavan , Roesler Ralph R. , Tureyen O. Inanc
Published: December 2007

The objectives of this paper are to demonstrate the impact of detailed and small-scale heterogeneities upon interference tests. Specific issues encountered when interference tests are analyzed in reservoirs with complex geological properties are discussed. These issues relate to questions concerning the use of low-resolution models, the degree of aggregation, methodology of scale up and the reliability of conventional methods of analysis.
Estimation of Storativity Ratio in a Layered Reservoir with Crossflow
Authors: Al-Ajmi N. M. , Kazemi H. , Ozkan E.
Published: December 2007

This paper presents a practical method to estimate the storativity ratio of a layered reservoir with cross-flow from pressure transient data. The method uses an analytically derived formula for the storativity ratio in terms of the separation between the two semi-log straight lines on pressure versus log-time plot. Knowing the storativity ratio from a well test, individual layer properties may be estimated if the layer flow rates are available from production logs. Demonstrations of the method to estimate the storativity ratio and individual layer properties are presented by examples. Comparison of the results with those obtained from the existing techniques is also provided to highlight the accuracy of the proposed technique.
Modeling Imbibition Capillary Pressure Curves
Authors: Adams Stephen
Published: December 2007

Although spontaneous imbibition capillary pressures are relevant in all reservoirs having undergone or undergoing gravity stable water displacement, they are not commonly measured nor considered for reservoir modelling. Imbibition is particularly important when establishing initial hydrocarbons in place for reservoirs already having residual hydrocarbon columns prior to production commencement.

As part of a saturation-height study, an empirical model relating imbibition capillary pressure curves to their drainage precursors was created. Drainage saturation-height functions could then be used to create imbibition equivalents based upon the saturation history of the reservoir rock. Calibration was carried out using laboratory measurements of both drainage and imbibition capillary pressure curves.

This "imbibition from drainage" (IFD) model was verified against log derived water saturations from wells in the initial study area. The match was excellent in those wells considered to have reliable petrophysical evaluations. The IFD model was even able to describe imbibition capillary pressure curves for sections of reservoir in drainage transition zones prior to the commencement of water imbibition. The model has since been further verified in other hydrocarbon accumulations found in different basins.

The IFD model developed represents the first publication of a technique for creating meaningful spontaneous imbibition capillary pressure curves and imbibition saturation-height functions through reservoirs with significant capillary transition zones. The technique should be widely used to describe water saturations in reservoirs with residual hydrocarbon columns, providing better estimates of initial hydrocarbons in place than with more commonly used drainage data. Iteration of the model also allows determination of both original and current day Free Water Level locations in systems having residual hydrocarbon columns from either leakage prior to production or from gravity controlled water sweep during production.
Realistic Assessment of Proppant Pack Conductivity for Material Selection
Authors: Barree R. D. , Cox S. A. , Barree V. L. , Conway M. W.
Published: December 2007

Proppant selection in hydraulic fracturing is a critical economic and technical decision that affects stimulation and field development economics. In many cases the selection is based on laboratory data from standardized API conductivity tests on clean packs at specified stress and temperature. These tests predict conductivities that are optimistic compared to observed field performance. Often a laboratory measured conductivity difference of only 5-10% is considered a significant variance when applied to the producing life of a well. The significance of these small differences, however, is often overwhelmed by other factors affecting fracture performance in the field.

The selection of a particular proppant should be based on an identifiable difference in performance under field conditions. This requires an accurate assessment of all the damage mechanisms that can and do occur during fracturing and their impact on final conductivity. This paper outlines the primary damage mechanisms and their effect on conductivity, fracture cleanup and ultimate stimulation response. The expected variance in laboratory measurements of conductivity is also quantified.
Ultra-Lightweight Proppant Development Yields Exciting New Opportunities in Hydraulic Fracturing Design
Authors: Wood William D. , Brannon Harold D. , Rickards Allan R. , Stephenson Chris
Published: December 2007

Recent research involving the modification of the mechanical properties of particles has resulted in the development of new materials which have particle strengths suitable for application as fracturing proppant yet, possess much lower apparent specific gravity than today's commercial proppant products. For example, whereas the apparent specific gravity of commonly used Ottawa sand is 2.65 g/cc, various embodiments of the new proppant materials range from 1.25 to 2.0 g/cc.

Options for proppant selection have previously been limited to identifying the product of median particle diameter to avoid bridging and, sufficient particle strength to withstand the fracture closure stress, thus providing high proppant pack permeability. Fracturing fluids have been selected primarily based upon in-situ rheological properties in an effort to insure proppant placement by providing sufficient viscosity to minimize proppant settling.

Treatment pumping rates are limited by the wellbore configuration, the cumulative cross-sectional perforation area and, the desire to keep the fracture ‘in zone’. As the reservoir properties are fixed and the proppant variables dictated by the wellbore and reservoir stress environment, the fracturing practitioner was left with only limited control of two input variables, significantly limiting creative optimization of the stimulation treatment design.

Many potential benefits of application of the new ultra-lightweight proppant in hydraulic fracturing treatments are readily apparent. These include substantially reduced proppant settling, allowing the potential for much increased effective propped length, for fluids of lower viscosity and/or, for reduction of pumping rates. The development of the ultra-lightweight proppants is perhaps most exciting from the perspective of the stimulation design engineer, owing to the enhanced options afforded him or her to improve well stimulation. The design engineer is provided not only a new parameter to influence design, but given freedom from the previous limitations imposed on the fluid and treating rates by the high density proppants previously employed.

The objective of this paper is to identify those new opportunities afforded the stimulation design engineer, due to availability of these new ultra-lightweight proppants. Numerous fracture modeling runs have been conducted varying fluid density and rheological properties, treating rates (Reynold's Number), proppant density and size.

The results of these efforts are provided, and compared in terms of created fracture geometry, propped fracture length, propped fracture surface area, settled proppant height, and fracture conductivity. The data clearly illustrate that the use of ultra-lightweight proppant allows for optimization of fracturing treatments with greatly improved effective fracture length and more importantly, well producibility.
A New Treatment Increases the Fracture Gradient to Cure Lost Circulation and Control a Flowing HPHT Well in the East Mediterranean Sea
Authors: Sanad Medhat , Butler Carl , Waheed Arshad , Sweatman Ron
Published: December 2007

This paper addresses a well-control issue in a challenging high pressure/high temperature (HPHT) exploration well where a possible underground crossflow was in progress and the well was losing oil-based mud before reaching the final target depth below 15,000 ft (4572 m). Several days were spent trying to control the well using various formation-sealing treatment systems (some conventional and others new), but with no success. Eventually a new wellbore pressure containment improvement system (WPCIS) was implemented, and it controlled the losses effectively. Full circulation was then re-established to overbalance the HP zone and kill the well. The well had been losing at an equivalent circulating density (ECD) of 16.4 lb/gal. Application of the WPCIS process improved the wellbore pressure containment (WPC) side of the mud weight window, also called the fracture gradient (FG), to sustain an equivalent of 17.0 lb/gal mud as measured by a formation integrity test (FIT). This remarkable WPC and apparent FG improvement was achieved along with several other cost-saving factors.

Upon re-entry of the well seven months after the successful WPCIS treatment, the seal in the exit zone(s) was still holding against pressure of more than 12,000 psi and temperatures of 300°F. This sustained WPC seal by the WPCIS saved even more cost and enabled a liner to be set without losses for a successful completion of the well.

As a followup to previous discussions,1 this paper further describes the WPCIS process and its applicability and then demonstrates how the system can help optimize well plans, leading to lower costs for drilling fluids, casing design, cementing, and completion equipment. A post-treatment study is also included to help explain how the WPCIS sealing mechanism shut off the HPHT flow into the exit zone and increased the near-wellbore FG.
Brunei Field Trial of a Fibre Optic Distributed Temperature Sensor (DTS) System in a 1,000m Open Hole Horizontal Oil Producer
Authors: Lanier G. H. , Brown G. , Adams L.
Published: December 2007

A fibre optic DTS system was installed on Brunei Shell's South West Ampa (SWA) 293 well to allow real-time measurement of the temperature profile along well bore and open hole producing section. The object was to infer the inflow production profile of the well. Although fibre optic distributed temperature systems are now commonly used in different types of well applications, this particular application posed a significant challenge requiring the system to be installed in a horizontal well bore and monitor data located within a 2 degree Celsius geothermal temperature range.

Thermal simulations suggested that the inflow profiles could be used to determine whether flow was being produced from the heel, toe or distributed along the open hole section - despite the expected small degree of temperature change. In addition, the simulations suggested qualitative changes in time related to production changes associated with gas and/or water breakthrough could be identified along the horizontal producing section. This information was used to impact future development well designs, location of horizontal sections within the reservoir and planned length of horizontal.

SWA 293 well design and installation considerations will be presented along with findings and interpretations of the temperature survey results from the distributed temperature system installation.
Application of Flow-Thru Composite Frac Plugs in Tight-Gas Sand Completions
Authors: Eberhard Mike , Meijs Raymund , Johnson Jeff
Published: December 2007

Several major developmental programs in the Rocky Mountain region of the United States are in fields where zones of several hundred to several thousand feet of stacked, tight (<0.05 md) lenticular gas sands exist. In order to be productive, these wells require multiple fracture treatments over the pay interval. Since field development has been ongoing, the drilling programs are extending into more marginal production areas. Infill programs are downsizing spacing, and also, successful refracturing programs are being conducted in some fields. Before 1998, traditional methods were being used to isolate fracture treatments. These methods usually required killing the well between fracture treatments or during cleanout operations. Unfortunately, field studies have determined that the traditional isolation methods have negatively impacted well productivity.

In view of the costs involved and the lower productivity experienced with the new drilling programs, it became apparent that either well costs had to be reduced or well productivity had to be improved!

This paper will discuss the application of flow-thru composite frac plugs (FTCFP) and how they were capable of addressing the current needs to reduce operational costs and improve productivity. These plugs can be used as an alternative to traditional isolation methods, or induced stress diversion. Through June 2002, there have been over 3,200 FTCFPs run in the Rocky Mountain region. The benefits gained from FTCFP usage are derived from the following: Well drill-out costs are reducedPositive isolation is allowedAll zones can be produced during completion.

Their use has now become a "best practice" in stacked-pay completions.
Monitoring and Managing Business Performance from a Portfolio Perspective
Authors: Howell John I. , DuBois James R.
Published: December 2007

Corporations often begin each year with a corporate strategy, a business plan and high expectations of success from their pending business operations. As they execute the business plan they meet with successes and failures, all the time wondering if they should reassess future business plans. Are they better off drilling the remainder of the proposed opportunities, or should they reconsider other opportunities? These decisions are frequently impacted by emotion and intuition as much as by technical analysis.

Throughout the year, corporate executives routinely share information with analysts and stakeholders about their results to date. The information reflects their reactions to the results received to date as tempered by their expectations for the remainder of the year. This system of information collection, analysis, decisions and communication frequently lacks consistency and can be quite time consuming.

This paper will illustrate how companies can use portfolio management techniques to improve the efficiency of their business plan monitoring and the quality of the information available to the decision process. We will show how portfolio management can be used to track corporate performance and continually reassess the remaining business plans throughout the year. As results are derived, the company can use portfolio processes to monitor the expected business results and the probability of meeting their goals. We will illustrate how portfolio management can help decision makers determine when to change plans and when to stay on the planned course.
Capillary Pressure and Wettability Behavior of Coal - Water - Carbon Dioxide System
Authors: Mazumder Saikat , Plug Willem-Jan , Bruining Hans
Published: December 2007

Enhanced Coal Bed Methane (ECBM) recovery techniques, based on carbon dioxide injection, have been proposed for the recovery of larger fraction of methane in place. Laboratory studies and recent pilot field tests demonstrate that CO2 injection has the potential to enhance coal bed methane recovery through displacement desorption mechanism with an added advantage that this technology can be employed to sequester large volumes of CO2 in deep coal seem reservoirs, thereby reducing emissions of industrial CO2 as a greenhouse gas.

It can be expected that carbon dioxide enhanced ECBM is detrimentally slow unless operated at high enough pressures such that the coal becomes carbon dioxide wet. Indeed in water wet coal the small fracture system remains almost entirely filled with water and kinetics of CO2 adsorption and CH4 desorption is determined by the slow diffusion in the relatively large aggregates of water filled fractures and coal. Capillary diffusion is of the order of hundred times faster and fills the small fractures with carbon dioxide proportionally faster provided that conditions are such that the coal is CO2 wet.

For this reason we undertook to measure the capillary pressure of grounded coal between water and carbon dioxide. The grounded coal precisely exposes the coal surface of relevance here. A computer code is written, which simulates the capillary pressure experiment. The code makes it possible to get useful results before complete capillary pressure equilibrium in our laboratory cell have been attained.