bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of Dynamic Filtrate Loss During the Drilling of a Horizontal Well With Fractures and Its Impact on Well Performance
Authors: Wu Z. , Vaidya R. N. , Suryanarayana P. V.
Published: December 2007

In this paper, we present a new approach for modeling filtrate invasion during the drilling of a horizontal well with fractures, and the impact of its cleanup on well performance. The approach incorporates the drilling schedule and the experiment-based dynamic filter-loss data into multiphase reservoir simulator. Unlike the traditional leak off model in which the assumption of the piston-like displacement in the filtrate invaded zone, the fluid flow in the invaded and the reservoir zones are described by use of more realistic two-phase oil-gas flow equations which are solved under the dynamic boundary conditions of the leak off model and time-varying reservoir exposure due to drilling, tripping, completions and workovers. Since, impact of fractures on both invasion and flow-back is more pronounced in tight formations, this paper will focus on such formations.

In real drilling process, the initial dynamic mud-cake formation is critical for controlling filtrate loss. A dynamic fluid-loss model which reflects the spurt loss, non-Darcy and non-Newtonian characteristics of filtrate flow through the mud cake is coupled with the reservoir simulator. Mud properties and different events influence cake compression, dynamic cake deposition and cake erosion as well. The application of the dynamic filtrate loss model avoids the complexity in building a multi-parameter mathematical mud cake model without loss of generality. As in previous works, the dynamic filtrate loss model is based on actual special core tests.

Sensitivity analysis is conducted to study the influence of dynamic leakoff coefficient on the saturation distributions during the filtrate invasion and flowback. In existing experiments, only the leakoff coefficients for matrix are measured. The extrapolation of the dynamic leakoff coefficients for simulation of fluid loss into intersecting fractures is discussed. Driven by Buckley-Leverett equations, theoretical analysis is presented to emphasize the quantitatively spatial correlation between the invaded filtrate saturation and spatial permeability reduction in the invaded zone. Moreover, well performance influenced by the water blocking, relative permeability alteration and the damaged permeability variation are simulated. A horizontal well example is used to illustrate the flexibility of this approach. The results show that the dynamic leakoff coefficient significantly impacts the clean-up and well performance. The results also shed light on the relative value of hydraulically fracturing a conventional over-balanced drilled horizontal well, versus hydraulically fracturing the well after it is drilled underbalanced.
Distillation Effects in Heavy Oil Recovery Under Steam Injection With Hydrocarbon Additives
Authors: Jaiswal Namit J. , Mamora Daulat D.
Published: December 2007

Recent developments such as Liquid Addition to Steam for Enhancing Recovery (LASER) of bitumen during cyclic steam injection (SPE 79011) indicate increased production with the use of hydrocarbon (C5+) as a steam additive. This was attributed to viscosity reduction of bitumen when in contact with the hydrocarbon additive. However, our study indicates that steam distillation - in addition to viscosity reduction - plays an important role in enhancing heavy oil recovery.

We have conducted an experimental and analytical study to investigate the effect of (i) distillation and (ii) propane as a steam additive, with the aim of enhancing recovery of 12°API oil from San Ardo field, California. Three distillation processes were investigated: dry-, steam-, and steam-propane-distillation, the latter at propane:steam mass ratio of 0.05. Distillation temperatures ranged from 115°C to 300°C and were increased in steps of 10°C. Distillation pressures ranged from 0 psig for dry distillation to 998 psig for steam- and steam-propane distillation (15°C superheated steam conditions). In addition, yields were measured for field conditions of 260 psig and a temperature range of 220~300°C. Samples at each cut were collected and analyzed to determine volume of water and weight and composition of the hydrocarbon.

Main conclusions from the study are as follows. First, final yield at 10°C superheated conditions is practically the same for steam- and steam-propane distillation, about 10 wt%, significantly higher than that for dry distillation, 5 wt%. This clearly indicates the importance of steam distillation on oil recovery during steam- or steam-propane injection.

Second, final yield at field conditions is practically the same for steam- and steam-propane distillation, about 18 wt%. Propane appears to have little effect on the distillation of heavy oil, possibly due to the following reasons: (i) lesser light fractions in the heavy oil, and (ii) less solvent effect of propane on non-paraffinic fractions as these are less abundant in heavy oil than in intermediate crude. Third, a multi-stage thermodynamic model was developed, calibrated and satisfactorily matched experimental results of yields. This analytical model may be used for rapid selection of steam additives to evaluate their distillation performance.
A New Treatment for Wellbore Strengthening in Shale
Authors: Aston Mark S. , Alberty Mark W. , Duncum Simon , Bruton James R. , Friedheim James E. , Sanders Mark W.
Published: December 2007

The increase in complexity and associated costs with wells as a result of infield drilling, drilling below old fields and striving for deeper targets has generated industry interest and attention in wellbore strengthening. This heightened interest is demonstrated in the number of recent publications that have been prepared on the subject. These have primarily focused on and described methods that are effective in raising the fracture resistance of permeable formations such as sands. However, a much bigger impact can be made on the overall drilling operation if it is also possible to strengthen low permeability rocks such as shale along with the sands. The industry has seen this as a major challenge and to date the technology and expertise required to achieve this has not been consistent or reliable.

This paper will demonstrate that wellbore strengthening in shale is indeed feasible. A treatment pill was developed in the laboratory and successfully field tested at a US land-based location. The treatment consisted of a blend of particulates (known as stress cage solids) and proprietary cross-linked gelling polymers which set with time. Properties of the system such as compressive strength, adhesion to shale and the sensitivity to temperature and pressure were evaluated, and modeling work was done to engineer the size and concentration of bridging solids required.

Field testing was carried out in a 50-ft section of competent shale below the 9⅝-in. shoe in an operation where oil-based mud was being used. The initial fracture gradient was measured using leak-off tests to establish the native formation strength. The treatment was squeezed and allowed to set under pressure before drilling out, leaving a strengthened wellbore. Formation Integrity Tests (FIT) were conducted to confirm the presence of the strengthening effect. The robustness of the treatment was demonstrated by circulating drilling fluid for increasing periods of time and performing further FIT tests.

The well was left in a strengthened state at the end of the test period.

This trial demonstrates that by using appropriate technologies and methods it is indeed possible to reliably raise shale fracture resistance.
Estimation of Fracture Porosity of Naturally Fractured Reservoirs With No Matrix Porosity Using Fractal Discrete Fracture Networks
Authors: Kim Tae H. , Schlechter David S.
Published: December 2007

Matrix porosity is relatively easy to measure and estimate compared to fracture porosity. On the other hand, fracture porosity is highly heterogeneous and very difficult to measure and estimate. When matrix porosity of naturally fractured reservoirs (NFR) is negligible, it is very important to know fracture porosity to evaluate reservoir performance. Since fracture porosity is highly uncertain, fractal discrete fractal network (FDFN) generation codes were developed to estimate fracture porosity. To reflect scale dependent characteristics of fracture networks, fractal theories are adopted. FDFN modeling technique enables the systematic use of data obtained from image log and core analysis for estimating fracture porosity. As a result, each fracture has its own fracture aperture distribution, so that generated FDFN are similar to actual fracture systems. The results of this research will contribute to properly evaluating the fracture porosity of NFR where matrix porosity is negligible.
Porosity, Permeability, and MHR Calculations Using SEM and Thin-section Images for Characterizing Complex Mauddud-Burgan Carbonate Reservoir
Authors: Al-Bazzaz W. H. , Al-Mehanna Y. W.
Published: December 2007

This paper presents the process, and, results of the analyses of pore/grain morphology of rock fragments, from Mauddud-Burgan reservoir rock in Kuwait, for porosity, permeability and means hydraulic radius (MHR) calculations. The images are captured using SEM and thin-section analyses.

In this study, 2-dimensional images are used to characterize the morphology of the grains and pores, using a two step process. In the first step, the image is captured using a backscattered electron detector (BSE) digital electron microscopy imaging, and thin-section photography. All of the grain/ pore features captured in the image are reported in micrometer units. In the second step, the area of such features is scanned using image analysis software that has the ability to accurately measure several morphological parameters of pore and grain spaces.

A robust technique of visual estimate is used, which has the advantage of speeding the image analysis process. The visual analysis software tool counts different pores and grains and also measures their shapes and sizes that are crucial for porosity, permeability, and MHR calculations.

Several morphological features were been selected for measurement, including: object count, area, perimeter, and roundness. These analyses were conducted twice for each selected image – once for grain morphology and once for pore morphology. Porosity, permeability and MHR features are calculated based on area of the pore/ grain features measured from two-dimensional images.
Enhanced Heavy-Oil Recovery by Alkali-Surfactant Flooding
Authors: Bryan J. , Kantzas A.
Published: December 2007

This study presents the results of laboratory core studies investigating the recovery mechanisms of alkali-surfactant flooding in heavy oil reservoirs. Specifically, mixtures of water and alkali-surfactant systems have been injected into cores containing heavy oil (11 000 mPa·s and 15 000 mPa·s). Salinity is varied in order to generate oil-in-water vs. water-in-oil emulsion systems, and the effects of generating different emulsions are compared.

The application of this work is for the many heavy oil reservoirs in countries such as Canada and Venezuela containing viscous oil that still has some limited mobility under reservoir conditions. Alkali-surfactant (AS) flooding has considerable potential for non-thermal oil recovery after primary production.

Experiments were performed on cores with varying permeability, at different AS injection rates. All tests were performed on gas-free oil systems. The response from direct injection of AS systems is compared to AS injection after waterflooding. Pressure and oil recovery information is obtained from core floods, and these results are interpreted based on a semi-theoretical framework obtained from phase behavior and bulk liquid studies. It is demonstrated that both oil-in-water and water-in-oil emulsions can lead to the recovery of additional oil.

Alkali-surfactant flooding is already an established technique in conventional oil reservoirs, whereby enhanced oil recovery is a result of reduced trapping of oil due to the lowered oil/water interfacial tension. In addition, the injection of these chemicals may lead to the formation of emulsions, as has been documented by previous researchers. In our work, we demonstrate that in heavy oil systems, emulsion formation is a necessary requirement for the production of heavy oil. When these emulsions form, AS injection can lead to considerable improvements in the flooding response, even without the addition of polymers to stabilize the flood.
The Evolution of the Heavy-Oil-Exploratory-Well Testing Methodology—A Case History From Block 39 in the Amazon Rainforest of Peru
Authors: Prioletta Antonio , Cadena Jaime , Cachutt Rafael , Sersen Mateo , Flores Jose G. , Loli Manuel
Published: December 2007

The exploration for oil and gas is increasing in Peru, with 37 exploratory blocks currently under contract. Repsol YPF has an aggressive exploratory program for Block 39 in the Amazon rainforest of Northeastern Peru. Three wells have been drilled in the last two-year exploration campaign, all resulting in the discovery of heavy oils (API<15°, μ0>500 cp, GOR<40 scf/stb) from the Casablanca, Chonta and Vivian formations, consisting of reservoirs with excellent rock properties, but lacking sufficient energy to flow to the surface.

To be able to accurately assess the value of the discoveries, it was necessary to evaluate each of the prospective horizons via Drill Stem Tests (DST). However, testing heavy oil reservoirs via DST is a challenging problem, as stable production rates, important for the analysis of pressure transients, are seldom encountered. Due to heavier densities, lower solution gas volumes and higher viscosities, heavy oil reservoirs stand a lower chance of flowing to the surface than lighter oils. The problem is further complicated in the case of exploratory wells, where little can be anticipated in terms of knowledge of the reservoir properties, reservoir fluids and pressures.

The conventional exploratory well testing procedure in the area consists of perforating runs with either wireline or Tubing Conveyed Perforating (TCP) and separate DST runs, with questionable results in terms of quality evaluation of the reservoirs. The heavy-oil exploratory wells of Northeastern Peru needed an assembly capable of perforating, testing and artificially lifting the fluids to the surface for adequate production, sampling and reservoir evaluation, and that also reduced the time and cost associated with the testing of exploratory wells.

Different configurations, consisting of TCP perforating and DST tools, followed by separate ESP runs in combination with a DST string (to be able to shut-the-well-in downhole) were run in the first two discovery wells in Block 39. Based on lessons learned, a TCP-DST-ESP string was run in the third well with the purpose of perforating under dynamic underbalance conditions, producing at stable rates, sampling, and making downhole shut-ins, all in the same run. Results were outstanding, from both the operational and the reservoir evaluation sides, saving considerable rig time and resources, also achieving maximum reservoir productivity by minimizing formation damage.

This paper goes over the planning stage, the evolution of the well-testing methodology, and the field operational details, highlighting the technical results and most relevant achievements. The multi-disciplinary approach, combining well operations with reservoir engineering, well testing and artificial lift disciplines, was considered instrumental in achieving this project's outstanding results.
Modeling the Economic Impact of Cognitive Biases on Oil and Gas Decisions
Authors: Welsh M. B. , Begg S. H. , Bratvold R. B.
Published: December 2007

Cognitive biases have long been known to impact decisions taken under conditions of uncertainty [1, 2]. Previous demonstrations of these biases, however, have focused on their impact on a single, typically technical, parameter judgment rather than examining their potential impact on economics when applied to all of the judgments involved in a complex Oil and Gas (O&G) decision such as reservoir characterization. Herein, we model the impact of three individual biases – overconfidence [2], bias resulting from the trust heuristic [3] and availability [4] - to measure their effect on economic outcome as represented by NPV.

All three biases are shown to have marked effects on the estimated value of a project, not just its uncertainty. Overconfidence at the levels people commonly demonstrate shown to result in a $259 million dollar mistake in calculating NPV in our modeled decision – making a project with a negative NPV seem to have a positive NPV. Availability bias, as modeled herein, similarly acts to increase the apparent NPV of a project – making a project actually likely to result in a $55 million dollar loss seem to have an NPV of up to $329 million.

The trust heuristic differs slightly in that its use, rather than actively causing bias, prevents the use of techniques that reduce overconfidence. The model shows that incorporating the views of five experts rather than accepting the values provided by the best of the five reduces overconfidence by 10%, even when agreement between the experts is high. Referring this back to our overconfidence model results, we note that this equates to a difference of up to $125 million in the mean NPV of the project.

On the basis of our findings, we argue that industry personnel be educated in the psychological limitations affecting decision making as awareness of their existence is the first step in reducing their effect [5]. Further, the inclusion of such material in petroleum engineering and geosciences curricula would be an effective way of ensuring that knowledge of cognitive biases spreads across the industry [6].
Barnett Shale Completions: A Method for Assessing New Completion Strategies
Authors: Leonard R. , Woodroof R. , Bullard K. , Middlebrook M. , Wilson R.
Published: December 2007

Activity in the Barnett shale of north Texas has continued to surge over the past several years, and with this surge in activity has come a steady evolution of completion strategies. Most operators agree that the best Barnett shale wells are those that have the most extensive fracture network development. One of the biggest challenges facing operators has been determining which completion strategy will create the largest fracture network along with identifying the most cost-effective diagnostic methods for evaluating those strategies and ultimately optimizing the completions.

This paper will describe an integrated completion diagnostic methodology for assessing and potentially optimizing Barnett shale completion strategies. The methodology described employs radioactive tracing and logging together with chemical tracing and conventional completion metrics to evaluate the effectiveness of Barnett completions.

This methodology will be utilized to assess the effectiveness of four pairs of simultaneously-fractured parallel horizontal laterals located in three different areas stretching from the western edge of the Barnett "Core Area" to the western edge of the play's expansion acreage. Key completion parameters were identified that can be used to optimize future Barnett completions in this and potentially other areas within the basin.
Sensitivity of Project Economics to Uncertainty in Type and Parameters of Oil Price Models
Authors: Begg S. H. , Smit N.
Published: December 2007

Dynamic price models (which replicate the characteristics of real price fluctuations over time, not just the mean) are a crucial element in economic evaluations. However, there has been little systematic evaluation of the effects of uncertainty in what type of model is most appropriate, or of uncertainty in the parameters of such models.

We present the results of a sensitivity analysis of economic metrics to uncertainty in both type of oil price model and in the values of the model parameters. Uncertainty in both arises from arbitrary choices in their derivation from historical data and from uncertainty as to whether the past predicts the future.

We take four types of price model (simple probabilistic, Geometric Brownian Motion, mean reverting, mean-reverting with jumps) and use historical data to derive estimates (and uncertainty therein) of the numerical values of their respective parameters. The impact of model choice and parameter uncertainty is then compared via their impact on economic metrics for a typical field development decision.
Application of Convolution and Average Pressure Approximation for Solving Nonlinear Flow Problems—Constant Wellbore Pressure Case
Authors: Zhakupov M. , Ilk D. , Blasingame T. A.
Published: December 2007

"Real gas" flow problems (i.e., problems where the gas properties are specifically taken as implicit functions of pressure, temperature, and composition) are particularly challenging because the diffusivity equation for the "real gas" flow case is strongly non-linear. Whereas different methods exist which allow us to approximate the solution of the real gas diffusivity equation, all of these approximate methods have limitations (including numerical models).

The purpose of this work is to provide a direct solution mechanism for the case of time-dependent real gas flow which uses an approach that combines the so-called average pressure approximation (a convolution for the right-hand-side nonlinearity) and the Laplace transformation. For reference, Mireles and Blasingame used a similar scheme to solve the real gas flow problem conditioned by the constant rate inner boundary condition.

In this work we provide a direct solution scheme to solve the constant pressure inner boundary condition problem. Our new semi-analytical solution was developed and implemented in the form of a direct (non-iterative) numerical procedure and successfully verified against numerical simulation.
Collecting Single-Phase Retrograde Gas Samples at Near-Dewpoint Reservoir Pressure in Carbonates Using a Pump-Out Formation Tester with an Oval Pad
Authors: Jones Chris , Alta Wandi , Singh Jorawar , Engelman Bob , Proett Mark , Pedigo Bob
Published: December 2007

Collecting representative, single-phase retrograde gas samples from heterogeneous fractured carbonate formations is challenging, especially for cases in which the reservoir pressure narrowly exceeds the dewpoint. Conventional wireline probe/packer assemblies are undesirable in this situation because their small diameter probes increase the pressure drawdown, compared to other available intake configurations. Furthermore, the likelihood of establishing hydraulic communication with an open fracture or vug is low with a ½-in. diameter probe, compared to setting straddle packers spanning a 1-m formation interval. The straddle packer intake geometry reduces the drawdown pressure required to establish flow, thus maintaining the flowing pressure above the dewpoint and preventing the onset of unwanted condensation.

Inflatable straddle packers can be run with pump-out test tools, but they have temperature, pressure, and operational limitations. The new Oval Pad* design, an elongated oval-shaped probe/pad assembly, possesses many of the advantages of dual packers without their limitations. Like a straddle packer, the Oval Pad tool is effective when testing thinly laminated and tight formations as well as fractured or vuggy carbonates. The oval shape enables the pad to encompass a significant vertical length of the borehole while establishing a pressure seal with the formation.

A retrograde gas reservoir is contained within the vuggy carbonates in the Jambi Merang area of South Sumatra. Here the reservoir pressure narrowly exceeds the dewpoint. Pressure must be maintained above the dewpoint during sampling operations to prevent unwanted phase separation. The RDT pump-out tester was fitted with Oval Pad and nitrogen-charged sample bottles to collect single-phase samples and to keep the phase intact until PVT properties can be analyzed in the laboratory. These samples were necessary to determine laboratory PVT properties and to define a production strategy.

This paper presents the details and challenges of the successful collection of single-phase samples in this environment.
Advanced LWD and Directional Drilling Technologies Overcome Drilling and Completion Challenges in Lateral Wells of Barnett Shale
Authors: Janwadkar Sandeep , Morris Stephen , Potts Mike , Kelley Jeff , Fortenberry David , Roberts Geoff , Kramer Mark , Privott Steve , Rogers Tom
Published: December 2007

The Barnett Shale field of North Texas is the most prolific and fastest growing natural gas field in North America.1 The field has a multi-trillion cubic feet equivalent of upside potential, but efficient extraction of natural gas from the Barnett shale poses drilling and completion challenges.1 Low porosity in the horizontal interval makes hydraulic fracturing essential.

Some of the major drilling challenges that affected drilling efficiency were unacceptably low penetration rates, premature bit damage, high torque, and drag. Engineers determined that drillstring buckling, bit whirl, and stick-slip were resulting in inefficient transfer of weight on bit, premature bit damage and reduced ROP. To overcome this challenge, BHA and drill string modeling were used to eliminate buckling and improve transfer of weight to the bit. Additionally, advanced directional drilling technologies were implemented that significantly improved drilling performance.

Planning the hydraulic fracturing program requires a precise evaluation of the bedding planes and fracture sets, both natural and induced. In the past, resistivity imaging tools were run on wireline to acquire this information. To obtain this information in horizontal wells, logging while drilling (LWD) tools were tried. The initial runs generated images of low resolution, and as a result, the rate of penetration had to be controlled to improve the image quality. To overcome this challenge, state-of-the art LWD tools were developed to acquire high-resolution resistivity images while drilling, and at twice the rate of penetration previously possible.

This strategy has been implemented to drill several wells in the Barnett Shale with excellent results. BHA and drill string modeling, coupled with advanced LWD and directional drilling tools, have significantly improved drilling performance. The rotating hours have reduced from 330 to 165 hours per well. A 48.39% reduction in days required (31.2 to 16.1 days per well) from spud to rig release has been realized.
Acid Fracturing of Gas Wells Using an Acid Precursor in the Form of Solid Beads: Lessons Learned From First Field Application
Authors: Nasr-El-Din H. A. , Al-Zahrani A. A. , Garzon F. O. , Giraldo C. A. F. , Al-Hakami I. M. , Al-Marri H. M.
Published: December 2007

Acid fracturing treatments are commonly used to enhance the productivity of carbonate formations with low permeability zones. Various forms of HCl acid are used to create deep etched fractures. However, HCl reacts very fast with the carbonate rocks and unless retarded, will produce a fracture with low conductivity. In addition, concentrated HCl-based acids are very corrosive to well tubulars, especially at high temperatures. To address problems associated with concentrated acids, various retarded acids were introduced. Organic acids were also used in some cases. These acid systems were successfully used to acid fracture several wells in a deep gas reservoir in Saudi Arabia. Field data, however, indicated that there is a need to create deeper and more conductive fractures. To achieve this goal, it was decided to conduct a field trial with a newly developed acid system.

The new acid system is an ester of an organic acid in the form of solid beads. The ester reacts with water (hydrolyzes) at bottom temperature and produces an organic acid. The organic acid then reacts with carbonate minerals and etches the surface of the fracture. The system was thoroughly examined in the lab and showed promising results.

The treatment was conducted in the field without encountering operational problems. After successful placement of the solids in the fracture, the well was shut-in for 24 hours to give ample time for the ester to hydrolyze and for the generated acid to react with the formation rock. The well was allowed to flow and samples of the fluids produced were collected to understand chemical reactions that occurred during the treatment. The treatment has resulted in a slight increase in gas production. And as a result, the well was matrix acidized using 28 wt% HCl and responded very well to the matrix treatment.

This paper will discuss major reactions that occurred during this treatment, and how they impacted well response. Lessons learned and recommendations to improve the results of this new acid system will be discussed in detail.
The First Offshore Use of an Ultrahigh-Speed Drillstring Telemetry Network Involving a Full LWD Logging Suite and Rotary-Steerable Drilling System
Authors: Wolter H. , Gjerding K. , Reeves M. , Hernandez M. , Macpherson J. , Heisig G. , Zaeper Ralf
Published: December 2007

Drill string telemetry network technology allowing reliable data transmission at speeds up to 57,600 bits per second has been utilized in many land based drilling applications.

The drill string telemetry network incorporates a high-strength data cable that runs the length of each tubular joint. The cable terminates at inductive coils that are installed in the secondary torque shoulder of each connection. As the drill string is assembled, the inductive coils in adjoining tubulars are brought close together allowing data to flow across the connection. The network signal is boosted occasionally by repeater subs, which also provide locations for along-string temperature measurements. The technology offers robust, reliable operation and is virtually transparent to standard rig procedures.

In 2007, the Troll field in Norway saw the first commercial deployment of this technology into a complex offshore multilateral drilling project.

This paper details the lessons learned and value derived from the use of an ultra-high speed drill string telemetry network and compatible rotary steering, drilling dynamics and advanced formation evaluation measurement tools while drilling multiple laterals of an extended reach horizontal well from a semi-submersible drilling rig.

Of particular focus will be discussion of the specific value gained from: real-time analysis of high resolution dynamics and inclination measurements to instantly manage the drilling transition between relatively unconsolidated sands with imbedded hard calcite-cemented stringers; instantaneous network-enabled surface control of rotary steerable tools to eliminate non-productive time and improve directional control; real-time transmission and interpretation of high-volume, memory quality formation evaluation measurements to improve geological well placement; and non-productive time elimination resulting from the availability of full telemetry redundancy.

The paper includes comment and perspective from the Troll field operator regarding the immediate value and likely future utilization of telemetry drill string technology.
Use of Spoolable Reinforced Composite (SRC) Pipe for Transfer of Low Pressure Oil & Gas in BP Pakistan
Authors: Khan Asad Ali. , Naeem Muhammad , Asif Muhammad
Published: December 2007

BP Pakistan has been laying cross-country pipelines to produce oil and gas in the Badin concession for the last 20 years, and has gained considerable experience with conventional carbon steel material. The average time required to lay a 4" diameter × 5000 ft long steel pipeline has been around 4 weeks. There was a desire to reduce this time to improve put-on-production (POP) time. Other factors driving us to think out of the box were corrosion, high operating and life cycle cost etc.

A project consisting of laying 4"-1500 psig × 5000 ft Spoolable Reinforced Composite (SRC) pipeline from wellhead to facility was initiated in consultation with BP Exploration & Production Technology Group (EPTG). EPTG was actively involved in the development of this new technology in the wider BP world, and this was seen as an opportunity to test the material in Pakistan. Testing of the material for potential use in high-pressure (HP) gas was also envisaged. In order to ensure rigorous testing of new material and technology, one of the toughest construction location (high water table, collapsing trench, three major crossings, a number of minor crossings, etc.) was selected. Since most of the potential risks to delivery were evaluated upfront, the result was a record laying time of 0.5 km / hr. The project was completed with great success and learnings for the use of this technology in future, and to share with others who choose to use the same material and technology.

This paper provides a brief overview of this new material, its physical properties, potential use, characteristics, advantages over conventional carbon steel and installation experience at BP Pakistan and recommendations for future utilization in oil and gas industry.
Investigation of Methods to Improve Utica Shale Hydraulic Fracturing in the Appalachian Basin
Authors: Paktinat J. , Pinkhouse J. A. , Fontaine J. , Lash G. G. , Penny G. S.
Published: December 2007

The primary purpose of stimulating fractured shale reservoirs is the extension of the drainage radius via creation of a long fracture sand pack that interconnects with natural fractures thereby establishing a flow channel network to the wellbore. However, there is limited understanding of a successful method capable of stimulating Utica Shale reservoirs. Indeed, most attempts to date have yielded undesirable results. This could be due to several factors, including formation composition, entry pressure, and premature pad fluid leak-off. Furthermore, stimulation of Utica shale reservoirs with acid alone has not been successful. This treatment method leads to a fracture length and drainage radius less than expected resulting in poor well productivity.

In this work, geological data is first examined for the reservoir. Laboratory data are then presented to address the unique mineralogy and mechanical properties of the Utica shale. The high percentage of acid soluble carbonate and dolomite suggests an acid treatment to lower entry pressures. This treatment can be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, potential for scale generation and the prevalent problem of recovery of injected fluids. Acid solubility is presented vs. time and acid strength. Conductivity data is presented for gas fracs, matrix acidizing and proppant fracturing of the shale. The adsorption, as well as the regained relative permeability to gas is examined vs surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative permeability to gas. Information obtained from this study can be used to optimize fracturing treatments of Utica shale reservoirs in the Appalachian Basin.
Accurate Calculation of Hydrocarbon Saturation Based on Log-Data in Complex Carbonate Reservoirs in the Middle-East
Authors: Obeida T. A. , Al-Jenaibi F. , Rassas S. , Serag Eldin S.
Published: December 2007

Generating saturation functions (capillary pressure or J-functions), to initialize complex carbonate reservoir, always presents challenge to Petrophysicists and reservoir engineers, especially with no SCAL data available or any existing rock properties trends such as porosity-permeability relationship which are used to assign saturation function in 3D models. The proposed method requires initial water saturation (Swi) distribution in 3D model in hand (first stage) and then the Swi distribution recalculated more accurately (second stage) using group of capillary pressure (Pc) curves based on Swi intervals. Calculating Swi distribution in two stages should not impose any limitations since in the first stage Swi distribution can be estimated by many ways such as J-functions (4), group of Pc curves based on porosity intervals (part of this work). Otherwise, it may be estimated by any girding software which uses Swi log-data, but this method is not recommended since the software would give erroneous estimation of Swi in the areas of no well control such as in the transition zone area.

The proposed method calculates the Swi distribution in two stages, first the Swi calculated by Pc curves based on porosity rages, then in the second stage the Swi recalculated using group of Pcs based on water saturation ranges.

A script file was written to differentiate between these regions and assign saturation numbers (SATNUMs) for each saturation region which used in the simulator to initialize the dynamic model. Shuaiba reservoir is presented as study case here to demonstrate the capability of the proposed method. The proposed procedure can be to initialize huge complex carbonate reservoir such as Shuaiba formation in the United Arab Emirates.

The initial water saturation profile from log data matched the water saturation calculated by the dynamic model in 90% of the wells (more than 100 wells at initial water saturation).

The proposed procedure eliminates the tedious efforts to find rock property trends such as porosity-permeability correlations, which in many carbonate reservoirs may not exit, in order to assign a saturation function for each porosity/permeability range(s).

The difference in initial oil in place (STOOIP) calculations between the static model (40 million cells) and the dynamic model (2.7 million cells) is less than 2 percent. It can be used also in many heterogeneous reservoirs to reduce the uncertainty in STOOIP and thus reserves estimations.
The Evolution of Automation in Drilling
Authors: Eustes Alfred W.
Published: December 2007

This paper has been written for the keynote speech to be given in the "Drilling Automation – Where Are The Game Changers?" plenary session for the 2007 SPE Annual Technical Conference and Exhibition in Anaheim, California. The paper covers the evolution of drilling mechanization and automation from the mid-nineteenth century to today. In the history of drilling, there have many aspects of drilling mechanization and automation that have been investigated, machines designed and built, and operations implemented with varying levels of success and many failures. These aspects include drilling fluid systems, cementing operations, downhole automation, and the rig floor. Because drilling mechanization and automation history has been centered on the rig floor and related surface operations, the focus of this paper is on the rig floor for drilling operations such as rate of penetration, rotary systems, rig floor mechanization and automation, and entire drilling rig automation.
Viscoelastic Surfactants: A New Horizon in Fracturing Fluids for Pennsylvania
Authors: Leitzell Jeffrey R.
Published: December 2007

The Upper Devonian play within Pennsylvania has been the predominant focus of most operators for many years. These sandstone and siltstone formations are regularly hydraulically fractured with a variety of fluids ranging from high concentration crosslinks, linear gels, polyacrylamide slick waters and even treated fresh water. These fluids, although economical, lack quality and can cause severe damage during the stimulation process. Whether it is leaving behind heavy residual damage or not supplying enough viscosity to carry proppant deep into the created fracture, these fluids do not offer the advantages of an all-inclusive system.

Recently, with the development of visco-elastic surfactants (VES's), a standalone, total package fluid is available at an economical cost. VES's offer high quality with no polymers, giving us a completely clean fluid without residual damage. They can be designed to supply a wide range of viscosities with excellent carrying properties to help ensure optimal proppant placement. With the fluid being surfactant based it is a good foaming agent, which provides exceptional water recovery and strong flowbacks.

Best of all, these fluids are all-inclusive, removing the need for additional additives. It consists of one on-the-fly additive that is compatible with extremely poor quality water that may have been reused. There is no need for additional clay controls, biocides, surfactants or iron controls, but in extreme cases, their additions do not create any compatibility issues. This allows VES's to deliver a high quality system at a competitive price.

This paper will take an in depth look at visco-elastic surfactants and their current applications in the Upper Devonian throughout Pennsylvania. It will highlight the treatment design, operational execution and production results from a variety of wells during the initial application of VES fluids.
Type Curve-Based Production Prediction Tool for CBM Prospects
Authors: Aminian K. , Ameri S. , Bhavsar Bhavsar
Published: December 2007

The complex nature of gas production from CBM reservoirs requires significantly more reservoir properties than conventional reservoirs. Parametric studies are often conducted to evaluate the impact of the reservoir parameters on recovery factor, well performance, and future revenues. To conduct parametric studies, the production behavior must be predicted for ranges of various reservoir parameters. In order to incorporate the unique flow and storage characteristics of CBM reservoirs, it necessary to utilize complicated and expensive reservoir models to predict production performance of the CBM reservoirs. Therefore, a simple yet reliable tool is needed for predicting production behavior of CBM reservoir. The CBM Production Predication Tool developed in this study is a quick and reliable tool that can assist the typical gas producers in evaluation of CBM prospects. The tool utilizes the previously developed CBM Production Type Curves as a foundation to predict the production performance. The results can be used to evaluate the economic feasibility and to maximize potential recovery. To simplify the application of type curves for parametric studies a software package with a graphical user interface using Visual Basic programming language has been developed. The input requirements are simple and straight forward. The output is provided both in graphical and tabulated forms which can be exported into spreadsheet for further analysis by the user.
A Simple and Reliable Method for Gas Well Deliverability Determination
Authors: Aminian K. , Ameri S. , Yussefabad A. G.
Published: December 2007

Multi-rate tests generally provide accurate values for gas reservoir formation parameters and deliverability equation coefficients. This type of results enables the engineer to make proper decisions on whether remedial work is required and the potential improvement that can be achieved. The multi-rate tests, such as isochronal or modified isochronal tests, are however cumbersome to conduct due to need for achieving stabilization or lengthy shut-in periods.

The goal of this study has been to develop a simple and reliable method for gas well deliverability determination based on a single rate build-up or fall-off test. Traditionally, single rate tests have been analyzed using empirical backpressure equation using an average value for the exponent (n). Such approximations often provide inaccurate results and do not reveal any information regarding the conditions of the well. Alternatively, single rate tests can be analyzed using theoretical transient gas flow solutions. However, to accurately estimate mechanical skin factor and the deliverability equation coefficients from a single rate test, turbulence factor, β, must be available. There are numerous correlations in the literature for estimating β. These correlations do not provide unique results and calculated skin factor can range widely as a result.

This study introduces the concept of the reservoir-specific β-factor. The methodology for developing a correlation for β factor using multi-rate tests has been developed. Once the β-factor correlation for a reservoir is established, there would be no need for additional multi-rate tests and single rate can be analyzed to provide accurate estimates of mechanical skin factor and deliverability equation coefficients. The accuracy of the proposed methodology has been verified through application in two separate reservoirs in the Appalachian Basin.
Improved Fracturing Technology for Coalbed Methane Gas Wells in Western Pennsylvania Increases Gas Production Over Offset and Historic Wells in Mount Pleasant CBM Field
Authors: Snyder S. G. , Jockel D. W. , Lopez A. W.
Published: December 2007

Coalbed methane (CBM) drilling has been occurring in the Mount Pleasant, Westmoreland County, Pennsylvania area for about a decade, with various fracturing techniques applied in these CBM wells using conventional gas well fracture methods. However, production has been response-limited either due to incomplete placement of fracturing designs and/or because these older conventional gas well fracturing designs were not effective for these CBM wells.

Due to the poor nature of the production in these coal seams, it was determined to look more closely at the fracturing techniques and apply newer technologies designed specifically for CBM well fracturing. The objective of this review was to make future drilling of the CBM wells in this area economically feasible. This paper will discuss specifics of the coalbed field, fracture designs applied in the past and in the present, fracturing job design considerations, and chemical attributes for the fracturing job.

Most of the historic fracs placed on these wells used a linear gel guar system, low sand concentrations, low sand volumes, larger proppant size, and relied on high pump rates to put the sand away. More recent frac designs were developed to utilize a hybrid crosslinked fluid system, higher sand concentrations, higher sand volumes, and a lower pump rate. Also, chemicals designed more specifically for CBM wells are included in the redesigned test wells.

Finally, we will discuss gas production with the historic fractures that were placed on these wells in the past along with several current wells in the field that used a different design. We will then compare the gas production from these data sets to the gas production for the wells in the field that were fractured by applying the new fracturing technologies. By comparison of the data sets, this paper will demonstrate that the new fracturing technologies applied to this CBM field have resulted in significantly improved gas production for the perator.