bluuebunny/crossref_metadata_2025 huggingface dataset:
The Blowout at UPRI Search Klua d-27-J/94-J-8
Authors: Grace R. D. , Bueckert J. D. , Miller M.
Published: December 2007

In December 1999, UPRI and Search Energy combined their resources to drill an exploration well south and west of Fort Nelson, British Colombia. An unusual chain of events combined to result in loss of control and a blowout. Located in an environmentally sensitive area, containing the blowout was a most important priority and a most difficult challenge. The very high flow rate, hydrogen sulfide content, large volume of water and freezing temperatures made work at the well slow and difficult. This paper chronicles the unusual chain of events that preceded the blowout and the equally unusual approach to recovery. The lessons learned at the Klua blowout will be of benefit to the entire industry worldwide.
North Sea Coring Record Attained by Step Change Application Modeling
Authors: Norrie A. G. , Akram S. , Niznik M. R.
Published: December 2007

A North Sea coring record was set by Conoco UK Ltd (CUKL) and service provider Baker Hughes INTEQ (BHI) on 20 January 2001. A 179-ft core was cut and recovered in 6" hole from the Rotliegendes formation in the Southern North Sea.

In-depth operational planning, which included offset core viewing by a multi-discipline well team was undertaken in an effort to identify potential coring hazards. Physical testing of offset cores, rock strength data, and other relevant data sets were used to model the length of core that could be safely cut.

The coring operation was executed with the selected coring assembly and 179 ft of high quality core was recovered. Subsequent testing and analysis was performed on the core, which satisfied all evaluation requirements of the sub surface team. CUKL and BHI have successfully applied these planning techniques on a number of other wells resulting in significant improvements in coring efficiency, recovery and core quality.
Pressured Drilling Riser Design for Ultra-Deepwater
Authors: Zhang Jane , Magne Eric , Morrison Denby , Efthymiou Mike , Leach Colin , Lo King H.
Published: December 2007

This paper focuses on the design considerations of a pressured drilling riser that can be used with a surface BOP in deepwater. One key element to the development and reliable use of surface BOP drilling is this (riser) link between the seabed and the drilling rig.

The pressured drilling riser, unlike a conventional marine drilling riser, is not designed to cover all situations and applications. On the contrary, it is a purpose-built riser designed to suit the requirements of specific drilling application.

This paper outlines the general design process of the surface BOP riser. Discussion of key design issues that are sensitive to ultradeep-deepwater application are included.

The technical aspects of using (disposable) standard casing with threaded connector for the drilling riser are discussed, with a particular emphasis on the connector fatigue-testing program to quantify the stress concentration factor for fatigue design.

Emerging composite material offers some alternatives to the steel riser when drilling in ultra-deep water. Design issues related to the high-pressure composite drilling riser are briefly discussed.
Whipstock Casing Installation Advances Well Construction Process
Authors: Mayfield David , Rodriguez Edgar M. , Nordenstam Erik , Buster Jerry
Published: December 2007

A technological breakthrough in the well construction process was recently accomplished in the deepwater Gulf of Mexico. An 11-3/4" O.D. liner was successfully installed through a whipstock window cut into a 13-5/8" casing. It was the first documented attempt worldwide to run casing larger than 10-3/4" O.D. through a 13-5/8" window.

The job's success can be attributed to thorough planning of well site operations and computer modeling of the proposed installation. The primary components of the planning activity included 1) analysis of available casing exit systems, 2) modeling of the bending and compressive loading on the 11-3/4" liner connections, and 3) detailed modeling of the drag expected during liner running operations both through the whipstock and into the deviated hole to total depth.
Mechanisms Of Mineral Scale Inhibition
Authors: Tomson M. B. , Fu G. , Watson M. A. , Kan A. T.
Published: December 2007

The adsorption and desorption potential of inhibitors to crystal nuclei has never been determined at the extremely low, threshold levels that are known to inhibit nucleation. An extensive study of adsorption and desorption isotherms of four phosphonates on barite or calcite are tested over a wide range of solution conditions (0 – 1 M NaCl, 0 – 0.1 M Ca, 0 – 0.33 M sulfate, 4.6–6.4 pH). From these adsorption/desorption observations, it is proposed that the primary driving force for adsorption is related to simple hydrophobic repulsion from solution of a macro neutral molecule and not, as is generally presumed some specific inhibitor-surface interaction. A single isotherm may be derived from these vastly different adsorbent, adsorbate combinations after the solid phase concentration is normalized to per unit surface area and the solution phase concentration is normalized to the concentration of metal phosphonate concentrations. From the nucleation study, it is observed that the inhibitor needed to completely inhibit barite formation is approximately equal to 16% surface coverage. Equation to predict minimum inhibitor need is proposed based upon this model and compared with field observations. Brine chemistry of a specific well dictates the solution speciation of scale inhibitors and adsorption potential, thereby, that will determine the efficiency of inhibitor. Surprisingly, the range of predicted inhibitor concentrations is quite similar to what is observed in the field as a minimum effective dose, even though it was arrived at by a completely independent method of calculation.
A Surface Sensitive Study of the Influence of Corrosion Inhibitor on Chemical Scale Inhibition
Authors: Wylde Jonathan J. , Allen Geoffrey C. , Collins Ian R.
Published: December 2007

A combination of Laser Raman Spectroscopy, Secondary Ion Mass Spectrometry and Scanning Electron Microscopy has been used to investigate the influence of corrosion inhibitors on the mechanism of scale formation.

In a series of experiments mixed barium and strontium sulphate scales were precipitated onto a steel surface in the separate presence of three generically different scale inhibitors. In each, one of two contemporary corrosion inhibitors was also added and the rate of scale growth monitored. All experiments were performed at a constant temperature, pressure and solution pH of 25°C, 1 ATM and 4.5 respectively.

A significant influence on the rate of scale formation was observed in the presence of corrosion inhibitors. The corrosion inhibitors affected the way in which scale ions, as well as scale inhibitors, attached themselves to the surface. These data indicate the presence of subtle interactions in these multi-component systems which strongly influence the efficiency of individual production chemicals.
Friction Factors for Turbulent Flow of Non-Newtonian Fluids in Coiled Tubing
Authors: Rao Bharath N.
Published: December 2007

The applicability of Newtonian friction factor correlations for predicting friction pressure losses in turbulent coiled tubing (CT) flow of non-Newtonian fluids is investigated. All correlations presented are expressed in a simple and convenient form by separating the contribution of curvature effects of the reel and friction pressure losses in corresponding straight tubing. The primary advantage of separating reel effects from the straight tubing pressure losses is that the form of the friction factor correlation provides more generality and can be extended to both Newtonian and non-Newtonian fluids. Moreover, pipe roughness effects can be easily incorporated if necessary, and a single correlation can be used to predict friction pressure losses in both straight and reeled tubing. The correlations presented are valid for a wide range of generalized Reynolds numbers, and are applicable to most combinations of reel and tubing sizes available today. The results obtained from these proposed correlations are compared with published experimental data and very good agreement is obtained.
Regional Data Analysis to Better Predict Drilling Success: Brushy Canyon Formation, Delaware Basin, New Mexico
Authors: Balch R. S. , Hart D. M. , Weiss W. W. , Broadhead R. F.
Published: December 2007

Incomplete or sparse information introduces a high level of risk for oil exploration and development projects. "Expert" systems developed and used in several disciplines and industries have demonstrated beneficial results in modeling the decision making process of knowledgeable experts. A state-of-the-art exploration "expert" tool using a computerized data base and computer maps generated by neural networks, is being developed using fuzzy logic, a relatively new mathematical treatment of imprecise or non-explicit parameters.

Analysis to date includes generation of regional scale maps of aeromagnetic, gravity, structure, thickness, and production data for the target Brushy Canyon Formation in the Delaware Basin, New Mexico. For each regional scale map, data attributes were also computed to look for more subtle trends. These attributes include directional first and second derivatives, dip azimuth and magnitude, and azimuth and magnitude of curvature. These data were mapped and gridded to a 40 acre spacing, the current well spacing for Delaware pools in New Mexico, and compared to average monthly production in the first year for Delaware Brushy Canyon wells. The geophysical and geologic data covers 60478 bins (3780 square miles), of which 2434 of these bins have oil, gas and water production data. Using a new fuzzy ranking tool each data attribute was ranked for its ability to predict production potential at these well locations. The highest ranked attributes are gravity dip-azimuth, second latitude derivative of thickness, longitude derivative of gravity, and longitude derivative of structure. These attributes are being used to generate a production potential map for the Delaware basin, using neural networks and expert systems, at the scale of 40 acres. Such a map would be a useful tool for evaluating the potential of infill, step out, and wildcat wells in the Delaware basin, both at reservoir and regional scales.
Applicability of Timely Gas Injection in Gas Condensate Fields To Improve Well Productivity
Authors: Marokane D. , Logmo-Ngog A. B. , Sarkar R.
Published: December 2007

Gas-condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottomhole pressure declines below the dew point pressure. To alleviate the problem, pressure maintenance and gas cycling are common practices for developing gas condensate reservoirs.

A study has been conducted to investigate the applicability of one-time produced gas injection in removing the condensate bank around the wellbore and thereby restoring well productivity. The study focused on two major issues: the optimum time of commencing gas injection and the optimum volume that will remove the condensate bank permanently and restore well productivity. The practice will accelerate the production rate per well and maximize the ultimate hydrocarbon recovery.

Three gas-condensate fluid samples with maximum liquid dropout in the range of 6 %, 11 %, and 21 % were used. The benefit of the method was investigated using a full-field compositional reservoir simulation model of a gas condensate field.

Reservoir simulation results indicated that, for the lean gases, the best time of starting the gas injection was when the average reservoir pressure around the producing well fell below the maximum liquid dropout pressures. For the rich gas, however, gas injection starting at average reservoir pressure above the maximum liquid dropout pressure resulted in better recovery.

The study showed that one-time gas injection not only restored the well productivity and increased reserves but also accelerated the recovery process. These findings bring a different perspective to the development and management of gas condensate reservoirs.
A Natural Polymer-Based Crosslinker System for Conformance Gel Systems
Authors: Reddy B. R. , Eoff Larry , Dalrymple E. Dwyann , Black Kathy , Brown David , Rietjens Marcel
Published: December 2007

This paper describes a material derived from natural sources that can be used to crosslink a variety of polymers over a broad temperature range to produce gels for conformance applications.

Delayed crosslinked polymer systems have been used for many years in conformance applications. For the past decade, the most widely used system has been based on chromium (+3) crosslinked polyacrylamide. Organic crosslinkers, such as phenol/formaldehyde and polyethyleneimine (PEI) have also been used with a variety of polymers. However, these systems are being scrutinized by governmental agencies and have been scheduled for phase-out in some countries. Because of these issues, a single, environmentally friendly crosslinker that could be used with a variety of polymers over a broad temperature range was the focus of this study.

This paper details the laboratory development of an environmentally friendly, natural polyamine crosslinker system. This crosslinker can be used with a variety of polymers, such as polyacrylamide, AMPS/acrylamide, or alkylacrylate polymers. Gels ranging from stiff and ringing type to "lipping" gels have been obtained. The data illustrate a simple, commercially available system that can be applied to field operations. Potential crosslinking mechanism(s) of the system will be discussed.
Three-Phase Flow in Wag Processes in Mixed-Wet Porous Media: Pore-Scale Network Simulations and Comparison with Micromodel Experiments
Authors: van Dijke M. I. J. , Sorbie K. S. , Sohrabi M. , Tehrani D. , Danesh A.
Published: December 2007

Water-alternating-gas (WAG) injection is a technique which has been applied successfully in the field for improving oil recovery. However, there is still an incomplete understanding of the pore-scale physics of WAG processes and how these lead to improved oil recovery. This is especially true in systems of non-uniform wettability e.g. mixed-wet rocks. In this paper, we describe the development of a pore-scale network simulator for capillary-dominated three-phase flow in media where the wettability varies from pore to pore. Reduction of phase continuity in weakly wetted pores has required incorporation of double and multiple displacements for mobilisation of disconnected phase clusters. Three-phase flow processes, in particular WAG injection cycles, have been simulated for which the saturation paths are recorded along with the statistics of the corresponding phase pore occupancies and displacement mechanisms. Comparison of the saturation paths obtained in 3-D mixed-wet network simulations shows reasonable agreement with paths for an analytical model, despite the imposed low phase continuity. The WAG cycle simulations show the importance of multiple displacements during higher order WAG floods. Furthermore, using 2-D network simulations we have modelled the WAG floods following primary drainage and initial water flooding in a water-wet micromodel. Good agreement is found between simulation and experiment, in particular with respect to the displacement mechanisms occurring during the WAG cycles.
Three-Phase Hydraulic Conductances in Angular Capillaries
Authors: Al-Futaisi Ahmed , Patzek Tad W.
Published: December 2007

In this paper, we extend to three fluid phases a prior finite-element study of hydraulic conductance of two-phase creeping flow in angular capillaries. Previously, we obtained analytic expressions for the hydraulic conductance of water in corner filaments. Here we present the results of a large numerical study with a high-resolution finite element method that solves the three-phase creeping flow approximation of the Navier-Stokes equation. Using the projection-pursuit regression approach, we provide simple analytic expressions for the hydraulic conductance of an intermediate layer of oil sandwiched between water in the corners of the capillary and gas in the center. Our correlations are derived for the oil layers bounded by the concave or convex interfaces that are rigid or allow perfect slip. Therefore, our correlations are applicable to drainage, spontaneous imbibition, and forced imbibition with maximum feasible hysteresis of each contact angle, oil/water and gas/oil. These correlations should be useful in porenetwork calculations of three-phase relative permeabilities of spreading oils. Finally, we compare our results with the existing correlations by Zhou et al., and Hui & Blunt, who assumed thin-film flow with an effective film thickness proportional to the ratio of the average, our correlations are two-four times closer to the numerical results than the corresponding correlations by Zhou et al., and Hui & Blunt.
Geochemical Modeling of Fracture Filling
Authors: Noh Myeong H. , Lake Larry W.
Published: December 2007

This paper reports on a mathematical model to simulate hydrodynamics and fluid-mineral reactions in the fracture within a permeable media. Fluid convection, diffusion and precipitation / dissolution (PD) reaction inside a finite space are solved as a simplified representation of natural fracture mineralization. The problem involves mass transfer within the fluid accompanied by chemical reaction at the fracture surface. Mass-conservation equations for components in the fluid are solved in this problem, and these are coupled with chemical reaction at the fracture surface. The intent of this model is to show the time evolution of fracture aperture shrinkage patterns caused by PD reactions. We present the aperture distribution along the fracture with various boundary conditions. Partially cemented fractures are created if cementation fails to completely fill the fracture or if subsequent dissolution leaches out some of the mineral.
Stimulation of a Deep Sour Gas Reservoir using Gelled Acid
Authors: Nasr-El-Din H. A. , Al-Mutairi S. H. , Al-Jari M. , Metcalf A. S. , Walters W.
Published: December 2007

Stimulation should always begin with a good understanding of the well history and the reservoir rock. This should include an evaluation of the formation composition and flow characteristics, permeability and porosity, and the mechanical properties of the rock. Determination of the "Key Factors" limiting stimulation success should be identified. The potential treatment fluids and technique should be evaluated for the ability to provide the necessary benefits to overcome these limits.

This paper describes stimulation design and results in a carbonate gas field located in eastern Saudi Arabia. The field produces gas with H2S that varies from 0 to 10 vol%. The Khuff reservoirs, at 11,000 to 12,000 ft, are highly acid soluble carbonates (> 85 wt%) with elevated bottom hole temperatures approaching 275°F and a composition having increasing dolomitization with increasing depth. Acid leak-off control problems result from the presence of natural fractures in the formation. Various retarded acid systems were tested with reservoir rocks. In addition, the issues of corrosion control were considered given the low-carbon steel tubulars downhole (L-80 & C-95) and the H2S. Although the gas is sour, proper design of acid systems eliminates problems of iron sulfide and elemental sulfur precipitation.

Evaluation of cored material showed 15 wt% anhydrite streaks. Kinetics studies conducted using reservoir rock indicated that the reaction rate of the in-situ gelled acid is an order of magnitude lower than that of neat acid. An acceptable corrosion rate on all metals by the acid in the presence of H2S and compatibility of all systems with reservoir fluids were obtained. Wells have been treated using acid fracturing techniques employing viscous fluids without encountering any operational problems. Substantial increases in gas production and flowing wellhead pressures have resulted from these treatments. Analysis of well flow back samples collected following acid fracture treatments was used to assess the effectiveness of the fracture treatments.
Field Application of Glass Bubbles as a Density Reducing Agent in an Oil Base Drilling Fluid for Marginal/Low-Permeability/Low-Pressure Reservoirs
Authors: Blanco J. , Ramirez F. , Mata F. , Ojeda A. , Atencio B.
Published: December 2007

This paper shows the results of a successful application of the addition of hollow glass spheres, also known as glass bubbles, as a density reducing agent in a drilling fluid. In this field application, glass bubbles were used in combination with an oil based drilling fluid (Core-Drill-N). It was corroborated that the fluid-glass bubble mix is stable, homogeneous, and is compatible with conventional mud motors, bits and surface cleaning equipment.. The system has good rheological and filtration control properties and is suitable for drilling low pressure reservoirs, low permeability and pay zones.

During this field application in the well MOT-25B in Venezuela, the density of the base fluid was maintained between 7.1-7.3 ppg (near balance condition) with calcium carbonate as bridging agent.

This technology is an alternative to the use of aerated fluids where the reservoir requires a fluid density between 6.0-7.5 ppg, offering some economical and technical advantages due to the elimination of surface compressing and air injection facilities, and to the simplification of operations required to avoid excessive overbalance during drillpipe trips. Additional potential benefits of this low-density fluid include torque reduction as a result of higher lubricity, higher penetration rates and decreased formation damage due to lower invasion of drilling fluid. Glass bubbles are also an alternative to decrease the density of water based drilling fluids, polymer-based fluids, emulsion systems and brines.

Laboratory tests were also carried out with different concentrations of glass bubbles in order to evaluate potential field substitutes for aerated fluids in wells which might require lower density fluids. Several formulations for the systems mentioned above were developed with the purpose of achieving maximum density reduction without affecting some mud properties. Fluid density as low as 6.0 ppg was obtained from a 100% oil base mud.
Designed Simulation for a Detailed 3D Turbidite Reservoir Model
Authors: Wang Feng , White Christopher D.
Published: December 2007

Intelligent reservoir management requires assessment of risks caused by geologic heterogeneity and examination of alternative development schemes. Numerical simulation is a powerful tool for integrating geologic and development models, but simulation is often too expensive or time-consuming if there are many sensitivities and scenarios to examine. In this paper, response surface methods are used to approximate the relationship between gas recovery responses and reservoir and production parameters. The response models are based on a set of numerical simulations selected using experimental design, which efficiently estimates effects of many factors across a broad range of uncertainty. The three-dimensional reservoir model examined in this study is from an outcrop study of the Permian-age Bell Canyon, which is interpreted as a channel-levee-lobe turbidite system.

Examination of realistic reservoir models is complicated by the large number of factors and by correlations between model factors. Principal component analysis can simplify the modeling process by using the correlations to reduce the dimensionality of the factor space. A large number of reservoir geologic parameters are reduced to a small set of principal components while most of the original geological information is still preserved. The principal component design also spans the scatter-cloud of correlated reservoir factors more efficiently. Based on these principal components and several engineering factors, reservoir simulations are selected using a central composite design. Response surface models relating the simulation responses and the design factors are estimated via linear regression. The validity of the models is verified by reservoir simulation of randomly selected points within the feasible region of geological parameters. Uncertainty analysis, including parameter sensitivity estimation and recovery uncertainty assessment, is done conveniently and inexpensively using response surface models and Monte-Carlo simulations. Quality maps identify optimal well locations within the complex depositional setting documented at Willow Mountain.
Successful Acid Treatments in Horizontal Openholes using Dynamic Diversion and Instant Response Downhole Mixing—An In-Depth Postjob Evaluation
Authors: Surjaatmadja Jim B. , McDaniel B. W. , Cheng Alick , Rispler Keith , Rees Matthew J. , Khallad Abe
Published: December 2007

This paper discusses a relatively new acid-stimulation process that uses dynamic fluid energy to divert flow into a specific fracture point in the well that can initiate and accurately place a hydraulic fracture. These acid-stimulation methods often use two independent fluid streams: the acid phase down the treating string and other liquids or gases down the annulus. The annular fluid may simply serve as a wellbore pressurizing component, or with this process, two different fluids can be mixed downhole with high energy to form a homogenous mixture.

Using variations of this process, treatments were performed in four openhole, horizontal wells in the same formation. The first well was acid-fractured with coiled tubing to place many small fractures along the open hole. The second well was acidfractured with coiled tubing, but downhole mixing concepts were also used to provide in-situ generation of CO2 foam where fewer, but larger, fractures were placed in this well. The third and fourth wells were treated with acid using blasting-type rotating or non-rotating jetting tools while mixing the acid with CO2 downhole. Numerous small, near-wellbore fractures were the expected result in these two wells.

Experimental laboratory investigation of the physical mechanisms that contributed to these successful stimulations was considered important. Large-scale laboratory tests were performed to more closely examine the physical rock response to the jetting mechanism and conditions. The findings of these tests are presented in this paper.
Evaluating Operation Strategies via Integrated Asset Modeling
Authors: Liao Tony Tianlu , Stein Michael H.
Published: December 2007

An integrated asset modeling approach was used to evaluate gas compression and operating strategies for six gas fields in offshore Trinidad. Material balance and well models were linked to a pipeline network model. These IAM models were successfully used to evaluate the benefits of compression and looping of a pipeline segment. The modeling allowed the impact of interference of fields, different sand units within a field, wells, and facility constraints to be quantified. Compression could increase the gas recovery from six Trinidad fields by between 8.8% and 11.7 % of the original gas in place.
Gas-Condensate Well Performance Using Compositional Simulator: A Case Study
Authors: Bengherbia Mourad , Tiab Djebbar
Published: December 2007

The TFT gas-cap field in Algeria produces a lean gas condensate from an Ordovician reservoir. The dewpoint pressure (2619 psi) is approximately the initial reservoir pressure (2683 psi). The pressure reaches the dewpoint within a short production time, and then drops below the dewpoint. This pressure drops causes a loss of productivity, and high condensate saturation builds up near the wellbore could lower gas productivity.

To simulate the depletion process, the Peng-Robinson EOS was developed to characterize the fluid from a well data. A tuned model matched the experimental PVT data like Constant Composition Expansion (CCE), and Constant Volume Depletion (CVD) that are reliable and give a high degree of match results. This is performed by pseudoizing the EOS components from 11 to 7. A splitting method is discussed, and refers to the procedures of dividing the heptanes-plus fraction into hydrocarbon groups with a single carbon number, which are described by the same physical properties used for components.

A compositional simulation is performed to study the behavior of gas condensate fluid, and to show the phenomenon of condensation of liquid in the reservoir when the pressure drops below the dewpoint pressure. Because the compositional computing time increases significantly with the number of component used, the pseudoized fluid components discussed before are used to reduce the computing time.

An agreement between the tuned Peng-Robinson EOS and experimental PVT data leads to a good depletion process for use in production simulation. The simulation model yields high-quality match with the test data, such as the average pressure, gas production, and liquid (condensation), which leads to good performance predictions.

A good understanding of the gas condensate reservoir, when operating above and below the dew-point, and how this reservoir is affected by three zones, the inner, the middle, and the outer, where the pressure drops below the dew-pressure, and the variation of liquid and vapor phases for each component in an other hand.
Evolution of Dolomitic Completion/Stimulation Optimization in Indian Basin Field, Eddy County, New Mexico
Authors: Peavy M. A. , Weaver R. T. , Torres G.
Published: December 2007

This paper will provide a case study of the evolution of the stimulation and completion methods used to redevelop a dolomite formation located in Indian Basin field, New Mexico, USA which commenced in mid-1990 (Fig. 1). The field, discovered in 1963, produces from the Upper Pennsylvanian formation, a fractured, vuggy dolomite located at approximately 7500 ft. with a gross productive interval of 300 ft. Field production has reached an all time high as a result of the utilization of technology in a quest for the optimal completion process during this time. Significant completion/stimulation challenges involved reservoir, environmental and safety, drilling, and production issues. Reservoir concerns involved zone stratification, low bottomhole pressure (400-1200 psi), and high H2S levels (8,000 to 10,000 ppm). Four drilling methods were used over the past seven years, which impacted completion stimulation design. These included water based mud with lost circulation materials, air drilling, dry drilling, and an aphron "at-balance" system. Producing the wells involved a process called "co-production" whereby high rates of water are produced along with gas for sustained time periods.

This study will compare well data on twenty wells drilled by Kerr-McGee where gas productivity ranges from 500 MCFPD to 10,000 MCFPD/well. Well stimulation was one of the most critical components of the development process due to the nature of the rock where significant permeability streaks may dictate the degree of stimulation coverage throughout the zone. Approximately 40 stimulation treatments will be summarized and reviewed to highlight the evolution and success of the stimulation methodologies utilized today. Treatments ranged from small volume straddle packer acid jobs to high rate foamed acid fracturing stimulations.

This paper will provide historical production information comparisons used to shape the stimulation process. Other technologies were utilized during this time to better define an optimized completion process. The impact of core analysis, acid studies utilizing core material, FMI logs, production logs, and post stimulation treatment logs will be addressed in the paper. These technologies all played a role in revealing formation characteristics that led to the current "best practices" utilized by Kerr-McGee in the field.
Acidizing Performance in Hassi R'Mel Field, Algeria
Authors: Meddahi Fateh , Tiab Djebbar
Published: December 2007

Recently, matrix stimulation treatment was used for the first time in the Hassi R'Mel field in Algeria, one of the major gas condensate fields in the world, to increase the production of wells supposed to be producing below their potential, because of damaging events occurring during drilling, completion, and workovers. Acidizing jobs were conducted by three different companies. Three different kinds of mud acid system were used to stimulate a total of thirty-four wells during 1998 to 2000.

In this study, the primary goal is to determine to what extent our predetermined objectives have been reached, and identify the conditions that lead to a greatest response to acidizing. For this purpose, laboratory evaluation was performed to identify formation properties and its response to different acid formulas, used or proposed by service companies. Pre- and post-stimulation engineering data were collected and analyzed. Finally, economic evaluation of each well and for the whole field is performed.

The results of this study show that the reservoir was highly damaged by drilling and workover fluids. All acid formula were found to be effective in removing the damage, however insoluble precipitates capable of blocking pore throats were generated, especially in layer A. This layer of Hassi R'Mel field is described as dirty sand. Field results showed that: (a) layer A did indeed suffer production loss, (b) corrosion problems are severe, (c) chemical diversion proved to be ineffective in acidizing multi-layer wells, (d) damage is not completely removed, and (e) cleanup of wells takes long periods of time. These drawbacks can be reduced if: (a) corrosion inhibitor is used before well flowback, (b) more acid volume is injected, (c) overflush solution volume is three times the volume of main treating fluids, (d) Acid concentration is decreased, and (e) Chemical diversion is used together with mechanical diversion to treat multi-layer wells.
Gas Storage Performance in a Fractured Formation
Authors: Gerov Lubomir G. , Lyomov Shteryo K.
Published: December 2007

This paper presents analysis of the performance of Chiren Underground Gas Storage Field located in Northwest Bulgaria. The storage was built in a depleted gas condensate reservoir. The producing formation comprises of fractured multi layered carbonate and sandstone rocks. The gas field/storage has been object of several controversial studies.

The paper includes analysis of the influence of rock deformations, water drive, and effect of the capillary processes, from the period of gas field to the recent days. In the study, data from the 30 years history period, laboratory data as well as mathematical simulation are used.

The results show significant influence of the heterogeneity of the formation, production injection schedule, and the well spacing. Progressive time dependent gas dis-balance is observed. Evaluation shows that it is in the range of 1/3 the peresent stored gas volume in the reservoir. Well logs prevail good state of the production casing and luck of gas migration in upper formations. Simulation shows that the main reasons for the gas dis-balance and formation of zones with higher pressure as a result of water movements, formation rock deformation and well water cut. The inadequate reservoir management has neglected those factors and it seems it's the main reason for the bad reservoir performance.
Evolution of Completion Practices and Wellbore Geometry: A Sour Gas Carbonate Reservoir in the Wyoming Thrustbelt
Authors: McInnis N. A. , Harting T. A. , Vaitl J. D.
Published: December 2007

Successful redevelopment of the giant Whitney Canyon-Carter Creek field began in 1995, ten years after initial drilling was completed. Keys to this exploitation success were a better technical understanding of the reservoir, the evolution of completion practices and enhanced wellbore geometries. Application of these learnings fueled the infill program, producing an incremental 134 Bcf since 1995, with initial well rates up to 60 MMcf/D.

Pore volume re-interpretation in 1994 identified a potentially large, under-developed resource. Early drilling confirmed this potential. To effectively access these reserves however, historical completion practices had to be redefined, given the reservoir's fluid sensitivity and the need for better stimulation in this low permeability, pressure-depleted system.

Completion optimization focused on acid system design, diversion and debottlenecking. Emulsified acid and CO2-energized fluids increased etched half-length and load recovery. Better zonal isolation was achieved in a progression from bridge plugs to reservoir stresses and sparse perforating. Further, tubulars were upsized to reduce pressure losses due to friction.

Wellbore geometry evolved from vertical to high angle, extended reach wells. These increasingly complex wellbores contacted more reservoir, targeting improved rock quality and the natural fracture system. Each of these factors contributed to improved rate and recovery, but provided many operational challenges.
New Completion Techniques Improve Production Rates in a Maturing Gas Reservoir
Authors: Stromquist Marty L. , Boulton Ken , Pangracs Steve
Published: December 2007

To ensure continued economic success of drilling new wells in maturing gas or oil fields, it is often necessary to find methods to reduce well costs or to improve stimulation efficiency. Imperial Oil Resources applied the emerging technologies of grass-roots coiled tubing drilling and coiled tubing fracturing in the Tilley Milk River Gas Unit. This paper will describe the impact of these new technologies on well economics and production.

In 2000, grass-roots coiled tubing drilling was used on 9 wells in the Tilley field. Drilling costs were 15% below estimates. Coiled tubing fracturing was also applied to the wells drilled in 2000. First year average gas productivity was 50% higher than expectations, leading to investment reappraisals indicating that well reserves were 30% above previous estimates. In 2001 an additional 25 wells were fracture stimulated with coiled tubing also showing increased production rates.
Stimulation Techniques for Low-Permeability Reservoirs with Horizontal Completions that Do Not Have Cemented Casing
Authors: McDaniel B. W. , Willett R. M.
Published: December 2007

Existing literature offers numerous success stories for stimulating cased/cemented horizontal completions in low-permeability reservoirs.1–8 However, operators who are faced with limited producing potential need to reduce well costs. Completing the horizontal section openhole or with a noncemented liner is attractive. In low-permeability reservoirs, production from such completions has often been below expectations, and sometimes even commercially unfeasible. This is especially true when we consider only completions in reservoirs other than fractured chalks.

To achieve proper stimulation with a technique such as fracture acidizing or hydraulic fracturing with proppants, operators must incorporate an economic and effective method for controlling the fluid or proppant placement. Currently, few well-proven technologies exist for controlling fracture placement in noncemented wellbores. In some cases, high risk or very high cost is associated with these technologies, depending on reservoir conditions or the potential for production improvement.

This paper examines several approaches that have been used to solve these problems, and presents some of the reasons for their mechanical and/or economical success or failure.

Generally, the successful use of either conventional fracturingtreatments or waterfracs (with very little or no proppant) will require some method of controlling fracture placement along the horizontal for significant production improvement. Controlling fracture placement is usually also required for effective fracture-acidizing of carbonate formations. Case histories from Canada and west Texas are included, and other examples within the literature are cited.
New Fluid Technology Allows Fracturing Without Internal Breakers
Authors: Weaver J. , Schmelzl E. , Jamieson M. , Schiffner G.
Published: December 2007

A recent development in fracturing fluid technology is the introduction of a unique fracturing fluid that requires no internal breakers. The new system will be referred to as low molecular weight fracturing (LMWF) fluid. Despite very robust and stable rheological properties during pumping, LMWF fluid returns to its original low viscosity shortly after fracture closure. The distinctive properties of this fluid will be presented, along with a discussion of the influence that this system is expected to have on the effectiveness of fracture stimulation treatments. Case history information will also be reviewed and the paper will attempt to explain well performance as it relates to "effective" fracture geometry, and the effect that fracturing fluid properties can have on this important stimulation design parameter.
Acid Stimulation of Sour Wells
Authors: Delorey J. R. , Vician D. N. , Metcalf A. S.
Published: December 2007

Production of Hydrogen Sulfide (H2S) gas in oil and gas wells has increased over the last few years. These sour (H2S Producers) wells have been successfully acid stimulated for many years. Wellbore acid washes, high rate squeeze treatments and acid fracs have been the norm for stimulating wells in carbonate formations. However, to accomplish this there are many problems related to the interaction of the treatment fluids and the H2S. These can result in excessive corrosion, unwanted precipitants, metal cracking, etc.

In recent years, the practice of drilling horizontal wells has led to the technique of underbalanced acid washing. Controlling corrosion, metal fatigue and unwanted precipitants when using this technique in sour formations presents a special challenge. The resulting interaction of the H2S and acid additives, especially corrosion inhibitors has been the primary focus of concern.

This paper describes test equipment and procedures designed to investigate H2S and acid additive interactions. Test results with a range of inhibitors and additives designed to minimize formation damage and protect coiled tubing and tubular steels are provided. Specifically, weight loss, pitting and precipitation products are listed.
Safe and Economic Gas Wells through Cement Design for Life of the Well
Authors: Ravi K. , Bosma M. , Gastebled O.
Published: December 2007

Natural gas is one of the cleaner sources of energy, and our challenge is to produce it safely and economically. The extreme operating conditions that occur in gas-storage and gas-producing wells could cause the cement sheath to fail, resulting in fluid migration through the annulus. Designing cement sheaths that can withstand the stresses induced by the various operations and maintain integrity during the life of the well will help minimize the risk of cement failure.

A design procedure has been developed to estimate the risk of cement failure as a function of cement sheath and formation properties and well-stress loading. A few examples of the loading are cement hydration, pressure testing, gas injection, and gas production. The design procedure simulates the sequence of events from drilling to cement hydration, hydraulic fracturing, injection, production, etc. Cement failure modes simulated are de-bonding, cracking, and plastic deformation. An appropriate nonlinear material model, including cracking and plasticity, is used in the analysis.

The sustained casing pressure observed on a number of wells after they have been put on production emphasizes the need to design a cement sheath that will maintain integrity during the life of the well. Field cases and applications are discussed. From the process discussed in this paper, one can estimate the risk of failure of different cement systems and select the system that can help minimize the overall cost. The process should improve the economics of constructing and producing gas and oil wells and also improve the safety due to the reduced risk of zonal isolation failure.
General Correlation for the Effect of Non-Darcy Flow on Productivity of Fractured Wells
Authors: Settari A. , Bale A. , Bachman R. C. , Floisand V.
Published: December 2007

The paper describes a systematic study of the effect of the turbulence on productivity (or injectivity) of fractured wells. It extends significantly beyond previous work, and shows its limitations.

A new correlation has been developed, based on over 2,000 high-accuracy numerical solutions for vertically fractured well for a simple geometry. The base correlation was developed for fully penetrating fracture and it is applicable to liquid and high-pressure gas systems. The general correlation for fully penetrating fracture is a function of the two dimensionless parameters and two other parameters, which can be chosen as fracture conductivity and permeability. Additional results are provided for the effect of partial perforations on a fully penetrating fracture. As a limiting case, this scenario can represent also transversely fractured horizontal well. The final correlation therefore involves 5 variables.

The results show that the conventional notion that turbulence is important only in high rate gas wells is often false. Turbulence effect on productivity or injectivity can be significant for liquid flow in high permeability formations, with limited perforations and especially in transversely fractured horizontal wells.
Residual gas saturation investigation of a carbonate reservoir from Western Canada
Authors: Ding Minghua , Kantzas Apostolos
Published: December 2007

The value of residual gas saturation to water influx is a key factor for estimating recoverable reserves in gas reservoirs overlaying active aquifers or natural gas storage reservoirs. Most of our previous work investigated the determination of residual gas saturation for sandstone reservoirs with high values of porosity and permeability. However, vast gas resources are trapped in low porosity and permeability carbonate reservoirs. A number of cores from a Western Canada carbonate reservoir were tested as part of an experimental program to determine the residual gas saturation at ambient conditions. Primary and secondary spontaneous imbibition tests were performed on each core plug. Different initial water saturation conditions were used and the obtained results were compared. The centrifuge technique was used to set the initial water saturation. The initial imbibition rate was found to be the key for residual gas saturation. The effects of core plug properties were addressed. Our work also addressed the prediction of field scale recovery by application of simple scale-up laws. Different simple predictive models, which were used to fit sandstone reservoirs successfully, were tested as part of this work. The laboratory experimental results were also compared with log data to predict gas production and gas recovery of reservoir under different matrix block sizes.
Resolving the Completion Engineer's Dilemma: Permanent or Retrievable Packer?
Authors: Triolo M. T. , Anderson L. F. , Smith M. V.
Published: December 2007

Traditionally, completion engineers have faced a dilemma when deciding whether to run a large bore, hydraulic set, permanent, or retrievable packer. Thanks to advances in cutting technology, this decision is no longer an either/or proposition. The innovative alternative is the removable packer.

This paper will address the development of a removable packer that combines the best features of both permanent and retrievable packers: large bore, high performance, simple design, and flexible retrieving options. The paper will trace the development of the technique from stack-up testing to the maiden run and retrieval of the first removable packer in the Milne Point field, Alaska. Through analysis of this case history, the paper will address challenges faced, problems solved and lessons learned that are now being applied to future enhancements of the removable packer technique.