bluuebunny/crossref_metadata_2025_split huggingface dataset:
Africa's First Dual Horizontal / Dual Completion Multilateral Well
Authors: Aloko J. A. ‘Ayo’ , Fischer Stephen P. , Osselburn Jeff , Lee Dean 
Published: December 2007

Abstract
In April 1997, TOPCON, a joint venture of Texaco, Chevron and the Nigerian National Petroleum Corporation (NNPC), spudded the well Funiwa-43ML, offshore Nigeria. This multilateral well, with a level 5 junction, was drilled as a dual horizontal oil producer targeting an 11-foot thick oil column between gas and active water layers in an unconsolidated sandstone reservoir. The opposing laterals were 3052′ and 2242′ long horizontal sections respectively, within a ± 2-foot target window and were completed with 7″ slotted liner completions. Since the wellbore trajectories penetrated the reservoir's gas-cap prior to landing the well in the target oil column, the casing in the build sections was cemented to provide hydraulic isolation.
The junction in the main bore, from which the 2nd lateral was drilled, was created by milling a window in the casing with a drilling whipstock. This drilling whipstock was then replaced with a guidestock prior to running and cementing the 7″ liner in the 2nd lateral. The portion of the 7″ liner that extended back into the main bore was then washed over and retrieved along with the guidestock. This resulted in a full bore, full access junction providing mechanical support at the junction.
Completion equipment was then installed to hydraulically isolate the junction. This was achieved by running single string production packers below the junction in each lateral. Separate tubing strings were then tied-back, through the junction, to a dual string production packer above the junction. This resulted in the level 5 junction, ie.; a junction with mechanical and pressure integrity. The well was then completed as a dual string completion to surface.
This paper will describe the drilling and completion aspects of this project highlighting the construction of the junction thus allowing the well to be completed as a dual horizontal, dual completion multilateral well.
Extended-Reach Drilling -- What is the Limit?
Authors: Mason C.J. , Judzis A. 
Published: December 2007

Abstract
British Petroleum has continuously been at the forefront of ERD (Extended-Reach Drilling) achievements, with its operations at Wytch Farm in Southern England, Pompano in the Gulf of Mexico, numerous fields in the North Sea and the Niakuk and Milne Point developments off the North Slope in Alaska. In order to access reserves and extend the life of mature fields, a strong demand for cost effective ERD has now materialised. As the ERD envelope has rapidly evolved during the 1990s, many operators are now reassessing field opportunities previously considered uneconomic, when an onerous capital investment in new equipment was necessary.
A now common question is "Using ERD, how far can we drill using an existing rig and what is the impact of upgrading various rig components?" This paper attempts to address this question by exploring a number of recent case studies where offset field data and advanced analysis techniques are utilised. Increased emphasis is being placed on data collection and analysis, both of which are necessary in understanding critical ERD operations. With this improved learning, predicting future performance in higher step-out wells is more manageable.
For future ERD campaigns it has been determined that drilling hole is not necessarily the most limiting operation in significantly extending reach. The "drilling" constraint that is now emerging is more often associated with excessive drag levels when running long casing strings or sliding drilling in high angle, high step-out wells. Most of this recent experience relates to shallow reservoirs where the highest step-out wells have been drilled. This however is where the most productive engineering advances have been made.
The paper will also provide a vision of the future and highlight areas where technological breakthroughs will be required in order to drill and complete ultra-reach ERD wells of the future.
P. 87
Extended Reach Drilling at the Uttermost Part of the Earth
Authors: Naegel M. , Pradie E. , Beffa K. , Ricaud J. , Delahaye T. 
Published: December 2007

Abstract
The paper presents the recent development of marginal oil and gas accumulations in the vicinity of the offshore Hidra field, by Total Austral operator and partners Deminex and Pan American Energy.
Lying 12 km off the Coast of Tierra del Fuego in 35 m of water, the Hidra field was originally developed in 1989-1990 with conventional deviated wells drilled from two wellhead platforms, Hidra Centro and Hidra Norte. In 1996, three ER wells were drilled with a jack-up from these platforms to tap the Ara Sur and Hidra Sur accumulations. Although technical difficulties had to be overcome, the project was successfully completed. The first well (HNP-7) reached a horizontal departure of 6.2 km at 1700 m TVD representing more than twice the reach of previous conventional wells. This experience established the feasibility and cost effectiveness of ER wells, as a means of developing marginal oil deposits.
Total and its partners decided to launch a second, more ambitious campaign in 1997, in which 9 ER wells were planned to be drilled, this time from the coastline. By May 1998, after a year of operations, 5 wells had been completed including the new American Continent record ER well, AS-3. Drilled late 1997 to a maximum departure of 7973m at a vertical depth of 1615 m, giving a HD/TVD ratio of 4.9, AS-3 was drilled and completed in 90 days. This technical achievement was the reward of intense engineering preparation, proactive attitude on the part of the project team and multidisciplinary teamwork and efficient risk management.
The engineering preparatory studies are described, together with the rig mobilization, modifications and drilling operations highlights. A primary consideration of this project is protection of the unspoiled environment at the drilling site. The utter remoteness of the location has added a significant degree of difficulty to an already challenging task.
An effort has been made with the mud logging company to improve the monitoring of hole condition, especially during the critical 12 1/4" phase, which reached 6700 m in length, at 80-85 inclination, using a device which measures in real time the total amount of cuttings flowing at the shale shakers. This data is combined with Pressure While Drilling data to further estimate hole cleaning efficiency and ECD. To overcome friction, the 9 5/8" casing of well AS-3 was run to 7720 m MD in flotation, requiring careful engineering and unconventional procedures and equipment.
Landing into and drilling through the Springhill reservoir which is only 10 to 20 m thick and can exist locally in lenses, requires delicate geosteering techniques. This paper lists the main challenges that had to be overcome and the techniques employed. An economic comparison with other more conventional development schemes is outlined.
The results achieved so far open the way to more ambitious targets which are presently under evaluation.
P. 99
Design, Implementation and Simulation Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas at Prudhoe Bay
Authors: Cockin A.P. , Malcolm L.T. , McGuire P.L. , Giordano R.M. , Sitz C.D. 
Published: December 2007

Abstract
In 1990 a single well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective water flood and miscible gas flood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon miscible gas. This paper describes how the usual SWCT design was modified to accommodate the miscible gas, the results of the SWCT, which for the miscible gas part were significantly higher than miscible gas coreflood residuals, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper explains, with simulation support, what caused the measured residuals to be higher than expected, and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to gas flooding.
P. 61
Net Pay Determination for Primary and Waterflood Depletion Mechanisms
Authors: Cobb W. M. , Marek F. J. 
Published: December 2007

Abstract
Net pay, as represented by thickness (h), is one of the most important parameters used in volumetric estimates of in-place hydrocarbons, well test interpretations, fluid injection analysis (water, gas, or enhanced recovery methods), reservoir engineering studies, or unitization procedures. Unfortunately, the petroleum engineering and geological literature provides very limited insight into how net pay should be computed. For a porous interval to be counted as net pay, the interval must contain hydrocarbons, be reasonably permeable, and for waterfloods, be laterally continuous from injector to producer. The issue is what portion of this interval can be produced to yield meaningful quantities of hydrocarbons under the particular drive mechanism.
Frequently, a permeability cutoff is selected and net pay is defined as being that part of the reservoir interval possessing permeability greater than the cutoff value. Due to the lack of core permeability measurements throughout all wells, the permeability cutoff cannot be directly used everywhere to differentiate between pay and nonpay rock. Consequently, net pay determination procedures usually relate the permeability cutoff to a log porosity cutoff. The resulting porosity cutoff, often coupled with a gamma-ray or other log cutoffs, is applied to available well log data to determine net pay on a well by well basis. It should be recognized that unless certain guidelines are followed, the porosity cutoff can result in very misleading net pay values because there is often not a strong direct relationship between permeability and porosity.
This paper provides insight into the selection of the appropriate permeability cutoff to compute accurate porosity and other log cutoff values. Results indicate that the permeability cutoff for a particular reservoir is dependent on a number of variables including (1) fluid viscosity, (2) permeability distribution, (3) reservoir pressure differentials, and (4) reservoir drive mechanism (primary or waterflood).
This paper provides guidelines for computing permeability cutoffs in primary and secondary recovery projects and defining those intervals which can be anticipated to be productive under various development scenarios. Also, improved techniques for converting permeability cutoffs to porosity cutoffs are discussed. Example calculations of permeability cutoffs for net pay determination in two waterflood projects are presented.
A General Linear Material Balance Method for Normally and Abnormally Pressured Petroleum Reservoirs
Authors: Wang Shie-Way 
Published: December 2007

Abstract
This work presents a generalized straight line, material balance method to determine the initial fluid in place of a petroleum reservoir without restrictions on fluid composition, pressure gradient, water influx, or constant pore volume assumption. All preexisting methods are applicable to either restricted ranges of reservoir fluids or reservoirs of normal pressure gradient. This work extends the method presented by Walsh in handling compositional effects of fluid composition for constant pore volume reservoirs to include the effects of abnormal pressure gradients and expansion of formation water. This method can be shown to degenerate to preexisting methods under appropriate reservoir conditions. New examples are given to illustrate how to apply this method to over-pressured gas condensate reservoirs, and detection of water influx. The significance of this work is that it provides a unified formulation of material balance calculation, which can be applied to determine the initial fluid in place for oil and gas reservoirs with (1) compositional or non-compositional effects, (2) volumetric or non-volumetric conditions, (3) normal or abnormal pressure gradients, or (4) a combination of all of these. All previously published works become subsets of the present method.
P. 101
Drilling Fluids Filtration and Permeability Impairment: Performance Evaluation of Various Mud Formulations
Authors: Longeron D.G. , Alfenore J. , Poux-Guillaume G. 
Published: December 2007

Abstract
This paper describes the results of a three-year programme achieved in a Joint Industry Project aiming at evaluating formation damage arising from overbalanced drilling and completion operations.
Eight typical drilling fluid formulations, including water-based and invert synthetic oil-based muds have been used to perform static and dynamic filtration tests on outcrop sandstone core samples. The performance of each mud formulation has been quantified from continuous monitoring of fluid losses during mud invasion and from return permeability measurements after mud exposure. The impact of various parameters on permeability impairment, such as initial core permeability, fluid saturations (oil or gas), temperature and shear rate has been evaluated.
Results show that fluid losses and permeability impairments obtained with water-based muds are significantly greater than those observed with invert oil- based muds. Return permeabilities measured on six sections of long core samples. at increasing distances from the inlet face, showed a dramatic near-wellbore permeability reduction due to the invasion of filtrate generated from water-based muds. On the contrary, a stimulating effect, i.e. oil return permeability greater than initial oil permeability, was observed after invasion of filtrate from invert synthetic oil-based muds. This was attributed to a favorable relative permeability effect due to a reduction of connate water saturation during mud filtrate invasion.
The use of a heavy brine as completion fluid has generated a significant additional permeability impairment due to the trapping of the wetting phase. inducing an adverse relative permeability effect.
P. 237
Uncertainty Analysis in Predictive Reservoir Simulation Using Gradient Information
Authors: Lepine O.J. , Bissell R.C. , Aanonsen S.I. , Pallister I. , Barker J.W. 
Published: December 2007

Abstract
We demonstrate how gradient-based techniques can be used to estimate uncertainty in predictive reservoir simulations made following history-matching. We discuss how the gradient calculations can help in finding the parameters that make the largest contributions to the uncertainty, estimating the uncertainty on these parameters, and estimating the uncertainty in predicted quantities by use of a linear analysis. The methodology is illustrated on two field examples, and compared with other methods of uncertainty quantification.
P. 141
Integrating Dynamic Data Into High-Resolution Reservoir Models Using Streamline-Based Analytic Sensitivity Coefficients
Authors: Vasco D.W. , Yoon S. , Datta-Gupta A. 
Published: December 2007

Abstract
One of the outstanding challenges in reservoir characterization is to build high resolution reservoir models that satisfy static as well as dynamic data. However, integration of dynamic data typically requires the solution of an inverse problem that can be computationally intensive and becomes practically infeasible for fine-scale reservoir models. A critical issue here is computation of sensitivity coefficients, the derivatives of dynamic production history with respect to model parameters such as permeability and porosity.
We propose a new analytic technique that has several advantages over existing approaches. First, the method utilizes an extremely efficient three-dimensional multiphase streamline simulator as a forward model. Second, the parameter sensitivities are formulated in terms of one- dimensional integrals of analytic functions along the streamlines. Thus, the computation of sensitivities for all model parameters requires only a single simulation run to construct the velocity field and generate the streamlines. The integration of dynamic data is then performed using a two-step iterative inversion that involves (i) 'lining-up' the break through times at the producing wells and then (ii) matching the production history. Our approach follows from an analogy between streamlines and ray tracing in seismology. The inverse method is analogous to seismic waveform inversion and thus, allows us to utilize efficient methods from geophysical imaging.
The feasibility of our proposed approach for large-scale field applications has been demonstrated by integrating production response directly into three dimensional reservoir models consisting of 31500 grid blocks in less than 3 hours in a Silicon Graphics without any artificial reduction of parameter space, for example, through the use of 'pilot points'. Use of 'pilot points' will allow us to substantially increase the model size without any significant increase in computation time.
P. 189
Successful Application of a Novel Fracturing Fluid in the Wasatch Formation in Eastern
Authors: Dawson Jeff C. , Le Hoang V. , Cramer Dave 
Published: December 2007

Abstract
Hydraulic fracturing of wells drilled in the Wasatch formation is a viable method of enhancing productivity. The Wasatch is a low porosity and low permeability, gas producing formation. It was deposited during the lower Tertiary period in eastern Utah and is composed of a fluvial sandstone and shale. This formation is routinely fractured as a completion method and generally requires crosslinked fracturing fluids that are not excessively viscous but are able to carry moderate to high amounts of proppant. As with most fracturing treatments, fracture clean-up and high conductivity are essential.
A novel fracturing fluid, utilizing ultra low polymer loadings was successfully applied to this formation. This fracturing fluid is based on polymer loadings ranging from 12 to 25 ppt (1.47 to 3.06 kg/m3) with the 25 ppt (3.06 kg/m3) reserved for temperatures ranging from 200 to 250 F (93 to 121 C). Most treatments under 200 F (93 C) utilize 15 ppt (1.83 kg/m3) of polymer. The fluid viscosity is enhanced by crosslinking the polymer with a metal based crosslinker. This fluid is ideally suited for the Wasatch formation because the viscosity development is restricted to about 400 cP at 100 sec. The limited viscosity allows the treatments to generate lengthy, thin fractures rather than short, thick fractures associated with borate based gels. Although the viscosity is relatively low, the proppant suspension characteristics are ideally suited to carry relatively high amounts of proppant. Most treatments have carried six to eight pounds per gallon with the highest loading being twelve pounds.
The fluid also causes minimal impairment to the sand pack. Most fracture conductivity enhancement has been traditionally directed toward improving the breakers. Although the breakers are able to efficiently degrade the polymer's molecular weight thus reducing the fluid viscosity, the fracture still contains an equivalent weight of polymer as the fragments that impair the conductivity and clean-up. The new fluid, having ultra low polymer loadings, together with today's efficient breakers, is able to clean-up better and minimize sand pack impairment caused by the degraded polymer fragments.
Case histories using the fluid, including quality control measures and problems, in the Wasatch formation will be presented.
P. 275
Qualifying Hydraulic Fracturing Effectiveness in Tight, Naturally Fractured Reservoirs by Combining Three-Dimensional Fracturing and Reservoir Simulators
Authors: Johnson Raymond L. , Dunn Kevin P. , Bastian Peter A. , Hopkins Chris W. , Conway Michael W. 
Published: December 2007

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

Abstract
Formation fines are ubiquitous in oil- and gas-bearing sandstones. Formation damage resulting from dispersion and migration of fines is a major concern in producing wells. These fines are mineralogically diverse and become a problem when they detach from pore walls, migrate with flowing fluids and choke off pore throats. The formation damage resulting from fines migration causes a reduction in well performance. A treatment that will inhibit the migration of fines will improve long-term well production. This paper presents the results of a laboratory evaluation and field case histories of fines control treatments in sandstone.
P. 461
Case History: Gullfaks C-36AT3, A Multipurpose Oil-Production Gas-Injection Well in the North Sea
Authors: Austigard Arild , Erichsen Leif , Vikra Stale 
Published: December 2007

Abstract
Statoil has recently drilled and completed a multipurpose oil production/gas injection well on the Gullfaks field. The well was drilled from the Gullfaks C platform as well C-36AT3.
The objectives of the well were to produce oil followed by gas injection in three different reservoir segments. Commingled production from the three segments was not feasible. Differences in reserves and production life required sequential production/injection. Accelerating production/injection from one of the segments would increase the wells net present value substantially.
To obtain this, a completion consisting of regular tubing production from the deepest zones, in combination with annulus production from the shallowest zone was selected.
By choosing this completion configuration, the question of an annulus barrier arouse. A new concept for annulus mechanical barrier was developed and installed in the well.
The reservoir section was planned drilled in one section, which meant drilling a 2300 m horizontal section penetrating sands and shales. Maintaining good hole stability as well as keeping the hole clean, thus minimizing the wear on the 13 3/8" casing were of major concern.
The reservoir consisted of unconsolidated rock, and sandcontrol was required. Open hole gravel packs combined with screens in open hole, run as an integrated part of the liner was chosen.
The well is producing independently from both the tubing and the annulus. The well is currently producing at an oil rate of 1385 Sm3/D (8700 bopd) with a water cut of 54%.
P. 505