bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predrill Estimation of Subsalt Fracture Gradient: Analysis of the Spa Prospect to Validate Nonlinear Finite Element Stress Analyses
Authors: Fredrich J. T. , Engler B. P. , Smith J. A. , Onyia E. C. , Tolman D. N. 
Published: December 2007

Abstract
Deepwater areas offshore the Gulf of Mexico, Angola, and Brazil contain vast oil and gas deposits that underlie thick salt formations. Drilling wells to recover these resources can be challenging because of extreme water and reservoir depths, adverse environmental conditions, and complex tectonics. In particular, stress changes can occur in the vicinity of salt diapirs that are of sufficient magnitude to affect fracture gradient and wellbore stability, and the vast majority of difficult drilling events associated with salt diapirs in the deepwater Gulf of Mexico are in fact associated with the salt – sediment interface. In prior work, non-linear finite element analyes were used to identify the style and magnitude of near-salt stress changes for several idealized diapir geometries. While providing insights, the analyses for idealized diapir geometries remain essentially unvalidated. The work reported here is intended to provide key validation for the conceptual model and numerical methodology developed to predict near-salt stress changes. In 2002, Conoco drilled the Spa prospect, Walker Ridge 285 #1, in the Gulf of Mexico to a depth of 29,452 feet MD / 29434 feet TVD, penetrating a nearly ten thousand foot salt section. While the potential for reduced fracture gradient below salt was recognized in well planning, pre-drill pore pressure and fracture gradient estimates were nevertheless based on seismic velocities in the adjacent abyssal basin. The sub-salt section was difficult to drill, and several formation integrity tests were performed. We developed basin-scale finite element models to represent the geometry of the salt diapir and performed non-linear geomechanical simulations to predict the stress changes in and around the diapir. The simulations predict stress perturbations that vary spatially in accord with the complex and irregular salt geometry. Significant perturbations are predicted adjacent to the salt diapir, and the models predict the reduction in fracture gradient observed sub-salt (nearly 3 ppg). This work thus serves to validate non-linear finite element stress analysis techniques that can be applied to reduce risks when drilling through massive salt diapirs. Besides providing a geomechanical basis for understanding sub-salt fracture gradient reductions, this work also demonstrates the potential for significant stress distortions associated with topography along the top of salt.
A New Approach for Reliable Estimation of Hydraulic Fracture Properties in Tight Gas Wells
Authors: Cheng Y. , Lee W. J. , McVay D. A. 
Published: December 2007

Abstract
Gas wells in low-permeability formations usually require hydraulic fracturing to be commercially viable. Pressure transient analysis in hydraulically fractured tight gas wells is commonly based on analysis of three flow regimes: bilinear, linear and pseudo-radial. With current well test analysis techniques, a reliable estimation of hydraulic fracture and reservoir properties relies on occurrence of all these three flow regimes. Without the presence of pseudo-radial flow, neither reservoir permeability nor fracture half length can be independently estimated. In other words, to reliably estimate fracture half length, reservoir permeability has to be known. Since pseudo-radial flow is often absent, the estimation is uncertain and unreliable. On the other hand, elliptical flow, which exists between linear flow and pseudo-radial flow, is of long duration (typically months to years). We can acquire much rate and pressure data during this flow regime but no practical well test analysis technique is currently available to interpret these data.
This paper presents a new approach to reliably estimate reservoir and hydraulic fracture properties from analysis of constant-rate drawdown pressure data obtained during the elliptical flow period. The method is based on equations modeling the elliptical flow regime and is applicable to estimate effective fracture half length, formation permeability and skin factor independently for both infinite- and finite-conductivity fractures. The method is iterative and features rapid convergence. It can estimate formation permeability when pseudo-radial flow does not exist. It can also be coupled with stable deconvolution technology, which convert variable production-rate and pressure measurements into an equivalent constant-rate pressure drawdown test, and thus provide property estimates from readily available, noisy production data. We present synthetic and field examples to illustrate the procedures and demonstrate the validity and applicability of the proposed approach.
Beryl Alpha—Reaching Out to Recover: An Extended-Reach Drilling Upgrade Project on a 30-Year-Old Rig
Authors: Cutt Richard N. 
Published: December 2007

AbstractThe Beryl field in UK Block 9/13 was discovered in 1972. The 40-slot, twin drilling rig, Beryl Alpha platform (see photograph Fig. 1) installed in July 1975 was the first concrete Condeep structure installed in the North Sea. The field is heavily faulted and stratigraphically complex, generating numerous drilling opportunities with associated geological uncertainties. Extended reach wells are planned to develop resources beyond the reach of the current platform rig capabilities.In the current industry environment where costs of semi-submersible rigs have risen dramatically and rig availability is an issue, the traditional concept of subsea satellite development is now problematic in terms of economic viability and control of schedule. The Beryl field has a number of satellite and in-field development opportunities beyond the platform's drilling reach. The concept of upgrading the Alpha drilling rigs to enable these resources to be developed by means of extended reach drilling (ERD) was conceived. The approach taken was to maximize ERD while remaining within the constraints of the existing derrick structures. This involved an innovative approach to retrofitting enhanced drilling capabilities on a 30-year old rig extending horizontal displacement from 15,000 to 25,000 ft (see field map on Fig. 2).This paper will address project planning from inception through the development of a rig upgrade execution plan and address the well design issues for the ERD program envisaged, including potential new drilling technology applications to reduce torque and enable multiple casing strings below 9-5/8-in. casing. Beryl celebrated its 30th year of production on 11 June 2006. The field life was initially estimated to be 20 years. At the time the Alpha platform was installed, Beryl Field reserves were estimated to be approximately 400 million barrels of oil equivalent, to date over 1.3 billion barrels of oil equivalent have been produced from the Beryl field and associated satellite developments (28% from subsea wells) far in excess of the original Alpha platform funding basis. Innovative approaches to field development characterised the beginning of Beryl's productive life and are being applied today to continue the process of extending field life by reaching out to recover and discover new resources previously thought beyond reach.
An Efficient Algebraic Multigrid Solver Strategy for Adaptive Implicit Methods in Oil Reservoir Simulation
Authors: Clees T. , Ganzer L. 
Published: December 2007

Abstract
We propose a new, efficient, adaptive algebraic multigrid (AMG) solver strategy for the discrete systems of partial differential equations arising from structured or unstructured grid models in reservoir simulation. The proposed strategy has been particularly tailored to linear systems of equations arising in adaptive implicit methods. The coarsening process of the AMG method designed automatically employs information on the physical structure of the models; as a smoother, an adaptive ILUT method is employed, taking care of an efficient solution of the hyperbolic parts whilst providing adequately smooth errors for the elliptic parts. To achieve a good compromise of high efficiency and robustness for a variety of problem classes – ranging from simple, small black-oil to challenging, large compositional models – an automatic, adaptive ILUT parameter and AMG solver switching strategy, α-SAMG, has been developed. Its efficiency is demonstrated for eight industrial benchmark cases by comparison against standard one-level and AMG solvers as well as the pure one- level variant of the proposed new strategy. In addition, very promising results of first parallel runs are shown.
Dope-Free Tubular Connections, through Research and Development to Field Trial and Implementation: A North Sea Case History
Authors: Andersen Henrik B. , Hummer Marcus P. , Engell Rasmus C. , Verdillon Lionel , Pardé Arnaud 
Published: December 2007

Abstract
In 2000 Vallourec & Mannesman Tubes approached Maersk Oil with the vision of a tubular connection that requires minimum handling in its lifespan from the mill to the well, removing environmental impact from dope and increasing safety at the well site. To realize this, all application of thread compound in the field or yard was to be eliminated, and a protector design developed that enables the protector to be removed only when the tubular is ready to be run in the well.
After an initial development period Vallourec & Mannesman Tubes had a final Dopefree product ready for test. The product a transparent waxy compound applied directly on selected premium threads, serving as both storage and running dope, completely eliminate the requirements for cleaning an redoping at the wellsite. It was decided to initially perform a field test and if successful to implement Dopefree on all tubular sizes where avalaible
Maersk Oil operates wells offshore in the Danish sector of the North Sea, which are characterized by being long horizontal wells (5,000 – 20,000 ft VS) drilled in chalk reservoirs. The wells are commonly completed with 4½" or 5½" completion inside a 7" liner hung off in a 9-5/8" production casing set just above the reservoir. The liners are in some cases cemented in place to allow for zonal isolation. The driving factors for Maersk Oil to test and subsequently implement Dopefree were: Increased safety by minimizing tubular handling,Minimize environmental impact by removing dope,Increase efficiency for wireline and coiled tubing operations by eliminating excessive dope in the well.
Drilling for Coalbed Methane in the San Juan Basin With Coiled Tubing: Results, Learnings, and a World First
Authors: Noynaert Sam , Pumphrey Dale , Pink Tony , Eiden Tug , Hartensteiner Fred , Nelson Chip 
Published: December 2007

Abstract
The San Juan basin is a prolific natural gas play in northwestern New Mexico and southwestern Colorado. It contains conventional oil and gas resources along with unconventional gas resources in the forms of tight gas and coalbed methane (CBM). Conventionally, drilling operations have been carried out by smaller rotary rigs with double or single derricks. These are usually minimalist, older rigs which fit well into the tight cost structure of the unconventional resources in the San Juan basin.
In 2006, a coiled tubing drilling (CTD) pilot program was initiated in the San Juan basin consisting of seven wells, drilled in order of increasing complexity. The intention was to evaluate the full capabilities of CTD and its potential for use in the San Juan basin as well as the general U.S. onshore area. The drilling program included vertical wellbores, S-shaped wells off of a pad, and a horizontal sidetrack- all targeting the Fruitland Coal. In addition, several vertical and directional deep-set intermediate strings for future drilling of the deeper tight gas in the Mesa Verde and Dakota formations were set with CTD.
The rig used was a new, custom-built, coiled tubing/rotary hybrid rig setup for use with large-diameter coiled tubing (3.5 in. and 2.875 in. OD). In addition, it had a single-sized derrick, rotary table and top-drive. This allowed the rig to drill with jointed pipe, handle and make-up bottomhole assemblies (BHA), and run liner and casing.
Problems were encountered in areas such as fluid and additive selection, bit selection, hole stability issues, and crew training and rig limitations. In addition, CTD in this format was new to the San Juan basin and its personnel. Further issues that added difficulty included maintaining stringent standards of safety and environmental compliance, as well as conducting world-first operations such as running a rotary-steerable system (RSS) on coiled tubing. The end result was seven successfully drilled wells that are producing at the same or at better rates than offsets drilled with conventional rotary technology.
Study on Gelation and Freezing Phenomena of Synthetic Drilling Fluids in Ultradeepwater Environments
Authors: Gandelman R. A. , Leal R. A. F , Gonçalves J. T. , Aragão A. F. L. , Lomba R. F. , Martins A. L. 
Published: December 2007

Abstract
Fast and non-progressive drilling fluid gelation is desired to prevent drilled solids sedimentation during pumps-off, while avoiding excessive pressure peaks when circulation is resumed. Gelation tendencies are normally higher at low temperatures typical of deepwater risers. Excessive pressure peaks can cause detrimental effects when fracture pressure is reached.
Besides gelation issues, excessive pressures and/or difficulties to resume circulation have been observed during drilling operations in water depths greater than 1.800 m. The problem happened especially with the fluid volume filling the control lines, at the time of circulation restart. Two field cases of fluid freezing in choke and kill lines have been reported which led to riser and BOP removal to unplug the lines, with significant non productive time and high costs.
The paper shows the results of an experimental study carried out to evaluate the rheological behavior and gelation properties of non aqueous drilling muds under low temperatures (bellow 4° C) and high pressures (up to 5.000 psi). The study aimed to quantify pressure effects on freezing temperatures and to develop representative methodologies for the evaluation of thyxotropic properties of such fluids. Experiments included steady state and transient shear and oscillatory tests at cone-plate geometries. The final goals are to design additives and drilling fluid formulations with flow point lower than 0° C at pressures higher than 2.500 psi and taylor made gelation profiles. Additionally modeling work was carried on to represent the time dependent behavior of relevant rheological properties at different temperatures and pressures. Such models were used to predict pressure peaks and compare them with real PWD data from ultra deepwater wells.
Are Preflushes Really Contributing to Mud Displacement During Primary Cementing?
Authors: Guillot D. J. , Desroches J. , Frigaard I. 
Published: December 2007

Abstract
During a primary cementing operation, it is most of the time necessary to prevent direct contact between the drilling mud and the cement slurry that is to be placed in the wellbore. The reason is that these two fluids are usually incompatible. This incompatibility can manifest itself either as an accelerating effect, the drilling mud/cement mixtures having a shorter thickening time than the cement itself, which is obviously not acceptable, or as a viscosifying effect, the drilling mud/cement mixtures being more or much more viscous than any of the two uncontaminated fluids, which can be detrimental to the displacement process.
To keep the drilling fluid and the cement slurry separated, low density and low viscosity fluids, that will be referred to as preflushes, are often pumped ahead of the cement slurry. Examples of such fluids are water, oil, or more advanced formulations which are usually called chemical wash. It was recognized relatively early that, to be efficient, preflushes should be in turbulent flow in the annulus for a minimum amount of time. In the early 90s the criteria for turbulence was refined by taking into account the eccentricity of the annulus on the flow regime.
The objective of this paper is to illustrate what fluid displacement modeling is telling us about the efficiency of these preflushes. It will be shown that, in a number of cases, preflushes are not as effective as one would think at preventing direct contact between the drilling fluid and the cement slurry, even when industry accepted rules are used to design them. In such circumstances the cement slurry is actually displacing the drilling fluid, but there are risks associated with this situation as explained above. It is therefore suggested that preflushes should be used with more caution and replaced by weighted spacers, in particular in circumstances where good cement quality is mandatory up to the top of the cement column.
Improvement of Placement Efficiency of BaSO4 and SrSO4 Dissolvers Using Organic Alkalis as pH Controlling Agents
Authors: Lakatos Istvan , Lakatos-Szabo Julianna , Toth Janos , Bodi Tibor 
Published: December 2007

Abstract
The research program is based on earlier evaluation of seven different polyamino carboxylic acids (NTA, EDTA, DCTA, DTPA, DOCTA, HEDTA and TTHA). The flow tests comprised the study of NaOH, KOH, Na2CO3 and K2CO3 solutions with and without dissolvers. Low molecular weight amines (mono-, di- and trimethyl and –ethylamines) served also as pH controlling agents. Comparison of inorganic and organic additives was made through their effect on effective permeability in artificially consolidated sandstone cores.
Based on the experimental findings it was concluded that solutions containing inorganic alkalis deteriorate the permeability independently of the fact that they were chelate containing or chelate-free. Similar results were obtained for all ethylamines. The methylamines, however, proved to be excellent pH controlling agents: permeability of the porous media remained unchanged, or even improved through extensive injection period; meanwhile the dissolution capacity of dissolvers was preserved or slightly increased.
It was clearly proved that selection of the best dissolver should be made by compromising the different technical aspects: not the chelating agent and the dissolution capacity is important, but also to the type of alkali compounds. Using organic alkalis the detrimental side effect of conventional inorganic alkaline compounds can be eliminated improving the flow characteristic and placement efficiency of dissolvers.
Assessing the Accuracy of History-Match Predictions and the Impact of Time-Lapse Seismic Data: A Case Study for the Harding Reservoir
Authors: Walker Greg J. , Lane H. Scott 
Published: December 2007

Abstract
The oil industry benefits from reservoir models that are accurate predictors of future performance, but a "good" match to historical well data doesn't guarantee a "good" prediction. This paper presents a case study from the Harding field in the North Sea, illustrating that we can greatly improve our chances of getting "good" predictions from our reservoir models by including time-lapse (4D) seismic data as part of the history matching process. The value of the surveillance is also discussed in the light of its use in improving reservoir performance prediction.
The first part of the case study addresses the accuracy of prediction. The Harding field (Figure 1) started production in 1996, with the first time-lapse seismic survey being acquired in 2000. Using computer-assisted history matching techniques,1 multiple alternative reservoir models were generated that matched the well surveillance to 2000. In a blind test of predictive capability, forward predictions from these alternative models were compared with the subsequent production data from 2000 to 2003, allowing us to compare quantitatively the prediction quality against the history match quality for the selected cases. The time-lapse seismic data from 2000 was then included in the history matching process and the impact on the resulting prediction quality through 2003 was evaluated. Addition of the 4D seismic data enabled the selection of a subset of reservoir models which better predicted the (known) future of the field.
The best hypotheses are those that make predictions that can be tested. If 4D seismic information is effective in reducing uncertainty, then there should be a way of making a quantitative estimate of the value of a future seismic survey. The impact and value of acquiring a future time lapse seismic survey, and a discussion around the metric for value of surveillance, are discussed in the second part of the case study.
Simultaneous Recording of Hydraulic-Fracture-Induced Microseisms in the Treatment Well and in a Remote Well
Authors: Mahrer K. D. , Zinno R. J. , Bailey J. R. 
Published: December 2007

Abstract
In June 2006, in a production well in a tight sandstone shale sequence, on-shore USA, two borehole seismic arrays were deployed in separate wells during a proppant-baring hydraulic fracture treatment. The intent was to delineate the treatment-generated fracture network by recording the microseisms triggered by the treatment, map the microseism source locations, and then use the map as an overlay to delineate the fracture network. The treatment was one facet of a proprietary, multi-faceted injection strategy with microseismic mapping used to determine if neighboring fracture networks overlap. In addition to mapping the network, the objective of this facet was to compare maps from the two arrays. One array was in a remote well, the other in the treatment well. The remote array was offset ~700 ft from the treatment well and at the injection depth. This array was ~500 ft long; self-locking; contained 15, 3-component motion sensors; and operates on a fiber-optic cable. The treatment-well array, the "TABS" or TriAxial Borehole Seismic array (licensed by ExxonMobil Upstream Research), is ~75 ft long; self-locking; operates on a standard, 7-conductor wireline; and includes (1) 3, 3-component motion sensors, (2) an ambient fluid pressure sensor, and (3) a gyroscopic, sensor orientation package. During the treatment, a 45-minute injection immediately followed by a 1-1/2-hour well shut-in, the remote array failed to detect any discernable treatment-triggered, microseisms. However, TABS, which recorded microseismicity only during the shut-in, recorded ~400 microseisms. During the operation, the remote array maintained one position; TABS was unlocked, repositioned, and relocked twice; Moving TABS allowed different perspectives for recording the microseismicity, improving the accuracy of mapping and enhancing additional characteristics extractable from the microseismic waveforms.