bluuebunny/crossref_metadata_2025_split huggingface dataset:
SubSea MudLift Drilling Joint Industry Project: Delivering Dual Gradient Drilling Technology to Industry
Authors: Smith K. L. , Gault A. D. , Witt D. E. , Weddle C. E. 
Published: December 2007

Abstract
In early 1996, a consortium of deepwater drilling contractors, operators, service companies and a manufacturer gathered to discuss potential approaches to "riserless drilling", also known as "dual gradient drilling". This technology overcomes a significant deepwater drilling challenge: eliminating some of the casing strings necessitated by the relatively high pore pressures and low formation strengths found in areas like the deepwater Gulf of Mexico.
That initial workshop led to what has become one of the largest and most significant joint industry projects (JIPs) in the history of our industry: the SubSea MudLift Drilling JIP. The JIP's overarching goal became to provide a total solution for dual gradient drilling, that is, both hardware and the methodology to safely and efficiently use that hardware.
Five years and nearly 50 million dollars later, this JIP has succeeded in that goal.
This paper, the first in a series of three on SubSea MudLift Drilling (SMD), will present highlights of the history of the project, its organization and its management (see also SPE 71358 and SPE 71359). The information presented here demonstrates the level of effort necessary to produce a ready-for-application technology, and will assist anyone planning a major JIP to deliver a complex new technology.
Additionally, it will discuss the development of the SMD equipment, the preparation of SMD-specific drilling and well control procedures and the complementary relationship between those procedures and the equipment design. This paper will verify the integrity of the process used to develop these procedures, and it will help the reader understand the SMD system and techniques developed by the SMD JIP.
Aphron-Base Drilling Fluid: Evolving Technologies for Lost Circulation Control
Authors: Ivan C. D. , Quintana J. L. , Blake L. D. 
Published: December 2007

Abstract
Drilling depleted reservoirs is fraught with a host of technical and economic problems that often make it unprofitable to further develop some mature fields. Most of the problems center around uncontrollable losses in the large fractures that commonly characterize these reservoirs. Frequently, less expensive drilling fluids will be used in a particular interval, even though it may have the propensity to damage the formation. The reasoning holds that such fluids will offset the high costs of losing more expensive muds to the formation.
A specialized invasion control drilling fluid has been developed to drill reservoirs prone to lost circulation. This fluid combines certain surfactants and polymers to create a system of "micro-bubbles" known as aphrons that are encapsulated in a uniquely viscosified system. These aphrons are non-coalescing, thereby creating a micro-bubble network for stopping or slowing the entry of fluids into the formation. The unique viscosity builds to create a resistance to movement into and through the zone, thus generating a true non-invasive and at-balance fluid. Test data confirms its enhanced hole cleaning and suspension properties.
This paper describes the development and application of the specialized "micro-bubbles"-base drilling fluid for controlling downhole mud loss and formation damage. The authors will detail the laboratory methods used to generate appropriate formulations, the operational procedures, and field applications.
As detailed in the paper, this novel drilling fluid relies entirely on "micro-bubbles" network bridging and does not contain any conventional particulate agent for sealing the loss zone. Therefore, the fluid can be pumped through narrow drill pipe, coil tubing and downhole tools. Case histories show that drilling problems are reduced, while drilling fluid losses are prevented or minimized dramatically.
Development and Field Applications of Roller Cone Bits with Balanced Cutting Structure
Authors: Chen S. L , Dahlem Jim 
Published: December 2007

Abstract
A roller cone bit with balanced cutting structure is developed in this paper. A balanced cutting structure refers to energy balancing and/or force balancing. This paper describes why traditional roller cone bits are unbalanced, how the balancing condition of an existing roller cone bit is evaluated by a computer drilling simulator, and how an unbalanced cutting structure can be balanced by a design optimization procedure. Finally, bit performance in the field is discussed and compared with offset bits. It is found that a force balanced roller cone bit has better durability and drills faster than the offset bit.
Near-Field Exploration: From Failure to Success
Authors: Marchant Tim , Wilson Hamish , Bamford David 
Published: December 2007

Abstract
During the late 1980's and early-mid 1990's both BP and Amoco invested large sums of money exploring close to their core producing fields in traditional ‘heartlands’ such as the North Sea, Alaska and L48. These investments were largely unsuccessful. Amoco coined the term ‘stealth exploration’ to describe the activity carried out by individual assets whose failure costs only later appeared on the corporate balance sheet as exploration write-off.
The recent industry focus on short-term production has reawakened interest in near-field exploration. BP is no exception. Despite the overall corporate perception of failure, it became apparent that some business units, notably Canada Gas and Egypt Oil, were making a quiet success of near-field exploration. Therefore the company conducted a study to understand what made these BU's successful. The lessons learned were:
– A focus on monetisation and cycle time – Tight integration between exploration and production – Tight control of subsurface technical risk – Focus on certain key plays
The company allocated a limited amount of seed capital to test the concept of near-field exploration in five business units where BP has a dominant ownership of the regional infrastructure. This diverse group of upstream businesses has successfully managed a limited exploration programme and demonstrated that near-field exploration can be controlled and can add value through short-term production.
The key conclusion to be drawn from this story of ‘corpor; learning’ is that near-field exploration in large companies c make money provided three actions are taken:
Do not compromise on subsurface technical risk in the face of pressure from engineers and others attracted by the economics – an investment with a positive EMV and/or high RoR with a high technical risk is still a high-risk investment. Manage the activity as an integrated part of the production asset to minimise cycle time. Set tight performance metrics and manage the portfolio globally.
The Adaptation of Reservoir Simulation Models for Use in Reserves Certification Under Regulatory Guidelines or Reserves Definitions
Authors: Palke M. R. , Rietz D. C. 
Published: December 2007

Abstract
The estimation of oil and gas reserves is necessary for assessing the value of oil and gas properties, and for meeting the reporting and disclosure requirements imposed on oil and gas companies by various governmental and regulatory bodies. Reservoir simulation is a sophisticated technique of forecasting future recoverable volumes and production rates, and is an increasingly popular tool for reservoir management and optimization. Reservoir simulation is also progressively being used in the process of forecasting and estimating reserves. However, as with any reservoir engineering technique, certain precautions must be taken when relying on reservoir simulation as the means for estimating reserves. This paper identifies some of the unique issues encountered in the reserves evaluation process when reservoir simulation is utilized, and offers strategies for addressing these issues.
Perforating Unconsolidated Sands: An Experimental and Theoretical Investigation
Authors: Walton Ian C. , Atwood David C. , Halleck Phillip M. , Bianco Luis C. B. 
Published: December 2007

Abstract
This paper describes experiments and modeling undertaken to develop a perforating strategy for unconsolidated sand formations. The experimental program consists of single-shot perforations in cylindrical samples of three sizes (4-in, 7-in and 10.5-in diameters) of unconsolidated sand saturated with kerosene at residual brine saturation and placed under a high effective stress in a pressure vessel. The amount of sand produced during perforating, as well as that produced during post shot flow is measured and a video probe is used to observe post-shot sand production. CT-scan equipment is used to map the geometry of the cavity. The features of the sand behind the casing are examined and interpreted, providing essential insights into the interaction of the charge with the sand sample. A theoretical model of the failure mode of unconsolidated sands has been developed and supports the observations.
The main results so far from this study are as follows:
Perforating does not generate a tunnel in unconsolidated sands. The intense pressures set up in the weak sand sample by penetration of the shaped charge fluidize the sample and cause the initial tunnel to collapse. Production flow creates a dilated zone around the tunnel entrance. At a critical flow rate a large volume of sand is produced and the sample collapses. This occurs when flowing out of a hole in an unperforated sample as well.
The implications of these results for future work and for field applications are addressed.
First Ultra-Low Interfacial Tension Foam Flood Field Test Is Successful
Authors: Wang Demin , Cheng Jiecheng , Qun Li , Wu Junzheng , Wu Wenxiang , Zhang Yanqing 
Published: December 2007

Abstract
An important method to increase the recovery of reservoirs is ASP (alkaline/surfactant/polymer) flooding to lower the IFT (interfacial tension) between the crude oil and displacing fluid to an ultra-low value (&lt;10−3 mPa.s) to increase the displacement efficiency and at the same time to increase the viscosity of the displacing fluid in order to increase the volumetric sweep efficiency. However, the alkaline in the ASP fluid makes it difficult to increase the viscosity by polymers. Therefor, experiments were performed by adding natural gas to the ASP fluid to form an ASP foam (ASPF) displacing fluid. This ASPF fluid should have the characteristics of an ultra-low IFT, high displacement efficiency and also low mobility, which should increase the volumetric sweep efficiency also.
This paper introduces the results of ASPF tests in the laboratory and field. The experimental results in the lab include the foaming ability of the ASPF, the stability of the foam, its IFT, resistance to flow in cores and the incremental recovery of cores of different heterogeneity. The field results include reservoir description, well pattern, composition of the injected ASPF, injection and production conditions and problems encountered.
Good results were obtained in the field. The current recovery factor is already 65.6% OOIP. The final recovery is estimated to reach 71.3% OOIP.
Experiments and Analysis of Heavy Oil Solution Gas Drive
Authors: Sahni A. , Gadelle F. , Kumar M. , Kovscek A. R. , Tomutsa L. 
Published: December 2007

Abstract
We provide a general framework for interpreting heavy oil solution gas drive experiments. Evolution of the gas phase below the thermodynamic bubble point is investigated using dimensionless scaling groups and mechanistic modeling. The role of initial solution gas oil ratio, oil viscosity and depletion rate on the early growth of the gas phase is discussed. Factors leading to the coalescence of gas bubble clusters and development of bulk gas flow are illustrated with examples, along with an empirical correlation for critical gas saturation (Sgc).
Two carefully planned and monitored depletion experiments are conducted to evaluate the pre and post-Sgc behavior. These experiments are CT-scanned to obtain in-situ saturations, that are used in conjunction with differential pressure measurements along the core to obtain phase mobilities. Implications of conducting experiments at pressure depletion rates and gradients substantially higher than field rates are discussed.
Understanding Waterflood Residual Oil Saturation of Four Carbonate Rock Types
Authors: Kamath Jairam , Meyer Robert F. , Nakagawa Frank M. 
Published: December 2007

Abstract
Laboratory determination of residual oil saturation (ROS) in carbonate cores is sometimes uncertain due to wide pore size distribution, core scale heterogeneity, and complex wettability. The values obtained in laboratory tests may vary depending on flow rates, the type of samples (plugs or whole cores), and sample preparation techniques.
The purpose of our study is to integrate modern flow visualization technology with conventional laboratory tools to provide a comprehensive picture of waterflood recovery behavior in four carbonate cores. Our data set comprise thin sections; mercury injection; 3-D porosity distribution; oilfloods and waterfloods on cleaned samples; and 3-D flow imaging of miscible floods, oilfloods, and waterfloods on restored state samples.
The 3-D Computed Tomography (CT) images allowed us to understand the reasons for decrease in oil saturation observed with increased pressure drop in the corefloods; whether this is due to capillary-end effects, core scale heterogeneity, or actual reduction in ROS. We find that ROS
values under field-rate flooding conditions (~ 1 psi/foot, Nc• ~ 10−8, lateral flood) are in the 30%-60% PV range. These ROS values reduce significantly as the pressure gradient applied during the floods is raised from field values to the much higher-pressure gradients sometimes used in laboratory testing (~ 100 psi/ft, Nc ~ 10−6 ). The carbonate samples with large pore-throat aspect ratios have the largest ROS values and the biggest variation with the pressure drop used in the waterfloods.
On The Use of Upscaling Methods to Describe Acid Injection in Carbonates
Authors: Pomès V. , Bazin B. , Golfier F. , Zarcone C. , Lenormand R. , Quintard M. 
Published: December 2007

Abstract
In this paper, we study the dissolution process in carbonates for the design of acidizing jobs. The difficulty is the modelling of the formation and the propagation of the dissolution patterns (the wormholes) which result from an instability very similar to viscous fingering.
In reservoir simulators, the flow equations must generally be written at a scale larger than the standard Darcy equations in order to incorporate the heterogeneities of the formation (upscaling). In multiphase displacements without acidizing, the upscaled properties such as relative permeabilities and capillary pressure, are derived from properties on homogeneous core samples by numerical simulations using the standard Darcy's equation ("Kyte and Berry" methods). For acidizing, the upscaling process must also incorporate the effect of the dissolution which is similar to heterogeneity which change with time. To derive the upscaled properties, we will use a similar approach based on numerical simulations. However, we need a numerical simulator that can account for worm-hole formation at Darcy scale.
We have built a 2D numerical simulator which calculates the dissolution pattern in a core. The originality of the simulator is the introduction of the physics at the pore scale:
The flow equation takes into account Darcy flow in the matrix and Stokes law in the wormhole. The dissolution equation is derived from a volume averaging of the diffusion and reaction equations written at the pore scale.
Comparison between the numerical simulations and experimental results demonstrates that adequate physics is introduced in the model:
The various dissolution regimes observed in experiments are also obtained in numerical simulations: compact, wormholing and homogeneous An optimum flow rate corresponding to the maximum penetration of the wormhole is also reproduced with the simulator. For the effect of concentration and core length, the simulations exhibit the same trends as those observed with the experiments
In addition, the simulator as been used to study the effect of parameters which are difficult to change experimentally. The larger number of "numerical experiments" will be used to build the upscaled model for reservoir simulations.
A Semianalytical p/z Technique for the Analysis of Reservoir Performance from Abnormally Pressured Gas Reservoirs
Authors: Gan Ronald Gunawan , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents the development of a new analysis technique that can be used to determine the gas-in-place for abnormally pressured gas reservoirs. This new approach requires only production data (p¯ and Gp) — and does not require a prior knowledge of formation and fluid compressibility data. Using a pressure-dependent compressibility function based on the generalized gas material balance equation, this approach can be used to model both the rock collapse and shale water influx theories presented in the literature.
In this work we introduce two new plotting functions:
c ¯ e ( p i − p ) versus (p/z)/(pi/zi) and (p/z)/(pi/zi) versus Gp/G
where these plotting functions are developed using the generalized gas material balance equation for a gas reservoir under the influence of a pressure-dependent formation compressibility function (Fetkovich, et al.1) in conjunction with the two straight-line trends observed on the p/z versus Gp plot for abnormally pressured gas reservoirs. Using these new plotting functions we develop a dynamic type curve matching technique that simultaneously determines the gas-in-place (G). In addition to gas-in-place, this new technique can be used to calculate pore volume compressibility as a function of reservoir pressure.
We provide the verification of our new analysis technique using the results of numerical simulations and we demonstrate the application of this methodology using several field examples.
Decline Curve Analysis Using Type Curves — Evaluation of Well Performance Behavior in a Multiwell Reservoir System
Authors: Marhaendrajana T. , Blasingame T. A. 
Published: December 2007

Abstract
In this paper we present a new multiwell reservoir solution and an associated analysis methodology to analyze single well performance data in a multiwell reservoir system. The key to this approach is the use of FIELD cumulative production data and individual well flowrate and pressure data. Our new solution and analysis methodology "couples" the single well and multiwell reservoir models — and permits the estimation of total reservoir volume and flow properties within the drainage area of an individual well — where the analysis is performed using a SINGLE WELL reservoir model (type curve). This "multiwell analysis" using a "single well model" is made possible by a "coupling" of the single well and multiwell solutions based on a total material balance of the system. The data required for this approach are readily available in practice: basic reservoir properties, fluid properties, well completion data, and well rate (and pressure) data and cumulative production data for the entire field.
Currently, ALL existing decline type curve analyses assume a single well in closed system (or single well with constant pressure or prescribed influx at outer boundary). In many cases a well produces in association with other wells in the same reservoir — and unless all wells are produced at the same constant rate or the same constant bottomhole flowing pressure, non-uniform drainage systems will form during boundary-dominated flow conditions.
Further, it is well established that new wells "steal" reserves from older wells, and this behavior is commonly observed in the production behavior. Our new approach accounts for the ENTIRE production history of the well and the reservoir, and eliminates the influence of "well interference" effects. This approach provides much better estimates of the in-place fluids in a multiwell system, AND the methodology also provides a consistent and straightforward analysis of production data where "well interference" effects are observed.
This work provides the following deliverables:
A new solution for a multiwell reservoir where the formulation of this solution yields a simplified form for an arbitrary (individual) well during boundary-dominated flow conditions. A complete analysis methodology for oil and gas reservoir systems based on conventional production data (on a per well basis) as well as the cumulative production of the entire field. A systematic validation of this approach using a numerical reservoir simulator for cases of homogeneous, regionally heterogeneous, and randomly heterogeneous reservoirs. An application to a large gas field (Arun Field, Indonesia). This analysis provides very consistent estimates of in-place fluids and reservoir properties. All of these analyses (simulated and field data) clearly demonstrate that the effects of "well interference" on individual wells have been eliminated as a result of this analysis methodology.
Field Validation of 3-Dimensional Drag Model for Tractor and Cable-Conveyed Well Intervention
Authors: McSpadden A. , Brown P. , Davis T. 
Published: December 2007

Abstract
Field data is presented to validate the accuracy of a mathematical model to predict the drag forces involved in conveying tools into and out of deviated wells with cable (wireline or slickline). The curvature of deviated wells significantly increases drag and introduces non-linearity in the cumulative drag developed between the downhole tool and the surface. The model incorporates analysis of fluid flow in the wellbore to estimate total drag. The ability of a wireline tractor to deploy the tools into horizontal well sections may also be evaluated via the model. The model has been implemented in a computer program to numerically estimate and graphically represent the behavior of wireline and slickline cables in deviated and vertical wells.
Testing Configuration and Pre-Analysis Data Treatment to Eliminate the Effect of Fluid Segregation on Well-Test Interpretation
Authors: Al-Afaleg Nabeel I. , Gilani SyedKhalid 
Published: December 2007

Abstract
Fluid segregation in the wellbore of multiphase flowing wells poses a challenge in interpreting pressure build-up tests in some high permeability Saudi Arabian oil reservoirs. Current testing practice calls for placing the pressure gauge in the tailpipe assembly about 300 ft above perforations. Fluid gradient changes in build up tests between the pressure gauge and the tested zone as a result of fluid interface in the wellbore falling back to resevoir fluid contact, may significantly distort the recorded pressure. The distortion is dependant on reservoir permeability and water or gas cut. Field examples are presented to demonstrate the effect of fluid segregation on recorded pressure data. Down-hole shut-in tool is shown, through a field example, not to be effective in removing the segregation effect on pressure data. A different testing configuration was successfully used in the field to eliminate the fluid segregation on pressure data. For wells where the described testing setup cannot be implemented, two preanalysis procedures are presented to remove the effect of fluid segregation on pressure data.
CO2 Pilot Design and Water Injection Performance in the Naturally Fractured Spraberry Trend Area, West Texas
Authors: Schechter D. S. , Putra E. , Baker R. O. , Knight W. H. , McDonald W. P. , Leonard P. , Rounding C. 
Published: December 2007

Abstract
This paper addresses the field activities to develop a 15 well, 60-acre CO2 pilot in the Spraberry Trend Area in west Texas. Spraberry reservoirs originally contained 10 Bbbls OOIP of which less than 10% has been recovered. Waterflooding has been documented as a poor recovery technique. We demonstrate that an unexpected response to water injection may alter conventional wisdom. We also describe a unique characterization of the natural fracture system with step-rate injection testing, buildup and multi-well interference testing, and tracer surveys.