bluuebunny/crossref_metadata_2025 huggingface dataset:
Understanding the Effects of Reservoir and Operating Parameters on Tight-Gas Production Decline
Authors: Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

This paper presents a systematic analysis of production decline of tight-gas wells. The roles of fluid-reservoir and operating parameters on the flow rate, decline rate, decline exponent, productivity factor, ultimate recovery, and recovery factor are identified based on seven performance indicators. These seven indicators can be obtained easily by type-curve matching of production data (inverse study) or by simple computation using the presented equations (forward study). An action-reaction chart is constructed to provide a "quick-look" for the impacts (benefits or/and trade-offs) of actions (changes in reservoir/operating parameters) on the seven types of well performance (reactions). Among all the actions considered, well-stimulation and well-spacing result in the most complicated reactions. They are also the two engineering issues most pertinent to tight-gas developments. Their impacts are demonstrated by numerical examples.
Drainage Shape and Size of a Vertically-Fractured Tight-Gas Well
Authors: Alzate Guillermo A. , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

This paper presents a systematic simulation study of a tight-gas, vertically-fractured well aimed to describe the evolution of drainage shape and size with time. The drainage shape is described in terms of the drainage-aspect-ratio, the ratio of the length to width of the specified isopressure line. The drainage size is described in terms of the drainage-area-ratio, the ratio of the area for the specified isopressure line to the well spacing area. The shape and size of a drainage area are determined numerically for a specified isopressure line as functions of dimensionless fracture conductivity (1 ≤ FCD ≤ 1,000), fracture half-length (94 to 840 ft), permeability level, permeability anisotropy, and time. Knowledge of the evolution of drainage size and shape with time and their long-term behavior are extremely important for planning infill drilling activities, either for choosing new infill well locations or modifying well spacing/pattern. An example is given to show how to estimate drainage shape and size based on the results presented here.
Geostatistical Integration of Rock Physics, Seismic Amplitudes and Geological Models in North-Sea Turbidite Systems
Authors: Caers Jef , Avseth Per , Mukerji Tapan
Published: December 2007

Turbidite systems are complex heterogeneous siliciclastic deposits calling for a new approach to geophysical and geostatistical reservoir characterization. The aim of this paper is to demonstrate the integration of seismic amplitude and rock physics data into realistic geological scenarios using a novel geostatistical approach. Avseth (2000, 2001 with others) presented an integrated rock physics/seismic inversion approach to predict seismic facies within the Glitne Field reservoir, North Sea. The outcome of this work is a seismic derived conditional probability of facies. We provide a geostatistal methodology for integrating this large-scale probability model with smaller scale geological models consisting of channel complexes typical for known turbidite systems around the world.
Halfdan: Developing Non-Structurally Trapped Oil in North Sea Chalk
Authors: Albrechtsen T. , Andersen S. J. , Dons T. , Engstrem F. , Jergensen O. , Sørensen F. W.
Published: December 2007

Mæsk Olie og Gas AS has as operator for the Danish Underground Consortium (DUC) discovered and initiated the development of the Halfdan accumulation located in the southern part of the Danish North Sea. The accumulation comprises oil and gas in a low permeability chalk reservoir located outside structural closure.

This paper describes how the phased, fast track development of Halfdan was planned and executed while testing a new concept for constructing an aligned sweep pattern.

Tilted oil-water and gas-oil contacts across the Halfdan area are indicative of non-equilibrium conditions. The nonstructural trapping in the Halfdan area is provided by a combination of up dip thinning of the hydrocarbon bearing section, late structural tilting and the slow re-adjustment caused by the low permeability.

Accelerated and stepwise development was pursued to allow continuous optimisation of the development in light of the significant uncertainties associated with the fluid distribution and reservoir production characteristics. Appraisal drilling from a template and tie-back of the appraisal wells to temporary production facilities via the drilling rig and early deployed pipelines enabled production from the Halfdan 10 months after finalising the discovery well. Furthermore, a temporary water injection package installed on the drilling rig enabled evaluation of water injection before the installation of permanent facilities including determination of displacement efficiency, fracturing pressure and induced fracture orientation. Halfdan was produced through permanent facilities less than 18 months after finalising the discovery well.
Reservoir Modeling Using Multiple-Point Statistics
Authors: Strebelle Sebastien B. , Journel Andre G.
Published: December 2007

Two approaches are traditionally used to build numerical models for facies distributions within a reservoir. Pixel-based techniques aim at generating simulated realizations that honor the well data values, and reproduce a given variogram which models two-point spatial correlation. However, because the variogram cannot look at spatial continuity between more than two locations at a time, pixel-based algorithms give poor representations of the actual facies geometries. In contrast, object-based techniques allow reproducing crisp geometries, but the conditioning on well data requires iterative "trial-and-error" corrections, which can be time-consuming, particularly when the data are dense with regard to the average object size. This paper presents a new approach that combines the easy conditioning of pixel-based algorithms with the ability to reproduce "shapes" of object-based techniques, without being too time and memory demanding.

In this new approach, the complex geological structures expected to be present in the reservoir are characterized by multiple-point statistics, which express joint variability at many more than two locations at a time. Such multiple-point statistics cannot be inferred from typically sparse well data but could be read from training images depicting the expected subsurface heterogeneities. A training image need not carry any locally accurate information on the reservoir; it need only reflect a prior stationary geological/structural concept. Thus training images can be generated by object-based algorithms freed of the constraint of data conditioning. The multiple-point statistics inferred from the training image(s) are then exported to the reservoir model, where they are anchored to the well data using a pixel-based sequential simulation algorithm.

This algorithm is tested for the simulation of a turbidite system where flow is controlled by meandering channels with cross-bedding. The training image reflecting the channel patterns is an unconditional realization generated by an object-based algorithm. The final simulated numerical models reproduce these channel patterns, and honor exactly all well data values at their locations. The methodology proposed appears to be practical, general, and fast.
Assessing the Oil Water Contact in Haradh Arab-D
Authors: Stenger B. A. , Pham T. R. , Al-Sahhaf A. A. , Al-Muhaish A. S.
Published: December 2007

Haradh forms the southernmost part of the super giant Ghawar oil field located about 80 km (50 miles) onshore from the Arabian Gulf, in the Eastern Province, Kingdom of Saudi Arabia (Fig. 1).

A major feature of the Ghawar field is its tilted Original Oil Water Contact (OOWC), getting shallower from North to South Ghawar at an average gradient of 0.36 m (1.2 ft) per km. In Haradh, the OOWC displays also a large but localized west-to-east component.

Understanding the OOWC tilt mechanisms is vital since it will improve the effectiveness of the on-going Oil-Water Contact (OWC) delineation program. This will result in better placement of future producers and injectors, which in turn will reduce the cost of future developments.
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

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

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

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

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

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

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

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 (<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

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

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

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

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

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

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

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

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.
Combination of Experimental Design and Joint Modeling Methods for Quantifying the Risk Associated With Deterministic and Stochastic Uncertainties - An Integrated Test Study
Authors: Manceau E. , Mezghani M. , Zabalza-Mezghani I. , Roggero F.
Published: December 2007

This paper presents a fully-integrated methodology for managing reservoir uncertainties during history matching, production forecasting and production scheme optimization.

Based on the traditional experimental design methodology, this innovative approach, called the Joint Modeling Method, allows to model the production recovery as a function of both the deterministic uncertain parameters, such as petrophysical and production parameters, as well as non-continuous parameters such as geostatistical realizations and equiprobable matched models. In this new approach, the dispersion due to the non-continuous uncertainties is modeled in a rigorous statistical framework through the variance of the production recovery.

The method was successfully applied on data derived from a North Sea real field case. The objective was to quantify the impact of the principle reservoir uncertainties on the cumulative oil production and to optimize future field development in a risk analysis approach. The uncertainties were mainly on petrophysical data, geostatistical facies distribution and aquifer strength. The study was performed in the following steps: –sensitivity study. The most influential parameters were identified and the impact of geostatistical uncertainties was highlighted.–history matching. The influential parameters were constrained to the available production data. In particular, the geostatistical model was locally modified using both FFTMA technique and the gradual deformation method.–production scheme optimization. Experimental design and joint modeling were used to obtain probabilistic distributions of the optimized location of new wells in a non-producing zone.–risk analysis: Finally, probabilistic incremental oil production was obtained using Monte-Carlo technique.

Results show that this integrated methodology successfully enables to quantify the risk associated with the main reservoir uncertainties during the whole process of a reservoir engineering study (sensitivity, history match, production optimization and forecast).
Layered Modulus Effects on Fracture Propagation, Proppant Placement, and Fracture Modeling
Authors: Smith M. B. , Bale A. B. , Britt L. K. , Klein H. H. , Siebrits E. , Dang X.
Published: December 2007

Hydraulic fracture geometry (i.e., critical results of length and proppant placement) is driven by four major in situ parameters: Fracture Height (H), Modulus (E), Fluid Loss (C), and "Apparent" Fracture Toughness (KIc–app). In many (even most) cases, "Height" is the most important of these parameters –due to the need for some height confinement to achieve long fractures, or the need for height growth to insure good pay coverage. Due to this importance, industry research effort and most field measuring techniques concentrate on "eight." In particular, the growing use of seismic imaging is offering a tool to measure height growth away from the wellbore. Results from such diagnostics have often shown, as one expects, that in situ stress variations control height. However, results have also shown situations where this is apparently not the case.

This paper examines another in situ parameter, "Layered Modulus," which also affects height. In addition, by controlling the "local" width of a fracture, layered modulus (i.e., layered formations with different layers having significantly different modulus) can have a critical effect on final proppant placement.

The importance of layered modulus in directly controlling fracture height is illustrated in this paper, and this is compared with published solutions. In general, it is found that, just as concluded in the past, modulus contrast is probably not an important parameter in terms of direct control of fracture height. The greater importance lies in the effects on local fracture width. These local width changes can have a significant influence on controlling proppant placement – and this can be critical for low net pressure cases such as "water fracs" or fracturing in "soft" formations. It is also noted that layered modulus significantly impacts the average width of a fracture, and thus impacts the critical material balance aspects of fracture modeling if not properly accounted for.

Finally, some of the theoretical solution problems created by "Layered Modulus" formations for fracture modeling are discussed and compared. This is done by comparing with 3-D Finite Element (static) solutions, and shows how some common industry "approximations" for layered modulus give incorrect results. Based on this, examples with a fracture propagation model using a finite element-generated stiffness matrix are used to define types of cases where a simple "average" modulus is acceptable, versus cases where more complex calculations are needed.
When Fracturing Doesn't Work
Authors: Jennings Alfred R.
Published: December 2007

Well stimulation by hydraulic fracturing is one of the most unique of the commonly used oilfield practices. In spite of the fact that the treatments are relatively expensive and substantial permanent changes are induced in a fractured well, most of today's fracturing treatment applications are based on theoretical engineering relationships. For a treatment to be effectively ‘designed’, a myriad of treatment parameters must be considered using sophisticated fracture modeling software.

For those not experienced with fracturing, the development of a successful treatment approach may seem quite confusing. How does one know the ‘best’ or the ‘optimum’ fracturing treatment approach? Several related questions arise concerning candidate selection and methods to evaluate the effectiveness of the treatment.

The success of well stimulation by fracturing is readily observable through well response. Most often the response can be seen just hours after the treatment. Throughout its history, sufficient success has been achieved with fracturing that it has become one of the most widely used techniques for improving well productivity.

There are many instances where fracturing has not worked, or at least has not provided desired improvement in well productivity. Failure with fracturing always carries an economic impact whether it involves a single well or influences the feasibility of developing an entire field.

The purpose of this paper is not to provide an analytical treatise into all the reasons why fracturing treatments may fail. Rather, two approaches will be taken to address the topic "when fracturing doesn't work". The first will deal with the historical perspective and pertinent improvements in fracturing over the last 50 years will be discussed. Secondly, a series of common reasons for fracturing failures will be described. Finally, suggestions will be offered to provide further improvements in the success of application of hydraulic fracturing.
The Tools of Sand Management
Authors: Tronvoll J. , Dusseault M. B. , Sanfilippo F. , Santarelli F. J.
Published: December 2007

Sand Management is an operating concept where traditional sand control means are not normally applied, and production is managed through monitoring and control of well pressures, fluid rates and sand influx. In the last four years, Sand Management in conventional oil and gas production has been implemented on a large number of wells in the North Sea and elsewhere. In almost all cases it has proven to be workable, and has led to the generation of highly favorable well skins because of self-cleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher productivity indexes, and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed.

Different analysis and design tools are needed to evaluate sand production probability, to quantify risk reduction, and to establish practical operational criteria for safe and optimum production. Such design tools include the capacity to predict sand production onset, sand quantities and sand production rates, equipment erosion risks, and the conditions at which the sand can be transported inside the production liner and surface lines. Also, an essential tool is a sand monitoring technology to allow real-time quantitative sand flux tracking. The application of these tools and how they help assess risks in Sand Management are illustrated through field examples in this paper. Methods of handling the uncertainties and risks are discussed. Data from the North Sea, where active Sand Management was applied to increase well production rates, are presented. Finally, ideas on how to apply sand management and hybrid completions in challenging environments such as HPHT fields, marginal fields and complex structures are discussed.
Adding Value to Well Completions via Effective Wellbore Cleanup: Smart Thinking, Big Rewards
Authors: Kume Nicholas , Uzoho Forster , Ogoke Victor , Abiodun Afolabi F.
Published: December 2007

There has been a proliferation of horizontal and high angle wells in West Africa, particularly in the Niger Delta. High production/injection rates and the need to optimize recovery from complex reservoir structures have been a justification for these wells. It has been noticed by many operators in this region that most of the horizontal and high angle wells either came in at a lower than expected potential or simply did not sustain initially high production rates. This paper details how a systematic analysis of critical factors; causing limited or poor productivity in over 30 horizontal and high angle wells, led to the identification of opportunities that have been so far exploited by the operators in West Africa to deliver superior value from their investments.

This paper further shows that so far, a history of 100% technical success and greater than 200% improvement in delivering and exceeding projected potential production of treated wells has been achieved. Additionally there has been a consistent productivity improvement by using these techniques over all previously applied techniques, even for well draining from the same sands and having similar petrophysical characteristics. Payback time analysis on each well is included as part of the results. A technical comparison between treatment results from the New Combined Systems and the previously applied technologies (using a Normalised Productivity Index, Fluid rate, Skin factor and Well Inflow performance Indicators) is also included.

Results of laboratory tests showing treatment effectiveness and compatibility with drill-in and formation fluids are also discussed to demonstrate the application of these techniques to different reservoir mineralogies and oil compositions.
Assessment of Sample Contamination by Downhole NMR Fluid Analysis
Authors: Bouton J. , Prammer M. G. , Masak P. , Menger S.
Published: December 2007

A recently developed nuclear magnetic resonance (NMR) downhole fluid analyzer provides in-situ fluid characteristics at reservoir PVT conditions. The device is part of the Reservoir Description Tool (RDT*), a modular formation sampler and tester. This paper presents the theory and the experimental evidence that led to the use of NMR as a means to assess the amount of mud filtrate contained in the pumped formation fluid. In particular, the problem of differentiating oil base mud filtrate from connate hydrocarbons is difficult and has not been addressed by conventional measurements. NMR relaxometry uses the inherent differences in T1 time constant values and distributions to make these distinctions. The T1 data is available in real time and can be used to determine the optimum pump-out rates and durations while sampling reservoir fluids.
Imparting Directional Dependence on Log-Derived Permeability
Authors: Schön J. H. , Georgi D. T. , Fanini O.
Published: December 2007

Cost effective, efficient production of hydrocarbons depends on accurate reserves estimates, reservoir architecture, and hydrocarbon distribution. In addition, a complete reservoir description including both horizontal and vertical permeability is critical to efficient development strategy. Hydrocarbon recovery efficiency depends on many factors, but one key parameter is the ratio of vertical to horizontal permeability.

There are numerous ways to estimate permeability. It is now possible to estimate permeability from continuous formation evaluation measurements. However, it remains difficult to determine directional permeability. NMR logs are used routinely to estimate permeability, but NMR-derived permeability is based on scalar properties (e.g., ϕ, T2 distributions from NMR, bulk volume irreducible water) and is inherently a scalar property.

Few formation evaluation measurements provide directional information. Dip and image logs provide bed thickness and layer dip information. However, only the new multi-component induction instrument (3DEXSM) and crossed-dipole shear-wave acoustic tools provide direct measurements of macroscopic formation anisotropy.

In this paper, we explore theoretically and with real data the computation of permeability anisotropy. We use laminated sand models as well as macroscopic models based on the resistivity anisotropy measurements to estimate kv:kh ratios. In addition to multi-component induction data, we explore standalone and joint interpretation of NMR property variations to predict the macroscopic reservoir permeability anisotropy.
Use of an Integrated Approach for Estimating Petrophysical Properties in a Complex Fractured Reservoir: A Case History
Authors: Bona N. , Radaelli F. , Ortenzi A. , De Poli A. , Peduzzi C. , Giorgioni M.
Published: December 2007

Answering general questions such as "Where is the oil? How much oil is there? Can we extract it?" is a challenging task for a large fractured reservoir in Southern Italy. Various studies were conducted to gain more insight into the way the oil is distributed in the rock and the producibility of the different structures observable at the core scale (matrix, vugs, fissures). These included CryoSEM and GC-pyrolysis, pore size distribution measurements, SEM analysis on thin sections, and a number of non-conventional techniques that were specifically designed for that type of rock. NMR imaging was conducted on several whole core samples and the different porosity contributions (microporosity, vugs, and fissures) defined on a 3-D basis. An analytical approach based on the percolation theory was used to separate the permeability contributions and define the conditions under which vugs and fissures may form a conducting system. The inputs were distributions of pore throats, throat length, coordination number, fissure orientation and porosities. Wettability is a key parameter for production estimates, and we utilised a technique for measuring it in both microporosity and fissures, which makes use of dielectric constant measurements. All the data contributed to our current understanding of the reservoir.
The Beauly Oilfield - Creating and Sharing Value from a Marginal Discovery
Authors: Sherrard D. W. , Beckly A. , Howell P. , MacAskill A.
Published: December 2007

Beauly is one of the smallest developed oil fields in the North Sea with recoverable reserves of 3MMstb. A novel risk sharing contracting strategy involving owners, engineering contractors and transporters (collectively termed the Stakeholders) has delivered production of 10,000 b/d from a field which by most conventional measures would not have been developed. Initial good performance is being sustained and current expectations are that all Stakeholders will realise a successful commercial outcome. Key elements of the contracting methodology has been adopted by the North Sea industry body LOGIC for it’s Satellite Accelerator initiative.