bluuebunny/crossref_metadata_2025 huggingface dataset:
Critical Parameters in Static and Dynamic Modeling of Tight Fluvial Sandstones
Authors: Apaydin O. G. , Iwere F. O. , Luneau B. , Ma Y.
Published: December 2007

This paper presents an integrated static and dynamic evaluation for selecting an appropriate geostatistical modeling method that best represents the production from a tight, stacked fluvial sandstone reservoir.The critical parameters investigated include sand body geometry, water saturation permeability, and hydraulic fracture properties.This effort involves the construction of several static and dynamic models within a one-square mile section of the field.

The study area contains about twenty-four wells with varying productivity or EUR, indicative of the reservoir heterogeneity.Several geological scenarios were developed to characterize facies/sand bodies, and multiple realizations of each scenario were investigated.Reservoir properties including porosity, water saturation and permeability were populated for each realization using sequential Gaussian simulation.

The geological scenarios incorporated variations of three widely used facies modeling algorithms: fluvial object, defined object, and sequential indicator simulation.These algorithms have their pros and cons in representing the distribution of reservoir facies.The model constraints, including facies at wellbores, global facies proportion, vertical facies probability, and areal facies probability constructed from well data were held constant between the scenarios, and infill well locations were used to evaluate the static facies prediction.

Reservoir dynamic models were used to rank individual scenario performance.The static and dynamic models share the same grid dimensions and no upscaling of reservoir properties was performed.The grid system and the recurrent data (completion, production and pressure histories) for the wells were consolidated in schedule files for input into a reservoir simulator.While there were no attempts to match the historical performance of the wells, boundary conditions and/or constraints derived from field operation were determined and used as production controls for the wells.Average hydraulic fracture properties were assigned to the fracture cells of each well, and gas production under depletion drive was simulated with the flow models thus built.The results were evaluated qualitatively and quantitatively to select the appropriate modeling workflow for constructing the static and dynamic models of the field.
Adsorption Kinetics of Surfactant Used in CO2-Foam Flooding Onto Berea Sandstone
Authors: Bai B. , Grigg R. B. , Liu Y. , Zeng Z.
Published: December 2007

This paper reports adsorption/desorption kinetics and equilibrium onto Berea sandstone for a surfactant used as a CO2-water foaming agent. Also, foam stability of the surfactant is compared before and after adsorption/desortion has occurred. Results show that this surfactant's adsorption onto and desorption from Berea sandstone took several days to reach equilibrium. Both adsorption and desorption were characterized by a short period of rapid adsorption/desorption followed by a longer period of slower adsorption/desorption. Both adsorption and desorption processes were best fit by a pseudo-second-order kinetic model. Coefficients of adsorption and desorption rate were determined. A method to predict equilibrium adsorption density using adsorption process data over a relative short period is proposed, which saves considerable time in determining complete adsorption isotherms. Surfactant concentration and temperature affect equilibrium density. Foam stability is affected by selective surfactant adsorption onto the rock.
Cement Mechanical Property Measurements Under Wellbore Conditions
Authors: Reddy B. R. , Santra A. , McMechan D. , Gray D. , Brenneis C. , Dunn R.
Published: December 2007

Cement integrity preservation during completion, stimulation, production, and even, during well abandonment is of critical importance for an operator from long-term economic, productivity, and safety perspectives. Traditionally, compressive strengths have been considered indicators of cement integrity. However, numerous squeeze cementing jobs regularly performed on completed wells are testament to the poor correlation between compressive strengths and cement integrity. Additional mechanical properties such as tensile and flexural strengths, elastic modulus, and Poisson's ratio are being taken into account with increasing frequency for maximizing the cement sheath performance during the life of the well. Unfortunately, all such measurements are performed on samples that have been cured, either under wellbore conditions (for example, pressure and temperature), or laboratory conditions (for example, atmospheric pressure) but tested at atmospheric pressure and temperature. Such properties may at best be useful for comparing different formulations in the selection process but do not provide information about the cement properties under downhole conditions.

Using ultrasonic shear wave and compression wave combination measurements, dynamic mechanical properties, such as elastic modulus, bulk modulus, and Poisson's ratio and compressive strength, are measured under pressure and temperature. These measurements are compared with mechanical properties obtained from load vs. displacement under static conditions and acoustic compression and shear wave measurements at atmospheric pressure and temperature. Correlations are made for several slurries. The results are presented. The results also will present cases where the measurements made using this method demonstrated unique advantages over the conventional load vs. displacement techniques.
Integration of Geologic and Dynamic Models for History Matching, Medusa Field
Authors: Lach J. , McMillen K. , Archer R. , Holland J. , Depauw R. , Ludvigsen B. E.
Published: December 2007

Medusa Field in the Gulf of Mexico produces from turbidite sandstone reservoirs at depths between 10,000 and 14,000 feet. Production from the field commenced in December 2003, and six wells are producing at a rate of 40,000 BOE/D. Well A-3 is producing from the T4B reservoir at average oil rates in excess of 10,000 STB/D.

The late Miocene T4B reservoir was deposited in a turbidite channel/levee environment with extensive thin-bedded levee and isolated massive sand channel-splay facies. Stratigraphic cross sections and seismic amplitudes show rapid lateral change from levee to channel-splay facies. Depositional slopes, consisting of the east-facing levee flank and west-facing regional slope, and syn-depositional normal faulting control the location and thickness of channel-splay deposition. Conventional core in one T4B well provides information on depositional facies, reservoir properties and rock compaction.

The decline of reservoir pressure early in the producing life indicated that well A-3 was connected to a smaller oil volume than estimated from pre-production models. However later performance, the ability to sustain oil flow rate and a slowing of the rate of reservoir pressure decline, suggested communication between the higher quality channel-splay and levee facies and a larger OOIP than indicated by the early performance. The eventual rise in producing gas-oil ratio and the onset of minor water production also affected the well's performance.

Simulation history matching commenced using pre-production reservoir characterization models with the objective to forecast well A-3 production and to evaluate the potential for a previously planned second well completion in the zone.Traditional history matching using the original static model was not satisfactory.

MEPO®, an optimization tool for assisted history matching, was used to complete the history match study. Multiple equiprobable history matches were obtained varying fault and facies transmissibility, fluid PVT, rock compaction curves, and critical gas saturation. The reserves and production profile risk for a future well completion have been evaluated with a range of the history match results.
Reconciling Prior Geologic Information with Production Data Using Streamlines: Application to a Giant Middle-Eastern Oil Field
Authors: Fenwick D. , Thiele M. , Agil M. , Hussain A. , Al-Humam F. , Caers J.
Published: December 2007

Effective history matching of real fields requires the resolution of two outstanding problems. First, a conflict may exist between the production data and the existing geological model built solely from static information. In resolving this problem one must relate the inherent multi-scale nature of production data to petrophysical properties of the reservoir at the proper scale. Second, during model updates, geological consistency must be maintained by honoring the prior geologic information. The geoscientist has to choose what prior information is well know (hence fixed), and what is uncertain (hence modifiable). In many instances, the type of geostatistical algorithm is fixed, while key prior geostatistical parameters should be perturbed (e.g. facies proportions, petrophysical properties trends, variogram parameters, and random seed).

We propose a new methodology that addresses these problems. First, streamlines are used to relate the production data to petrophysical properties at multiple scales. A combination of geostatistical tools (locally varying mean and probability perturbation method) are then used to jointly map multi-scale corrections back to the geological model through changes of the prior geostatistical parameters. The mapping reconciles the fixed prior geologic information with the production data. The geological model is then explicitly recreated by re-running the geostatistical simulation. This approach differs from other history matching techniques where the petrophysical properties of each grid block are modified directly. While a successful history match may be obtained, the resulting model may be inconsistent with important prior information, hence retaining little predictive power.

The methodology is demonstrated by applying it to history matching a giant Saudi Arabian carbonate oil reservoir. This reservoir has over 500 producers and over 50 years of historical data with dramatically changing field conditions. In the past, several attempts were made to manually history matching this reservoir. The process was found to be extremely time consuming, involving dramatic local permeability changes which are often not supported by geological data. By applying the new approach, rather than correcting permeability manually, the corrections supplied by the streamlines were used to constrain the geostatistical algorithms, thereby ensuring a consistent geological scenario at every iteration.
Pseudosteady-State Analysis of Finite Conductivity Vertical Fractures
Authors: Meyer B. R. , Jacot R. H.
Published: December 2007

A new solution methodology for pseudosteady-state behavior of a well with a finite-conductivity vertical fracture is formulated using a reservoir/fracture domain resistivity concept. The formulation encompasses a transformed resistivity domain based on an equivalent or effective wellbore radius. The resulting pseudosteady solution is presented in the form of the dimensionless productivity index (JD).

Some of the major advantages of this pseudosteady solution for finite-conductivity vertical fractures are 1) the methodology is based on fundamental principles, 2) the solution is analytical and easily implemented, 3) the equations are formulated for rectangular reservoirs, 4) the model includes wellbore flow (i.e., wellbore radius effect) which is important for low-conductivity fractures, and 5) the formulation accounts for a piece-wise continuous linearly varying fracture conductivity including: proppant tail-ins, over-flushing, pinch zones, choked flow (internal), and external skin mechanisms.

The stimulation ratios for finite-conductivity fractures with an undamaged well are compared with those of McGuire and Sikora1 (1960), and Holditch2 (1974). The accuracy and validity of the pseudosteady model is also illustrated by comparison with the works of Prats3,4 (1961,1962), Gringarten et al.5,6 (1974), Cinco-Ley et al.7–10 (1978,1981), Barker and Ramey11 (1978), and Valko and Economides12 (1998).

A summary of the fundamental building blocks, effective wellbore radius concept, pseudo-skin functions and fracture skin are discussed. An improvement to Gringarten's dimensionless productivity solution for infinite-conductivity vertical fractures in rectangular closed reservoirs is also presented.
Analysis of Best Hydraulic Fracturing Practices in the Golden Trend Fields of Oklahoma
Authors: Mohaghegh S. D. , Gaskari R. , Popa A. , Salehi I. , Ameri S.
Published: December 2007

In the past decades several hundred stimulation procedures have been performed in the Golden Trend fields of Oklahoma. The outcome of these stimulation jobs have not been the same for all wells. The effectiveness of the stimulation is a function of several factors including reservoir quality, completion and stimulation techniques. Completion and stimulation techniques can be further itemized as completion type such as open hole versus cased hole, type and amount of fluids and proppant and the rate at which they are pumped into the formation.

This project was supported by DOE and GTI in connection with the DOE's Preferred Upstream Management Practices (PUMP) project. The project was implemented in three fields in the Golden Trend in Oklahoma. Detailed production and completion data analyses revealed that the most influential controllable parameter effecting the production rate and ultimate recovery was fracture stimulation, and as such, the bulk of efforts were focused on determination of optimized hydraulic fracturing procedure. Detail stimulation data from more than 230 wells in the Golden Trend fields of Oklahoma operated by three independent operators were collected and analyzed using a new best practices analysis methodology.

The study was performed for gas and oil bearing formations. Among the findings of this comprehensive study were the best stimulation practices in carbonate formations that are primarily gas producing, and clastic formations, from which both oil and gas are produced. During his study authors were able to identify the best type of fluid, the most optimal injection rate and proppant concentration for both types of formations.

In this paper application of a new methodology that was used to perform the best practices analysis on the Golden Trend fields of Oklahoma is presented.
Experimental Investigation of Miscible Secondary Gas Injection
Authors: Kulkarni M. M. , Rao D. N.
Published: December 2007

Our earlier experimental work1 on tertiary mode gas injection indicated that the gas injection strategy, either continuous (CGI) or alternating with water (WAG), did not have a significant effect on recovery during immiscible gas injections. This paper examines the effect of gas injection strategy on recovery in miscible gas injection projects. Here we compare the effects of injection strategy (namely secondary and tertiary) on horizontal type, miscible continuous gas injection (CGI) and Water-Alternating-Gas (WAG) processes.

The secondary miscible corefloods demonstrated high oil recoveries in both CGI and WAG mode of injection, attributable to higher initial oil saturations and the high capillary numbers achieved due to miscibility. The flood performance was analyzed using the conventional recovery plots as well as the tertiary recovery factors, TRF, defined as the oil recovery per unit volume of gas injected. Comparison of the TRF plots for secondary and tertiary gas injections, clearly demonstrate the beneficial recovery effects of gas injection early in the life of the flood. On the other hand, the WAG floods demonstrated higher gas utilization factors than those in CGI under secondary mode of injection. The water shielding effect, responsible for delayed oil breakthroughs in tertiary floods, was observed to be minimal in the secondary WAG floods. This work reconfirms that the optimal injection strategy consists of a combination of CGI and WAG modes of injection, which appears to be independent of whether the gas injection is carried out as a secondary or tertiary process.
Can Large Domain of Uncertainty Be Reduced for Two One-Well Fault Blocks?
Authors: Macary S. , Ball B. , Baramawy M.
Published: December 2007

Two fault blocks, each containing one producing well, are part of a multiparty concession. Both blocks were tested by a major oil company in the mid 80's but proved to be non-commercial at that time and the wells were abandoned. Two further wells were drilled in early '01 and late '03 and have been on production since then. The short production history is common today for many companies pursuing marginal oil accumulations. Recent high oil prices have enabled viable production but the degree of uncertainty makes it difficult to diagnose reservoir performance and identify the best alternatives for future reservoir development.

The producing mechanism for the two fault blocks is believed to be depletion drive. However, high dip with some evidence of fracturing indicates possible improved recovery via gravity drainage. Material balance calculations utilizing limited production history, few pressure measurements and uncertain PVT data make it difficult to resolve OOIP, prevailing drive mechanisms, and ultimate recovery.

The BPP is also uncertain which consequently affects material balance.Accurate PVT data will give confidence in resolving the issue of whether a fault separating the two blocks is leaking.This fault is thought to be partially non-sealing as indicated by few uncertain pressure measurements, which complicate interpretations and decisions regarding further development.

The offshore location limits artificial lift or secondary recovery options. Production capacity is allotted from a shared facility and future decisions will require agreement among the involved parties. These concerns, in addition to considerable G & G unknowns regarding seismic definition of structure, facies variation, poroperm characteristics etc., generate a large domain of uncertainty. This is exacerbated by the interests and visions of the different partners and local regulations.

The best solution starts by an interdisciplinary team approach to enhance the understanding and potential impact of all available data through expert analysis and thoughtful integration. This results in more effective decisions regarding reservoir management and further development. PVT acquisition, multiphase metering, static modeling, reservoir simulation and infill drilling are some steps of an aggressive plan to develop this Concession.
Viscosity of Formation Water: Measurement, Prediction, and Reservoir Implications
Authors: Alboudwarej H. , Muhammad M. , Barrere C. , Archer R. , Hannan R. , Jones T.
Published: December 2007

Formation water is invariably produced with petroleum. An estimate of the dynamic viscosity of formation water as a function of pressure, temperature, salt content and preferably dissolved gas, is required for reservoir and petroleum production design and calculations. The extent of available experimental data on the viscosity of live formation water is very limited. In addition, most of the proposed brine viscosity correlations are based on the experimental data of NaCl solutions with no dissolved gas.

Several reconstituted formation water samples were tested in the present study. The total dissolved solids content of the water samples varied between 90,000 to 250,000 mg/L at a gas/liquid ratio of approximately 9.6 scf/stb. Viscosities were measured up to 14,000 psia and temperatures up to 200 °F using both capillary and electromagnetic viscometers calibrated with standard fluids for the interested range of pressure and temperature. Experimental results indicated that viscosity of formation water increases with increasing solids content and pressure as well as with decreasing temperature. The presence of dissolved gases decreased the viscosity of formation water; however, it was not significant. Experimental results were compared against water viscosities predicted by commonly used formation water viscosity correlations. The relative errors for some cases were as high as 200 %. Most correlations over-predicted the viscosities at higher pressures beyond 10,000 psia.

Comparison between reservoir simulation case studies for a base case and 30%-varied formation water viscosity case showed that both predicted oil and water production and water cut during the life of the producing well are significantly affected by the value of the formation water viscosity input.
C-Curve And Independent Oil-Rate And Oil-Cut Decline
Authors: Cunningham P. R. P. , Lecompte M. N.
Published: December 2007

Decline analysis is an important working tool, particularly for reserves evaluation in producing fields. However, its theoretical foundations are not fully understood and much work remains to be done to develop the theory and application of the method.

Based on practical experience of fitting decline curves to both field production and reservoir simulation results, the authors have identified two short-comings of conventional decline analysis, together with partial solutions to these problems. It is estimated that the two improvements together will lead to a significant improvement in the accuracy of decline analysis reserves evaluation.

The first problem is that of the limitations of hyperbolic curves and other alternatives to exponential decline. When field production or reservoir simulator results show non- exponential decline, the decline rate usually reduces in time (e.g. from 25% per annum to 15%, 10% etc), until levelling out and then continuing at a more-or-less constant rate (e.g. 5% per annum). In contrast, hyperbolic curves show decline rates than keep on reducing, eventually heading to a zero decline rate. In consequence, hyperbolic decline curves can give rise to unrealistically high ultimate recovery values. Instead of hyperbolic curves, an alternative generalisation of exponential decline is presented – the "C" or "cumulative" curve. These curves take a simple form; they include hyperbolic curves as a subset; and they allow the late-time decline rates to approach a non-zero asymptote.

The second problem is that there are cases where fitting a decline curve to the oil-cut curve gives a very unrealistic prediction of oil-rate, and vice-versa. A way of addressing the problem that has been found to be very successful is to fit independent decline curves to oil-cut and oil-rate and then use both simultaneously to predict how the gross-liquid production rate varies with time.
A Rapid, Rigsite-Deployable, Electrochemical Test for Evaluating the Membrane Potential of Shales
Authors: Al-Bazali T. M. , Zhang J. , Chenevert M. E. , Sharma M. M.
Published: December 2007

The membrane efficiency of shales is usually measured in the laboratory using pressure transmission techniques that can be very time consuming and require shale core samples that may not be available.These tests also require special high pressure equipment and cannot be conducted at the rig-site.

This paper presents a quick and relatively easy method for obtaining the membrane efficiency of shale cuttings (or cores) through electrochemical potential measurements. The electrochemical test measures the voltage drop across shales that are in contact with fluids of different salinities.The measured voltage drop is used to calculate the shale's ion selectivity, which reflects the shale's ability to restrict ion flow (membrane potential).Data are presented to show the influence of ion type and concentration, shale permeability and CEC on the ion selectivity.It was found that the shale membrane efficiency is well correlated with the membrane potential. The membrane potential is shown to be proportional to the ratio of the cation exchange capacity and permeability of shales.A higher cation exchange capacity to permeability (CEC/k) ratio correlates very well with higher ion selectivity. The rig site measured ion selectivity can be correlated with the spontaneous potential (SP) curves in the well.

The rapid determination of shale membrane efficiency using shale drill cuttings allows chemical interactions between shales and water-based fluids to be taken into account in wellbore stability calculations without the need for shale core samples.
Optimal Stimulation Treatments in Tight Gas Sands
Authors: Holditch S. A. , Tschirhart N. R.
Published: December 2007

Hydraulic fracture stimulation can improve the productivity of a well in a tight gas reservoir because a long conductive fracture transforms the flow path natural gas must take to enter the wellbore. Fig. 1a illustrates radial flow in the reservoir when no hydraulic fracture has been created. As can be seen, all of the gas must converge radially to a very small area called the wellbore. For a radial flow pattern, most of the pressure drop in the reservoir occurs near the wellbore. Figs. 1b and 1c show what the flow path of natural gas from the reservoir to the wellbore looks like after a successful fracture stimulation treatment. At early time, Fig. 1b, natural gas enters into the fracture from all points along the fracture in a linear fashion. The highly conductive fracture rapidly transports the gas to the wellbore. At late time, Fig. 1c, the gas in the reservoir is flowing towards an elliptical pressure sink and most of the gas enters near the tip of the fracture. Conventional wisdom in designing hydraulic fracture treatments for tight gas sands would suggest that successful stimulation of tight gas sands requires creating a long, conductive fracture filled with proppant opposite the pay zone interval. This is accomplished by pumping large volumes of proppant at high concentrations into the fracture using fluids that can transport and uniformly distribute proppant deeply into the fracture.

As fracture treatment technology has evolved, the trend has been to use more viscous fluids carrying higher concentrations of propping agents to create long, conductive fractures in tight gas sands. In the 1960's, slick water carrying very low concentrations of proppants (around 1 lb/gal) were used in many situations. These treatments were called water fracture treatments1. In the early 1970's, more viscous fluids were developed that were capable of carrying 5-6 lbs/gal of propping agents2. By 1980, delayed cross-linked polymer fluids were allowing the industry to pump treatments carrying as much as 10-12 lbs/gal of proppant3. The trend in the industry was to pump more proppant, to create the long, conductive fractures needed to optimize production from tight gas reservoirs.

Basic reservoir engineering calculations can be used to show that gas recovery and deliverability will be a function of propped fracture length and fracture conductivity in the reservoir interval. As the hydraulic fracture length and conductivity increase opposite the pay interval, the well will produce more gas at higher flow rates4.
Managing Deepwater Flow Assurance: Unique Riser Design Allows Dual Annuli Thermal Insulating Fluid Installation
Authors: Javora P. H. , Wang X. , Burman J. W. , Renfro K. D. , Weaver M. , Pearcy R. , Qu Q.
Published: December 2007

Flow assurance is one of the major considerations when designing a deepwater completion where undesired heat loss through the deepwater riser accelerates the formation of gas hydrates and the deposition of paraffin and asphaltene. In addition, any planned or unplanned shutdown of the well for various well operations for an extended period can result in critical heat loss, which then requires an extended warm-up time to restart the well. In some scenarios, restart of the well becomes impossible without assistance from chemical injection, unless of course, proper thermal insulation was implemented beforehand. Field applications of thermal insulating fluids have demonstrated significant reductions in heat loss by reducing conduction and minimizing thermal convection of the fluid. Such thermal insulating fluids have been applied with great success in many deepwater riser applications during the last several years.

For this major deepwater project in the GOM, "how to manage flow assurance" had been identified as key to success of the project from the very beginning of the planning phase. This paper details the selection criteria used in the riser insulation design for the project. Evaluation of several insulation options and combinations of options will be discussed, and the final selection of the preferred insulation method will be presented. The unique design of the deepwater riser enabled the operator to maximize the insulation efficiency by the proposed thermal insulation fluid and to meet the most stringent thermal insulation requirements of this project. Data from downhole temperature and pressure gauges and from the fiber optic DTS system will be presented.
Precommissioning to Startup: Getting Chemical Injection Right
Authors: Willmon J. G. , Edwards M. A.
Published: December 2007

The following paper will detail lessons learned from practical field experiences concerning the design, construction, and commissioning of a production chemical program for a green (new) field development. A competent program will require the interaction of various specialty products and services suppliers, including experts in flow assurance, modeling, fluid analysis and specialty chemicals. All are engaged in the early stages of the project and retained as resources throughout.

Areas addressed for the design and implementation of a chemical injection system include: Exploration: Collected bottom-hole samples are used for fluid characterization and risk assessment of any flow assurance issues. From this initial data, prevention and mitigation strategies, including but not limited to chemical inhibition, are developed. Chemical products can be developed and/or screened for effectiveness and applicability from this initial assessment. This includes performance screening, chemical-chemical compatibility testing, chemical-material compatibility testing, and product stability (which are particularly important for umbilical applications).Facility Design: Specifications for the processing system and equipment are detailed; materials of construction are screened for chemical and fluid compatibility, volume and deliverability requirements determined, and the chemical injection system are designed.Facility Construction: Monitoring and oversight throughout the construction process is performed to maintain the integrity of the initial design.Operational Strategies: Strategies will be developed addressing initial flow-back, start-up, steady state, and shut-in techniques.Logistic Strategies: Strategies will be developed addressing logistical concerns (product transfers and hand-overs).(Pre) Start-up commissioning and testing of equipment: Cleanliness and operability of the system is an absolute must. The chemical day tanks and injection lines are flushed to specification.

Chemical injection issues can be successfully managed in new (Deepwater) projects by: proper fluid characterization and risk assessment, field development strategy that includes design, specialty treating chemicals and operating plans, the involvement of specialists and specialty providers, and training and communication ensure safety and success.
Value of Information for Appraisal of Multiple Dependent Prospects
Authors: Kumar R. , Hara S. K.
Published: December 2007

Two common challenges in the appraisal of deeper prospects in deepwater are, the selection of the overall strategy -campaign or sequential, and justification of any individual activity in this high cost environment. Both require objective assessment of the Value of Information.

When dealing with multiple adjoining prospects, which not only have subsurface dependencies in their uncertainty characterization, but also dependent development concepts, the value of appraisal appears to be intuitively high. However, quantifying such VOI is extremely challenging since the different combinations of subsurface realizations and development scenarios propagate into millions of economic realizations. Furthermore, the time and effort needed to update the analysis for new information is nearly as great as for the first complete iteration.

Traditionally such a problem would be solved using three branches for volume uncertainty (Low, Mid, High) for each of the prospects; details are lost in the analysis that may result in the VOI being non-representative. This paper presents a methodology that samples the probability density function more exhaustively but does so very efficiently w.r.t calculation overhead. A two-pronged approach is adopted: Defining a nearly exhaustive range of the discrete combinations of subsurface volumes from different prospects, then "binning" these possibilities in volume to create a representation of the frequency distribution.Recursively pre-calculating the economic simulations for numerous combinations of bins of volumes for different development concepts / strategy

This methodology enables studying the problem in much greater detail and also decreases the turnaround time to update the expected economic value and VOI as new data is gathered and other insights are gained. The probability density function can be quickly updated when only the probabilities change while the realizations and scenarios remain unaffected.

This paper demonstrates the application of the above approach in evaluating appraisal VOI for a set of adjoining prospects in deepwater Gulf of Mexico that are both geologically dependent and share potential development synergies.
High-Tech Tools Improve Petroleum Industry Human Resource Management
Authors: Rueff S. , Thomas J. , Lee W. J. , Weatherford D. -J.
Published: December 2007

Career paths in the petroleum industry no longer follow the straight line from college graduation to the gold watch at retirement; in fact, job mobility has become an indicator of an employee's ability and ambition to compete. Furthermore, industry reorganizations over the last decade have led to a workforce that is scattered, aging, and nettled by shortages in key discipline skills that are likely to be filled by an increasingly international workforce. High-tech e-staffing systems offer today's mobile jobseekers access to worldwide oil and gas industry employment opportunities and offer employers tools that provide fast, efficient, economical access to international professional personnel.
Carter Creek Slimhole Well Design Enhances Development-Drilling Economics
Authors: Weatherl M. H. , Marshall J.
Published: December 2007

Starting in late 1997 a major development drilling campaign was undertaken by Chevron in the Carter Creek Field in Southwest Wyoming. The sour gas reservoirs at +/-15,000’ TVD were targeted to increase production and improve ultimate recovery in this mature area. Between 1997 and 2002 15 new wells were drilled and completed as a part of this effort at approximately $8 million per well. The formations in this part of the Rocky Mountains are characterized by complex geology, hard abrasive formations, plastic salt, and high concentrations of hydrogen sulfide gas (16%). Additionally, the field is located on environmentally sensitive federal lands. Directional drilling is generally necessary to reach the desired bottom hole locations from the available surface access routes.

Overall, the program was very successful, resulting in 5-8 BCF of incremental gas reserves per well. However, by late 2002, bottom hole pressure had declined to the point that the new wells were becoming marginally economic. Although a core area and major capital project for the operator, it became clear that the remaining reserves could no longer support the associated well construction cost. The viability of a large gas plant and more than 100 BCFG recoverable reserves were at stake.

During 2002 and early 2003 multi-discipline team work was undertaken to assess possible alternative well designs utilizing a variety of risk analysis tools. The result was a slim hole well design enabling the use of a smaller drilling rig and an overall savings which to date has approached $1 million per well. This paper details the evolution of a new well design which balances geological and production objectives with the increased risk related to a smaller hole size. At present, the new well design is being utilized at increasing depths with continued efficiency gains. The associated well construction cost savings have become instrumental in maximizing value from this important asset.
New Solutions To Extend the Application Window of Horizontal Openhole Gravel Packing
Authors: Pedroso C. , Sanches E. , Oliveira N. , Fernandes L. , Mickelburgh I. J. , Coelho G. S.
Published: December 2007

Introduction

Open hole gravel packing using the alpha/beta wave placement technique, has become the completion of choice for many operators developing fields with horizontal wells in unconsolidated sands. The interrelationships of the gravel placement parameters in these wells are well understood, and the process can be effectively modeled. However, for completions in deep and ultra deep water, difficulties limit the use of this technique.

New solutions are required to overcome the challenge of successfully packing through shale intervals, and to reliably overcome the gravel placement limitations imposed by low frac gradients. This paper presents the solutions currently in use and provides an application example using a new solution.

Horizontal Open Hole Gravel Pack (HZ-OHGP) Techniques

Successful gravel packing of long horizontal open holes has been achieved with two alternative gravel placement techniques – alternate path (A/P) and alpha/beta (A/B).
Fracturing for Sand Control: Screenless Completions in the Yegua Formation
Authors: Ellis V. R. , Cormier G. , Adams G. , Santos F.
Published: December 2007

Natural completions in the Yegua formation have resulted in failures caused by formation-sand production and wellbore collapse. In the past, the most popular remedy was small fracturing treatments with gravel-pack screens to control the production of formation material. Designing the completions specifically for wellbore stabilization, sand control, and maximizing the conductivity endurance, has resulted in techniques that eliminate the need for gravel-pack screens, helping to simplify completion operations and minimize cost. Field data, including logs and production history, have been used extensively for the purpose of verifying this technique. The completion technique includes several key components: Perforations—The interval length, along with perforation phasing and orientation, have shown to be the most important aspects of a successful completion.The use of resin-coated proppant and conductivity endurance modifiers (CEMs) are used to aid in stabilizing the proppant pack and demobilizing fines.The fracturing treatments are designed to maximize fracture width and decrease the pressure drawdown near the wellbore during production.

Several wells have demonstrated the effectiveness of this technique (frac-pack stimulation without gravel-pack screens) by producing no formation fines or proppant. These results are documented by several case histories comparing previous techniques to current techniques.

The application for this technique reaches further than the Yegua formation of east Texas to include any formation with similar properties. This technique provides extra benefits for wells with multiple zones by reducing the completion cost and minimizing the complexity of the wellbore for future entries.

In summary, by properly designing the completion of the Yegua Sand formation and applying curable resin-coated proppant or CEM's, sand control has been achieved without the use of screens. This technique has reduced the overall completion cost, simplified the wellbore configuration, delayed or eliminated casing collapse in Yegua producers, improved total gas recovery, and reduced well down-time.
Multiproduct Pipe Transport Conversion of Abandoned Single Product Pipelines
Authors: Davis C. , Fagan J.
Published: December 2007

This paper explores the potential of utilizing large diameter steel pipelines, that are no longer in use, to simultaneously transport small batches of different products. These pipelines were originally created in the United States to transport gas from the south to the north. As Canada emerged as a gas supplier to the northern states, these pipelines were no longer needed for their original purpose. Many of these pipelines were completely abandoned because an alternate usage was not identified for transporting large quantities of a single product. With these pipelines obsolete, building new smaller diameter pipelines was the only solution considered to accommodate the present need.

To accomplish the necessity of economically transporting small batches of product, multiple pipes are inserted into these large diameter steel pipelines. Polyethylene (PE) was selected as the piping material for this application because of the flexibility and tensile strength required during the insertion process. A method was developed to insert 10-mile sections of the PE pipes into the steel pipeline. Once these PE pipes are installed, a method of controlling and monitoring the flow is required. The control system allows the outputs to be maximized without causing failures such as bursting or leaking. Furthermore, to assure economical feasibility, performance benchmarks were proposed by industrial partners.

The model produced from this study analyzes steady state operation as well as transient effects such as opening/closing a valve or starting/stopping the pipeline. New formulas are derived to calculate frictional pressure drop for fluid flow in pipes containing internal pipes. National Instruments Lab-View, a graphical programming language, was used to transform the mathematical model into a real-time operational tool that can be directly connected to the pipeline system.
Successful Stimulation of Sandstones in the Dulang Field, Malaysia, Using Surfactant-Based Diverter: A Novel Solution for Mature Fields
Authors: Ali A. , Hashim A. H. , Hashim F. , Said R. , Nair D. S. , Chan K. S. , Samuel M.
Published: December 2007

Dulang is the major oilfield in the Malay Basin. Owned by the Malaysia national oil company, Petronas, it is located in the South China Sea, about 130 km offshore the east coast of Peninsular Malaysia in water depths of about 76 m. This field, consisting of sandstone formations, was discovered in 1982 and developed fully in 1991 resulting in 48 wells being drilled and produced. Currently, the reservoirs in this field are nearly depleted, having many idle wells with high Gas Oil Ratio (GOR) and water cut (up to 95%).

An attempt was made to revive the idle wells with potential recoverable reserves. A collaborative team was formed to devise a solution. The main focus was given to idle wells with high water cut. The objective was to increase oil production and reduce water cut. A number of options were reviewed, with one of the strategies being to increase oil production by shutting the water/gas production. However, due to various operational challenges that these well possess, (i.e. difficulty in mechanical isolation due to dual completion and availability of multiple water/oil zones) no direct approach could be employed.

In order to keep the drive and market of idle wells afloat, a different strategy was proposed and marketed which focused on increasing the oil production with little or no water increase. The water cut in response to this strategy would be expected to be either maintained or decrease resulting in higher oil production. The introduction of matrix acidizing utilizing a high temperature viscoelastic surfactant-based diversion system has made it possible to achieve such results.

A high temperature viscoelastic surfactant-based diverter was engineered to selectively plug the zone with high water saturation, allowing the treatment system to enter the zones with high oil saturation. Another advantage over the conventional particulate diverters is that it contains only a surfactant and does not have any solids or polymers. This paper discusses application and results of using high temperature viscoelastic surfactant-based technology in the Dulang fields.

This paper will also cover candidate selection, pre-job laboratory testing, execution and evaluation challenges in order to properly execute the job. Candidate selection, which is the most crucial task in this project, determines the right and potential candidates for the treatment. Extensive laboratory experiments, such as crude oil and acid compatibly (emulsion and sludge tests), and core studies (SEM, XRD, core flow, etc.) have been carried out to develop the most effective acid recipe. Previous treatment results will also be discussed in this paper. The success of the treatment in Dulang has proven the potential success of the application of this high temperature viscoelastic surfactant-based diverter for selective stimulation of high water cut oil wells.
Offshore Safety Division's Response to Concerns About Installation Integrity on UKCS
Authors: Cutts S.
Published: December 2007

This paper outlines the delivery of a key programme (KP3) being undertaken by the Health & Safety Executive's Offshore Safety Division (OSD) to address integrity concerns offshore. The approach and findings of the structured inspection programme are discussed, together with an analysis of both weaknesses and strengths. The participation of industry stakeholders is acknowledged as key to achieving an upturn in integrity performance and so minimising the potential for accidents.
Ultraslim Rotary-Steerable System Enhances Brownfield Production
Authors: Kholy K. E. , Kuyken C. , Kleverlaan M. , Saul D. , Andersen S. , Kirkemo E.
Published: December 2007

Schlumberger has worked collaboratively with Shell U.K. Limited (Shell), BP and Statoil to develop a 3 ¼-in. ultra slim through tubing rotary steerable system (RSS) with the objective of extending the production profile of offshore maturing fields. Through tubing rotary drilling (TTRD) is a very attractive option for enhanced reservoir development at low cost. Current methods use motor bottomhole assemblies (BHAs) in TTRD applications, but these have limitations. The introduction of the RSS will extend the reach of TTRD to pursue more distant targets, enhance production through precise directional control, improve drilling performance, reduce drilling cost, and improve ultra slimhole hydraulics. The tool has entered its field test stage and has two successful downhole runs to date.

This paper provides a brief overview of TTRD as a method of sustainable development of mature oilfields (brownfields). A detailed overview of the tool development is given, including the main milestones and a system description. The joint RSS development project is presented as a best practice in industry collaboration and a good example of a collective visionary approach to future brownfield development.