bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field-Data-Based Prediction of Well Productivity Decline Due to Sulphate Scaling
Authors: Bedrikovetsky P. G. , Monteiro R. P. S. , Daher J. S. , Gomes J. A. T. , Amorim V. C. 
Published: December 2007

AbstractThe system where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation. We derived an analytical model-based method for determination of kinetics and formation damage coefficients from production well data consisting of barium concentrations in the produced water and of well productivity decline.We analyse production data for five scaled-up producers from giant offshore field A, submitted to seawater flooding (Campos Basin, Brazil) in order to predict productivity index and to plan the well stimulation program. The wells are completed by gravel packs. Complete mixing of sea and formation waters in production well neighbourhoods in the reservoir under consideration was assumed in previous works. Using this assumption, quasi steady state model for reactive flow around production well is formulated. We obtained values of the two sulphate scaling damage parameters. The two coefficient values were used for prediction of productivity decline for these wells.Both coefficient values as determined for five wells are inside the variation intervals for scale damage coefficients obtained from coreflood data. It allows concluding that the productivity damage in wells under investigation was caused by sulphate scaling and validates the mathematical model. It also permits to perform a reliable prediction of well productivity. The values for kinetics and formation damage coefficients as obtained from well and laboratory data are recommended for use in reservoir modelling of sulphate scaling.Sulphate scaling can have a disastrous impact on oil production in waterflood projects with incompatible injected and formation waters. This is due to precipitation of barium / strontium sulphate from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity.
Incorporating Geomechanics into Petroleum Reservoir Numerical Simulation
Authors: Rodrigues L. G. , Cunha L. B. , Chalaturnyk R. J. 
Published: December 2007

Abstract
There is currently a need in rock engineering for a coherent approach, which allows the identification and incorporation of the important parameters and mechanisms for any rock engineering activity. This is the case of reservoir numerical simulation studies of oil/gas recovery strategies in which geomechanical effects play an important role on the underlying physics of the recovery process. For example, during the depletion phase or the cold-water injection of high-pressure/high-temperature reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, improvement of natural fractures, induced fracturing, and fault activation, which continuously modify the reservoir properties such as the porosities, the permeabilities and the fault transmissibilities. Modifications of such parameters strongly influence the flow pattern in the reservoir and ultimately the final recovery factor. In this work, a methodology is developed which enables the incorporation of key mechanisms and parameters to solve a numerical reservoir simulation problem that considers geomechanical aspects. The proposed technique utilizes an iterative-coupled reservoir-geomechanical modeling approach to capture the link between flow and in-situ stresses. In a validation stage, results from the coupled model are compared to ones obtained from a classical simulation approach (constant rock compressibility model). The usefulness of technique developed here is illustrated for reservoir performance forecasting of a giant Brazilian deepwater oilfield producing by water injection. The solution achieved to the real case problem revealed important geomechanical features that must be considered in complex oil exploitation project scenarios in which limited information and production uncertainties are present.
Modeling Rapid Multiphase Flow in Wells and Pipelines Under Nonequilibrium and Nonisothermal Conditions
Authors: Michel Guillermo , Civan Faruk 
Published: December 2007

Abstract
An improved mathematical model considering the nonequilibrium and the non-isothermal effects involved during rapid multiphase flow in wells and pipelines is presented. The extent of the non-equilibrium effect on deviation from the equilibrium model predictions is delineated under prevailing flow rates, fluid saturations, and temperatures. Applications for three-phase (oil/water/gas) systems are presented. The model presented here can be coupled with reservoir simulation for accurate representation of the well-fluid hydraulics and simulation of flow conditions in pipelines under nonequilibrium and non-isothermal flow conditions.
Estimation of Reserves Using the Reciprocal Rate Method
Authors: Reese P. D. , Ilk D. , Blasingame T. A. 
Published: December 2007

Abstract
In this work we develop, validate, and apply the "reciprocal rate method" to estimate oil reserves using only rate-time production data. This approach requires the development of boundary-dominated flow, and can be used to validate reserve extrapolations from numerical/analytical reservoir models. The methodology does presume that flowing well bottomhole pressures are approximately constant — but we will demonstrate that the method is tolerant of substantial changes in the flowing bottomhole pressure.
This approach requires a plot of the reciprocal of flowrate (1/q) and the so-called "material balance time" (cumulative production/flowrate or Np/q). The "secret" to this approach is the use of material balance time — this function accounts for most variation in rate/pressure, and permits the extrapolation of the 1/q function.
This methodology has been applied for oil wells (including oil wells with high water production) — and in all cases, the reciprocal rate method has proven to be robust and consistent.
The primary technical contributions of this work are: Direct method to estimate reserves using only rate-time data (time, rate, and cumulative production).The reciprocal rate method is based on variable-rate theory, and is more rigorous than Arps approach (exponential or hyperbolic rate relations).
A Numerical Two-Phase Flow Model Coupling Reservoir and Multisegment Horizontal Well
Authors: Gui Ping , Cunha L. B. , Cunha J. C. 
Published: December 2007

Abstract
To simultaneously simulate the flow behavior in the reservoir and horizontal wellbore, it is necessary the developing of a coupled model integrating both reservoir domain and horizontal wellbore domain. This paper investigates the transient flow behavior of horizontal wellbore and reservoir using a two phase coupled model. All the variables for both reservoir and wellbore domains are solved simultaneously, so that the results can reflect the flow characteristics and interactions between the reservoir and horizontal wellbore. The results show that the proposed coupled model can reveal the finite conductivity features of the horizontal wellbore. The influx and its effect are actually non-uniform distributed. A case study was conducted and analyzed in this paper.
A Probabilistic Approach to Shale Gas Economics
Authors: Gray William M. , Hoefer Troy A. , Chiappe Andrea , Koosh Victor H. 
Published: December 2007

Abstract
Unconventional resource plays, and shale gas plays in particular, are generally characterized by lower geologic risk and higher commercial risk. Large, continuous accumulations of tight, often naturally-fractured shale serve as both a hydrocarbon source and a potentially-productive reservoir. The likelihood of commercial production is a primary uncertainty in these plays, resolved in part by drilling pilot (appraisal) wells. The need to understand the range of potential for commercial realization places a heavy burden on the economic evaluation process. This requires maximum insight into the basis for a decision to pursue or not pursue any particular shale gas resource play. Beyond this, a consistent approach to economic evaluation is of critical importance when comparing the economics of various plays. Without consistency, comparison of multiple shale gas plays becomes extremely difficult, if not impossible.
The ability to define and represent key uncertainties and understand their respective impacts on economic feasibility is vital to play entry and subsequent decisions involving continued investment. Issues such as well design (vertical, horizontal, multi-lateral, etc.), well performance (initial production rates, estimated ultimate recovery, etc.), stimulation technologies, commodity price environments, as well as commercial aspects such as acreage availability and cost, project execution timing, and rig count are critical. Furthermore, because there are few well-established commercial plays, analogs are constructed mainly from these data-bearing plays; e.g. Fort Worth Barnett, and applied to emerging or prospective plays. Uncertainty surrounding the technical or commercial fit of a given analog for new basins/plays must be accounted for in the play/project evaluation process.
Pioneer focused on a number of domestic shale plays that differ in many ways, most notably in terms of "the stage of commercial maturation." Due to the large number of unknowns, deterministic economic modeling gave the team a low confidence in the results and was viewed as merely a scoping indication of commercial potential. It was recognized by the team and by management that deterministic, single-point solutions are unable to provide a reality check for the input assumptions, which typically leads to overly optimistic results. Therefore, it was determined that these models, while good for quick scoping evaluations, would be inappropriate for decision-making in emerging plays. A better solution had to be found.
This paper describes a consistent, systematic process employed in the evaluation of a number of shale gas plays, how various software applications were deployed, the vital role of multi-disciplinary participation, iterative modeling efforts and conclusions. In a general sense, we believe the lessons learned here can be applied either to unconventional or conventional upstream oil and gas projects.
Stochastic Modelling of Shale Gas Resource Play Economics
Authors: Stabell Charles , Gonzales Rosella , Langlie Espen 
Published: December 2007

Abstract
Unconventional petroleum resource plays present unique assessment challenges. These large, single accumulations cannot be counted and analysed as discrete entities that are delineated by down-dip water contacts. Equally important, the main assessment challenge relates to exploitation risks and uncertainties. This paper presents an integrated stochastic assessment framework for decisions related to shale gas resource plays. The shale gas resource play is modelled as a set of discrete cells that have not been explored (exploited) and that have the potential for economic production. The distinctive aspect of the modelling tool is the use of stochastic simulation to calculate the risks of failure in either the exploration, the appraisal/pilot, or the exploitation phases of the project on the basis of both sub-surface uncertainties and above-surface activity performance, cost and duration uncertainties. The tool also generates stochastic performance metrics that capture alternative outcome scenarios, economic returns and the delivery schedule of production and reserves. The performance metrics support both project-level and portfolio-level decisions related to unconventional resource plays. Project-level application is illustrated using data from a Canadian shale gas resource play.
Stacking Seismograms to Improve Microseismic Images
Authors: Shemeta J. E. , Maxwell S. , Warpinski N. R. , Quimby S. , Riebel T. , Phillips Z. , Kinser J. R. , Hinds G. , Green T. W. , Waltman C. K. 
Published: December 2007

Abstract
Microseismic mapping's primary limitation is its viewing distance which is affected by noise, attenuation, and the intrinsic size of the source event. In the Rocky Mountains the required viewing distances are often less than typical offset-well spacings, making accurate mapping difficult in many fields. A new approach to improving microseismic mapping capabilities is to digitally stack the signals from separate adjacent receivers to obtain noise cancellation. This approach requires large numbers of receivers and fast telemetry rates to obtain the necessary data. An experiment has been conducted in the Uintah basin with a 12 level receiver array in which 3 of the 12 levels consisted of triple receiver stacks. The improvement in the signal quality consists of reduced noise, improved hodogram linearity, and clearer phase arrivals. The subsequent microseismic maps using stacked data are both more accurate and contain more events that can be analyzed.
Refracture Treatments Proving Successful in Horizontal Bakken Wells: Richland Count, Montana
Authors: Lantz Tom , Greene David , Eberhard Mike , Pershall Richard 
Published: December 2007

Abstract
The Bakken reservoir development in Richland County, eastern Montana, has been a center of activity and has received significant attention in the industry since the first horizontal well was completed there in 2000. For one operator the initial completion program utilized cemented liners in the laterals in wells oriented to promote longitudinal hydraulic fractures. As discussed by Wiley, et al.,1 radioactive tracer logs indicated that there were often significant intervals, especially in the heel section of laterals that were not stimulated using this technique.
In late 2003, one operating company decided to attempt a refracture treatment in a well that showed long lengths of unpropped interval based on its tracer log. The approach was to emulate the completion technique then in use on new wells with uncemented liners. The result from this first refracture treatment was encouraging with a peak post-refracture treatment production rate in excess of the peak production rate after the original completion stimulation. As a result of this success, a refracture treatment program was initiated.
To date, all but one of the initial cemented liner wellbores have had refracture treatments pumped into them. The overall result has been an increase of over 1,300,000 stock tank barrels (STB) in the estimated ultimate recovery (EUR) for the wells in this program. Results showing the improved coverage from tracer logs will be presented along with examples of pre- and post-treatment production curves.
Over the course of this refracture treatment program, the fracture treatments have evolved. Treatment size has remained the same; however, the method of pumping the treatments has changed. This paper discusses how the refracture treatments were pumped and the results of the program.
Improving Reserves Estimates From Decline Curve Analysis of Tight and Multilayer Gas Wells
Authors: Cheng Y. , Lee W. J. , McVay D. A. 
Published: December 2007

Abstract
Decline curve analysis is one of the most commonly used techniques to estimate reserves from production data. In tight formations that have been stimulated, especially when there are multiple layers that communicate only at the wellbore, the uncertainty in reserves estimates from this technique is quite large because forecasting future performance is quite difficult. This uncertainty can affect the classification of reserves, and could limit what we should call "proved developed reserves." In this paper, we present new procedures to mitigate the complexity of decline curve analysis in multilayer tight gas wells. Using synthetic and field examples, we demonstrate how reserves can be estimated more reliably.
For tight and multilayer gas wells, it is not uncommon that decline curve analysis yields an Arps decline-curve parameter ‘b’ larger than 1. Single-layer hydraulically fractured tight gas wells also appear to have b values greater than one. Different practices are used to handle such complexity. For forecasts, some analysts simply use the ‘b’ value obtained from matching production data, while others force the ‘b’ value to be 1. Still others use the hyperbolic decline and the matched value of ‘b,’ but, when the decline rate reaches a predetermined limit, they switch to exponential decline for the remainder of the forecast. Thus, forecasted performance differs significantly when different analysts analyze the data. Consequently, the reserves estimate has large uncertainty, which can, in turn, affect its classification.
In this paper, we first present an in-depth investigation of decline behavior of tight, single-layer and multilayer gas wells by analyzing depletion characteristics using simulated data sets. We illustrate the long-duration transient effects present in single-layer stimulated tight gas wells and the complex flow regimes present when wells in layered reservoirs are produced commingled. Our work indicates that, as observed in field data, transient effects and coexistence of different flow regimes between layers lead to abnormal decline behavior (b&gt;1.0) in multilayer tight gas wells, which leads to errors in production forecasts. Our new procedure provides a method to minimize these errors.
Investigation of Water-Coning Phenomenon in Iranian Carbonate Fractured Reservoirs
Authors: Namani M. , Asadollahi M. , Haghighi M. 
Published: December 2007

Abstract
The water coning caused by the imbalance between gravity and viscous forces is the most important reason for water production in different fractured reservoirs. There are various controllable and uncontrollable parameters affecting this phenomenon. In this study different dynamic models were constructed to search for the key parameters affecting the coning process in both single-well and Cartesian multi-well models.
It has been determined that oil layer thickness, perforation thickness, fracture permeability and its orientation, especially horizontal not vertical fracture permeability, production rate, mobility ratio, and fracture storativity have the major role in water coning phenomenon. Also it has been determined that fracture spacing, aquifer strength and skin factor have insignificant effect on water coning in fractured reservoirs. The variation of water breakthrough time respect to each effective parameter has also been studied. We concluded that for any production program or adjusting the wells location, the parameter study is very important.
Multi-well studies using an Iranian fractured reservoir data show that the trend of dependency of water coning on each parameter is similar to the single-well model. However, in field scale, it is necessary to have all reservoir data including well location, and production history for a successful water coning simulation because a small pressure drawdown exerted by a far well will affect the cone shape and its breakthrough time.
In Situ Gelled Acid as a Diverting System in Water Injection Well
Authors: Miniawi Mohamed A. , Ahmed Wael A. Fattah , Ahmed Yaser Ali , Soufi A. Rahman 
Published: December 2007

Abstract
The formation damage of water injection wells reduces the ability of the injected fluids (water) to flow through the formations in order to maintain the reservoir pressure and sweep the oil to producer, therefore it is common use the acid to remove theses damages and enhance well injectivity.
This paper describes the successful job in one water injection well in Libya by using an In-situ gelled acid as a diverter with acid treatments to remove formation damage and improve permeability along the whole interval.
The water injection well was suffering high skin damage along 27 ft of the total 42 ft interval; the remaining 16 ft took the entire volume of the injected water. The objective of the treatment was to remove the damage and improve the permeability in the damaged zone.
Use of the In-Situ gelled acid was decided to block temporary the high permeable zone and allow the regular acid to create worm hole in the damaged zone.
The In-situ gelled acid is tested at the laboratory before performing the job. The polymer was cross linked at pH 2 and the sudden rise in viscosity was to about 1000 m Pa S (cp).
The design, quality control and results are detailed in this paper.
Innovation, Who Pays—Making the Economic Case for Adopting New Technologies
Authors: Kozicz John 
Published: December 2007

Abstract
Since the early 1980's hydrocarbon finding and development costs measured in $/BOE declined steadily reaching a low in the mid 1990's. This improvement in Capital Efficiency was driven by the adoption of technologies such as PDC bits, improved drilling fluids, and dual activity rigs, which help reduce costs as well as technologies such as horizontal drilling, and advances in well completion technologies which significantly improved well recovery. Additionally, advances in seismic and other exploration technologies significantly improved the exploration success rate and hence increased reserve additions.
However, since the mid 1990's finding and developing costs have been rising steadily as the rate of discoveries and additions in mature basins decline and fields become smaller resulting in higher costs as more wells and infrastructure are required to exploit these reserves. Furthermore exploration and production activities have moved to ever more demanding regions such as deepwater offshore, and harsh environment areas such as the Arctic requiring ever more costly wells and infrastructure to develop resources in these areas.
Technological innovation drove the improvement in capital efficiency realized during the 1980's and early 1990's. Since then the pace of technological innovation has slowed due in part to the desire to minimize technical and commercial risk as exploration and development activities move to these more demanding environments. The consequence of this is deterioration in capital efficiency. In particular the efforts to control costs have created barriers to the development and application of new drilling technologies which could significantly reduce the current 25 – 30% non productive time experienced drilling wells today.
This paper discusses a phased approach to technology evaluation, development and adoption which seeks to minimize the risks, both technical and economic associated with applying new drilling technologies or innovations.