bluuebunny/crossref_metadata_2025_split huggingface dataset:
Towards Proppant Back-Production Prediction
Authors: van Batenburg Diederik , Biezen Ewout , Weaver Jim 
Published: December 2007

Abstract
Proppant back-production from hydraulically fractured wells is a great operational problem to the oil and gas industry. Apart from safety problems related to erosion of tubing and valves, extra equipment and operators are required to handle wells that produce proppant. Substantial work has been conducted to develop methods to control proppant back-production. The methods include the modification of completion designs, the use of controlled fracture closure to obtain early closure on the proppant and the use of new materials designed to prevent proppant production. These materials include curable resin coated proppant, fiberglass, thermoplastic filmstrips, and chemicals that modify the surface of the proppant. Relatively little effort, however, has been directed towards understanding the mechanisms that cause proppant back production. A review of the relevant literature shows some experimental studies at a laboratory scale and one numerical study on the mechanical stability of proppant packs.
This paper presents the results of combined experimental and modelling studies to quantify parameters critical to proppant back-production. Laboratory experiments were conducted in several slot flow models. The experimental results were used to calibrate a numerical model to predict back-production. In the model flow inside the proppant pack is described by Darcy's equation for flow through porous media. The resulting velocity distribution is used to assess the local stability along the free surface between the proppant pack and the continuous fluid phase. These steps are repeated to evaluate the development of the interface over time. Similar methods have been used to describe viscous fingering in petroleum reservoir engineering. However, in viscous fingering the interface moves in the same direction as the fluid while the directions are opposite in the application described here.
Example simulations show how stable open channels can develop in propped hydraulic fractures. The results provide a foundation for the existence of such channels as has been speculated and hypothesized by many people over the last couple of years.
Simulation of Fractures Induced by Produced Water Re-Injection in a Multi-Layer Reservoir
Authors: Gheissary G. , Fokker P. A. , Egberts P. J. P. , Floris F. J. T. , Sommerauer G. , Kenter C. J. 
Published: December 2007

Abstract
In a recent study a numerical model for Produced Water Re-injection (PWRI) under fracturing conditions was presented [1]. The model was a 2-dimensional analytical fracture growth model and hence only appropriate for constant-height fractures fully penetrating the injection layer, with a "square fracture" option allowing a first order estimate of radial fracture dimensions. In this paper we present a new 3-dimensional fracture growth model which permits the description of elliptical fractures in a multi-layer reservoir with fracture length, height up and height down all potentially growing at different rates.
The pressure field in the formation around a fully contained elliptical fracture will resemble that of a fracture in an unbounded reservoir (i.e. 3D solution), while far into the reservoir it will approach a 2D solution, with a gradual transition between the two limiting cases. Solutions to both of these limiting cases have been developed earlier [2,3]. Here we present a new method which approximates the gradual transition from 3D-elliptical symmetry to 2D-elliptical symmetry with an abrupt transition. In a multi-layer reservoir the model can be applied independently to all the layers if no crossflow between the layers is allowed.
A comparison is presented between the two models which demonstrates that the previous model predicts larger fracture sizes. This is particularly the case if the pressure drop over the filtercake is relatively small.
We also present a new approach to represent plugging within the fracture due to the build-up of filtercake resulting from suspended particulates in the produced water. This new approach allows for flow channels to develop within the filtercake in the fracture, rather than the approach used in the previous study which adopts a parallel-plate flow model and allows uniform growth of filter cake on fracture walls.
A number of PWRI field examples is also presented. The model is very suitable to assess the containment capacity of layered reservoirs, which is demonstrated using a field example of a large reservoir in the Middle East.
Comparisons with Prudhoe Bay data show that our model is not capable of predicting the virtually immediate response to changes in the water quality. The model still assumes that the filtercake properties are determined by the cumulative volume of solids pumped into the fo rmation. This needs to be reviewed and possibly extended to also include immediate effects.
Acidizing Deep Open-Hole Horizontal Wells: A case History on Selective Stimulation and Coil Tubing Deployed Jetting System
Authors: Mascarà S. , D'Ambrosio A. , Zambelli A. , Gili V. , Loving S. , Dossena M. 
Published: December 2007

Abstract
The Val D'Agri field is located 20 Km SE of Potenza (Basilicata) in Southern Italy. The aerial extension of the field covers approx. 250 Km2 mostly (2/3) in the mountainous region (more than 1000 m. a.s.l.) of the field, while the remaining part is located in the river Agri valley at 600 m. a.s.l.
The field is divided into five blocks: Grumento Nova, Corleto Perticara, Caldarosa, Volturino and Tempa Rossa, operated by ENI Agip Division on behalf of different Joint Ventures, comprised by Enterprise Oil, FINA, and Mobil.
From 1980 to present 24 wells have been drilled by ENI Agip Division. The most significant discoveries have been Costa Molina 1(1980) and Monte Alpi 1 (1988), in the southern part, Cerro Falcone 1 (1992), in the northern part, and Monte Enoc 1 (1994), in the central part of the field which confirmed a unique reservoir. Val D'Agri is currently the most interesting Italian region for hydrocarbon production, and probably the most demanding from the completion technology point of view.
The overall plan is to drill more than 50 wells and produce about 100,000 bopd when the oil treating center and the pipeline network will be completed.
Changes in Solids Composition of Reservoir Drill in Fluids During Drilling and the Impact on Filter Cake Properties
Authors: Pitoni E. , Ballard D. A. , Kelly R. M. 
Published: December 2007

Abstract
Considerable emphasis is placed on the selection of carefully sized bridging agents (including calcium carbonate, sized salt and cellulosic materials) for low damage reservoir drilling fluids. The rationale behind this selection is to optimise the filter cake-building properties of the fluids, and hence minimise formation damage due to invasion of mud particles into the near wellbore formation. This feature is particularly desirable in non-cemented completions where there are no perforations to bypass such near wellbore impairment. In addition the filter cake needs to be compatible with sand control techniques and equipment so that the productivity is not adversely affected.
Laboratory experiments on clean reservoir drilling fluids can, indeed, show the benefits of correct particle sizing, particularly in situations where the formations have high matrix permeability. There is some doubt, however, that these laboratory observations can always be repeated in the field, where the introduction of drilled solids and exposure of the fluid to high shear can result in a decrease of particle size.
The paper presents data from tests carried out on laboratory and field reservoir drilling fluids which show the extent and speed of the changes that occur in bridging solids composition and size distributions during drilling. The effects these changes have in terms of filter cake properties have been demonstrated.
Practical recommendations are made, which have been applied to wells drilled in West Africa. One well was a +600 m long horizontal section, where the filter cake was determined to have a neutral effect on the skin factor, without treatments for filter cake removal. A standard fluid would normally require a treatment, even if it is claimed to be non damaging.
Correct fluid composition, bridging material selection, and good maintenance of the drilling fluid system are the keys to success for better productivity. A filter cake that allows a better flow profile along the entire wellbore reduces the risks of water coning or erosion associated with non uniform flow and pressure drop. Very often, the cost of a specialised reservoir drilling fluid system is less than that of any treatment required to remove a standard filter cake and restore the original permeability along the entire borehole.
The Equation for Geopressure Prediction from Well Logs
Authors: Eaton Ben A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This study has resulted in the development of four equations that may be used for the prediction of geopressure magnitudes from well prediction of geopressure magnitudes from well log and drilling parameter data. Equations are given for use with resistivity plots, conductivity plots, sonic travel-time plots, and corrected "d" exponent plots. All equations have the same theoretical basis.

Introduction
In 1965, Hottman and Johnson presented a method for predicting geopressure magnitudes by using resistivity and sonic log data. This technique has received wide acceptance even though the prediction charts were based only on data concerning Tertiary age sediments in the Gulf Coast area. It was specifically pointed out that these techniques were applicable only in areas where the generation of geopressures is primarily the result of compaction in response primarily the result of compaction in response to the stress of overburden.
In 1972, this author presented a theory on the effect of overburden stress gradients n geopressure prediction techniques.
Compaction caused by overburden stress was described classically in a soil mechanics book by Terzaghi and Peck in 1948. With a vessel containing a spring and a fluid, they simulated the compaction of clay that contained water. Overburden stress was simulated by a piston, as in Fig. 1. It was shown that the overburden stress, S, was supported by the stress in the spring, sigma, and the fluid pressure, p. Thus, the long-accepted equation of equilibrium was established.
(1) S = + p
If Fig. 1 and Eq. 1 are studied, it is obvious that if S is increased and the fluid is allowed to escape, sigma must increase while p remains as hydrostatic pressure. However, if the fluid cannot escape, p must also increase as S is increased.
Hubbert and Rubey published a comprehensive treatment of this theory as related to sedimentary rock compaction. They showed that, as the overburden stress is increased as a result of burial, the porosity of a given rock is decreased. Therefore, some fluid that was once in the pores of a given formation was later squeezed out by compaction. In many such cases, there is no escape route for the fluid, and thus the fluid becomes overpressured according to Eq. 1. This happens in many areas, and such generated overpressured zones are often called "abnormal" pressure zones or "geopressure" zones.
A Comparison of Coal Seam Directional Permeability as Measured in Laboratory Core Tests and in Well Interference Tests
Authors: Wold M. B. , Jeffrey R. G. 
Published: December 2007

Abstract
A thick composite coal seam at Dartbrook Mine has been characterised by stress and permeability testing over several years. Most recently, a four well injection interference test was conducted to measure the overall seam permeability anisotropy, and core samples from various sites near the interference test array have been tested in the laboratory. The magnitudes of horizontal permeability components as measured by the well test and by core tests were found to be similar, but the principal permeability directions were reversed. The interference test measured the permeability anisotropy of the entire composite seam while the core samples came from only one of the four seams making up the composite seam. Structural features and hydraulic fracture results suggest that different seams and even parts of single seams in the composite seam are very likely to have significantly different permeability tensors.
Practical Issues With Field Injection Well Gel Treatments
Authors: Smith J. E. 
Published: December 2007

Abstract
Polymer gel treatments are effective in reducing high water production, resulting in improved oil recovery. The gels function by moving into highly permeable, water saturated zones and severely reducing permeability to water in those zones, so that oil can be produced from tighter rock. The gels can be applied to injection wells or producing wells. They are effective at shutting off water or gas in oil wells. This paper focuses on field applications of injection well gel treatments to shut off water in oil producing intervals. Strategies for sizing treatments in injection wells are discussed, and field case history examples are provided to illustrate concepts. Guidelines for predicting timing and magnitude of production side response are provided, along with economics and risk factors. A plot of normalized incremental oil response against gel volume injected is introduced as a new means of estimating expected oil response for heterogeneous sandstone reservoirs with crossflow, based on actual field performance of several injection well gel treatments.
Comparison of 20 Minnelusa Waterfloods in the Powder River Basin
Authors: Towler Brian F. , Griffith Durward B. 
Published: December 2007

Abstract
This study compares the oil produced at a projected pore volume (PV) produced predicted from a suitable curve fit. The study compares fresh waterfloods with brine floods. The data plots and curve fitting techniques are such that PV Oil produced could be chosen for the Y axis for easier economic analysis. This technique was developed and described in Griffith13. The study was originated from interest generated by work performed by Morrow's research group at the University of Wyoming, (see Tang26, and Tang and Morrow27), indicating that fresh water flooding could result in a greater oil recovery then saline floods. Table 1 and Figure 1 shows the comparison of our 20 chosen waterfloods. The Widge field, which extends above the top of the chart, has not produced sufficient water to define the waterflood. The lowest plotted field, the Spirit Field, appears to have watered out very quickly after initialization of the waterflood. Figures 2 and 3 are the 20 flood separated into non-enhanced and enhanced floods. The West Semlek waterflood is placed in the non-enhanced although an attempt had been made to use polymer in the field. We have assigned fresh water flood status to those fields initially flooded with Fox Hills water even though the later makeup water was combined with produced brines. The West Semlek, the one brine flood, is the flood in Figure 1 which has the x marker and intercepts the 2.0 pore volumes fluid (water plus oil) produced at 42% of OOIP produced. In general the fresh water floods had generally higher recoveries than the one brine flood, which is consistent with Morrow's laboratory results.
Risk Analysis - Is it Really Worth the Effort?
Authors: Newendorp Paul D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction
During the past 10 years or so there has been a concerted effort within our industry to expand the use of new quantitative evaluation methods in the analysis of how to invest capital in exploration and production operations. This effort has taken the form of many articles in our literature, numerous short courses and management seminars on decision making under uncertainty, and countless after-dinner speakers extolling the virtues of the new decision-analysis methods. In the process we have been exposed to a whole new vocabulary of terms such as risk analysis, expected value concept, conditional probability, EMV, decision trees, utility theory, Monte Carlo simulation, Bayes' theorem, bid strategies, etc. The common thread running through all of these new ideas has been the argument that, if we change from our traditional (and largely intuitive) ways of deciding how and where to invest capital and, instead, base our decisions on these new approaches, we will do a better job in the long term of investing capital under conditions of uncertainty.
The new decision-analysis methods involve quantitative statements of the degree of risk and uncertainty. Many involve complex, hard-to-grasp statistical concepts. And, outwardly at least, many of the methods suggest or imply that "scientific decision making" is really a very simple, impersonal review of a bunch of numbers. On the other side of the coin is the feeling of many managers that decision making is a very personal, intuitive, subjective, and emotional personal, intuitive, subjective, and emotional process that does not lend itself to any form of process that does not lend itself to any form of quantification by a staff of statisticians or management scientists.
Thus, it is not surprising that recent proposals to convert the decision-making process proposals to convert the decision-making process over to the new methods have caused much consternation, frustration, and skepticism on the part of many managers. Some have rebelled at the suggestion to change from the ways they have been using (successfully?) over the years. Others have concluded that the new quantitative analysis methods clearly offer important new insights about how best to invest money under conditions of uncertainty. But probably the large majority of decision makers are undecided about it all and are trying to assess the charges and countercharges being hurled back and forth between the "believers" and "nonbelievers." Their concern is whether to walk away from what they perceive to be the reasonably satisfactory (although largely intuitive) ways of making decisions they have been using for many years and embrace a new way of analyzing decisions that they only partially understand. partially understand.
Review of Coalbed Methane Development in the Powder River basin of Wyoming/Montana
Authors: Peck Charles 
Published: December 2007

Abstract
Coalbed methane development in the Powder River basin has a long history that is largely reflective of the uncertainty of the economics of the play, caused by a poor understanding of the reservoir. Conventional wisdom characterized the Wyodak and related coals as too shallow and too immature, having too much water and too little gas. Prior to 1986, gas shows in the Wyodak were encountered by ranchers, and water well drillers, and recorded by researchers. In 1986, conventional gas sands charged with CBM from the adjacent Wyodak coal were discovered and produced. In 1989, the relatively deep Big George coal was drilled in the Sasquatch Unit of Johnson County, without success. Rahwide Butte commenced production, with some success. Tax credits spurred continuous drilling of a limited number of CBM wells through 1992, many of which did not come on line until 1993. The Marquiss wells that started producing in 1993 became the first significant producers that began to indicate economic reserves and production rates. In 1994 the Macsy area came on line and added further credibility to the play. By 1997, sustainable production rates and apparent significant reserves caused and drilling of the play to increase significantly. During this long development period, a great deal was learned of the characteristics of the reservoir, the environmental and political aspects of operations, costs, and technical aspects. The economic limits of the play remain uncertain in areas where the Wyodak and Big George coals are deep, where hydrologic conditions differ from the "sweet spots", and where splitting of the coal causes difficulty in completions.
Restoration of the Natural State of Core Samples
Authors: Cuiec L.E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction
The wettability of a reservoir rock plays an important role in oil recovery during a water drive. It influences the residual oil saturation, the relative permeabilities and the capillary pressure. Since it is impossible to measure all these parameters in situ, laboratory experiments are used, thus raising the problem of the representivity of samples.
Most scientists working on the problem have concluded that it is difficult to obtain valid measurements without operating under conditions as close as possible to those in the reservoir.
It is easy to reproduce reservoir temperature and pressure conditions in the laboratory. It is also possible to obtain reservoir fluids. Unfortunately, obtaining porous-medium samples that are representative from the standpoint of the surface state is more delicate.
To obtain such samples, we can try either to preserve the original surface state or else to restore it. At the moment the former method is the most widely used, but requires special precautions while the sample is being taken. precautions while the sample is being taken. Nonetheless, these precautions are not sufficient to prevent a temperature and pressure drop when the sample is being brought up. This drop may change the distribution of fluids on the surface of pores and be accompanied by the deposition of asphaltenes or other heavy fractions.
In summary, the preservation technique as is now practiced is far from being perfect. Likewise, only modest confidence is generally placed on the quality of preservation. placed on the quality of preservation. It would be thus advantageous to have another method that could be applied whether the sample had or had not been cored with precaution and protected from any contamination, oxidation, fluid loss, etc., or whether or not it had already been used for physical measurements in the laboratory.
The restoration method meets these requirements. It consists of two steps:cleaning the surface of the solid to remove as much as possible if not all the products that had become possible if not all the products that had become fixed there, whether they came from crude oil or mud. It is not possible to separate the products initially adsorbed on the rock in the products initially adsorbed on the rock in the reservoir from those that had become fixed there afterward.