bluuebunny/crossref_metadata_2025_split huggingface dataset:
Minimizing Environmental and Economic Risks with a Proppant-Sized Solid Scale Inhibitor Additive in the Bakken Formation
Authors: Szymczak Steve , Shen Dong , Higgins Rocky , Gupta D. V. 
Published: October 2012

Abstract
Within the past decade, hydraulic fracturing has been proven to improve the efficiency and economics of recovering oil and natural gas from shale formations. In a previous paper (SPE 134414), a summary of treatment results of placing a solid scale inhibitor into formations via the fracturing process for over five years and in over 1500 wells was fully discussed. The practice of hydraulic fracturing has come under scrutiny due to concerns about the environmental impact, health and safety. Therefore, a novel biodegradable solid scale inhibitor with an excellent ecotoxicity profile for fresh water incorporated into a solid matrix was recently developed and deployed in North Dakota. For one operator in this area with 150 Bakken-producing wells, 22 of the wells have experienced at least one event of severe mineral scaling in the pump and production tubing, leading to well failure, whereas the results from over 140 Bakken wells now fractured with the new solid inhibitor additives indicate no reported scale failures to date.
This paper provides a detailed description of the first deployment of this environmentally preferred proppant-sized solid scale inhibitor additive under severe scaling conditions in the field. In addition, an analytical method developed to track the residual of this additive in the produced fluid containing polysaccharide contaminants is also discussed.
Bias in Rate-Transient Analysis Methods: Shale Gas Wells
Authors: Agnia Ammar , Alkouh Ahmad , Wattenbarger Robert A. 
Published: October 2012

Abstract
Superposition-time functions offer an effective way for handling variable-rate data. However, these functions can also be biased and misleading. The superposition approach may generally be more useful for well-test analysis (constant rate solutions) than rate-transient analysis. Calculated data points do not tend to be sequential with superposition time but do tend to fall on a straight line corresponding to the superposition function chosen. Examples of superposition are logarithm of time (infinite acting vertical wells) and material balance time (boundary dominated flow). Production data from shale gas wells are usually subjected to operating issues that yield noises and outliers. When the rate data are noisy or contain outliers, distinguishing their effects from common regime will be difficult if the superposition time functions are used as a plotting time function on log-log plots. The superposition function may then lead to a log-log plot that has erroneous straight-line segments.
A simple technique is presented to rapidly check whether or not there is data bias on the superposition-time specialized plots. The technique is based on evaluating the superposition time function of each flow regime for the maximum production time. Whatever data are beyond the maximum production time (MPT) are considered as biased data and depend on the superposition function chosen. A workflow involving different diagnostic and filtering techniques is proposed. Different synthetic examples and field examples are used in this study.
Once all the problematic issues were detected and filtered out, it was clear that superposition time data beyond the MPT is biased and should be ignored. Thus, the proposed MPT technique can be relied on to detect and filter out biased data points on superposition-time log-log plots. Both raw and filtered data were analyzed using type-curve matching of linear-flow typecurves developed by Wattenbarger et al. (1998) for calculating the original gas in place (OGIP). It has been found that biased data yield a noticeable reduction in OGIP. Such reduction is attributed to the early fictitious onset of boundary dominated flow.
Relationship between Microseismic Activity, Hydrofracture, and Stimulated Zone Growth Based on a Numerical Damage Model: An Example from Bossier Sands
Authors: Guest Alice , Settari Tony 
Published: October 2012

Abstract
The key property controlling reservoir productivity is permeability. Permeability enhancement during hydraulic fracturing, to some degree, can be inferred from microseismic monitoring. In this study, we numerically model microseismicity occurring along the hydraulic fracture, compare it to the recorded microseismic activity and predict permeability of the reservoir based on the motion on the fractures.
We present a fully coupled fluid-geomechanical model of hydraulic fracture propagation in the heterogeneous reservoir. The fluid part is solved using the commercial code Geosim and the geomechanical and microseismic solutions are constructed using the damage mechanics. Permeability enhancement is calculated from the fracture displacement. We distinguish three fracture scales in terms of model implementation: the main hydraulic fracture (~100 m scale), new fracturing on the scale of microseismic events (~ 2-10 m scale) and microfractures (under 2-10 m scale).
We apply this technique to the hydrofracturing treatment in the Bossier sandstone where we focus on the effect of the preexisting fracture heterogeneities on the reservoir microseismic activity. We use the observed microseismicity as a guide to describe the reservoir heterogeneity. Even though we match the observed microseismicity very well in time and space, the permeability enhancement related to the formation of the new fractures is very scattered and the increased leak-off does not change in time enough to characterize the total leak-off into the formation. Permeability determined from the new fractures is several orders lower than permeability of the main hydrofracture. Such an enhancement is not efficient in this case and cannot drive enough fluid into the formation and therefore permeability of the main fracture remains the main driving mechanism. However, the effect on the production may be different and needs to be explored. The heterogeneity of the reservoir seems to be a very important property for the success of the hydraulic fracturing.
Strategies for petroleum exploration based on Bayesian Networks: a case study
Authors: Martinelli Gabriele , Eidsvik Jo , Hokstad Ketil , Hauge Ragnar 
Published: October 2012

Abstract
The paper presents a new approach for modeling important geological elements, such as reservoir, trap and source, in a unified statistical model. This joint modeling of these geological variables is useful for reliable prospect evaluation, and provides a framework for consistent decision making under uncertainty. A Bayesian Network, involving different kinds of dependency structures, is used to model the correlation within the various geological elements, and to couple the elements. Based on the constructed network, an optimal sequential exploration strategy is established via dynamic programming. This strategy is useful for selecting the first prospect to explore, and which decisions to make next, depending on the outcome of the first well. A risk neutral decision maker will continue exploring new wells as long as the expected profit is positive.
The model and choice of exploration strategy is tailored to a case study represented by five prospects in a salt basin, but it will also be useful for other contexts. For the particular case study we show how the strategy clearly depends on the exploration and development cost, and the expected volumes and recovery factors. The most lucrative prospect tends to be selected first, but the sequential decisions depend on the outcome of the exploration well in this first prospect.
Drilling Adjacent to Salt Bodies: Definition of Mud Weight Window and Pore Pressure Using Numerical Models and Fast Well Planning
Authors: Adachi Jose I. , Nagy Zsolt R. , Sayers Colin M. , Smith Martiris F. , Becker David F. 
Published: October 2012

Abstract
A 3D finite-element model covering more than 10 blocks in the deepwater Green Canyon area of the Gulf of Mexico has been used to calculate the stress distribution around an extensive salt body. The complex model geometry, and the determination of rock properties and pore pressure, was based on multiclient seismic data and state-of-the-art imaging techniques. The model has been used to determine the impact that salt geometry will have on drilling decisions. The numerical model shows that the near-salt stresses are dependent mainly on the morphology of the salt body. Higher compressive stresses were found in supra-salt minibasins and sub-salt concave-down embayments, resulting in higher mud weight windows. Areas below convex-down allochthonous base salt show lower compressive stresses, resulting in narrow mud weight windows.
A fast well planning tool has been developed to translate the results of the finite-element model to operational parameters for well design. With this tool, the full stress tensors are extracted along any arbitrary well trajectory, providing a high-resolution model for calculating the mud weight window. This allows the drilling engineer to create fast predictions along any chosen trajectory within the study area and to make quick comparisons of the drilling mud weight window along multiple trajectories, helping with the selection of the optimal wellpath design. The application of this tool is illustrated using a "case study" focused on four proposed trajectories for a hypothetical well that has to reach the Eocene-Paleocene Wilcox formation.
A Significant MWD Tool Signal Strength Improvement: Another Advantage of Using a Treated Micronized Barite Drilling Fluid System
Authors: Mahrous R. , Montoto B. P. , Sobrinho M. , Thomaz Gonçalves J. 
Published: October 2012

Abstract
An order of magnitude increase in the Measurement While Drilling (MWD) signal strength was achieved while using a treated micronized barite (TMB) drilling fluid system. The MWD transmits downhole data critical for real-time data acquisition, geosteering, and formation evaluation.
The MWD signal strength is one of the core variables that must be considered when drilling wells with increased measured depth. By displacing the conventional drilling fluid with the TMB System, the Acquisition System was able to recognize a ten-fold increase in signal strength from 0.1-0.2 psi to 1-2 psi. In addition, a 50% torque reduction was recorded and barite sag was not an issue. These performance characteristics make the TMB system a viable candidate for drilling high inclined wellbores and other critical wells.
This paper covers a successful field trial showing the comparable MWD signal strength data with a treated micronized barite drilling fluid system carried out in the 8½-in. section of an HTHP exploration well offshore Brazil.
Solid Expandable Liner System With Custom Composite Frac Plugs Enable Recovery Of Lost Reserves In The Piceance Basin
Authors: Caplis Chris , Cameron John , Holte Darwin , Frazier Garrett 
Published: October 2012

Abstract
Casing integrity failure, whether through parted casing, leaky collars or some other issue, may result in less effective stimulation work due to abandonment of the plug and perf method and/or having to complete through a frac liner. In more extreme cases it could result in lost reserves below the casing failure point. Modern technology has provided a cost effective solution to this problem.
In this case, the operator confirmed parted 4-1/2 inch production casing at 9,761 feet (Fig. 1) in their northern Piceance Basin acreage. The operator would have to repair the parted casing in order to frac the lower six zones of the well. The plug & perf method for zonal isolation was required to effectively complete the 2,825 foot vertical pay interval. In order to complete the stimulation program, the goal was to repair the short section of damaged casing and restore pressure integrity to the well while maintaining a sufficient inner diameter (ID) to allow composite frac plugs to pass through the repair and set in the base casing's larger ID below the split. After a corrugated patch failed to provide casing integrity, the solution was a 3- 1/2 inch single-joint solid expandable system that was expanded downhole to cover and seal the parted 4-1/2 inch casing in conjunction with the use of custom made composite frac plugs.
The 30-ft., 3-1/2 inch solid expandable high-pressure, high-temperature (HPHT) liner system was deployed and expanded in a single trip. This system provided the required pressure integrity to withstand the frac pressures needed in this area. The 3.261 inch drift ID of the expanded solid liner allowed the operator to run custom 3.06 inch outer diameter (OD) composite frac plugs below the repaired section and successfully complete the well.
This installation was a success, as the operator had essentially written off 63% of the well's reserves due to the casing part occurring above a majority of the pay interval. The operator is now realizing full production from the entire well. Moreover, this single-joint solid expandable liner technology coupled with the special drillable composite frac plugs can be used in any HPHT formation to repair the common issue of damaged casing to allow plug and perf completions to continue.
Ultrastrong Formations: Perforating Challenges, Limits, and Optimization
Authors: Mustafa Hanaey D. , Briner Andreas , Jumaat Mohd S. , Grove Brenden , Atwood David , Judd Tobias 
Published: October 2012

Abstract
Due to high global demand, easy oil production is no longer sufficient to meet the continuous requirements. Extracting oil by using enhanced recovery methods or from difficult environments poses many challenges that differ from one field or formation to another. Ultrahigh-strength formations present a particularly difficult environment. In addition to posing drilling challenges, such formations introduce significant challenges to completion operations—particularly perforating and hydraulic fracturing, which represent the critical final steps in establishing formation-wellbore communication.
A key perforating parameter is the perforation tunnel depth of penetration (DoP). A new paradigm of DoP modeling relies on shaped charge characterization in the laboratory under a range of rock strength and stress; however, most available data are for rock strength or unconfined compressive strength (UCS) values of less than 18,000 psi. Therefore, uncertainty exists regarding DoP in some Oman formations in which UCS varies from 20,000 to 55,000 psi. Two main phenomena need to be verified. First, because penetration is inversely proportional to UCS, extrapolation of the existing shaped charge performance data suggests that the penetration will be close to zero at this extreme rock strength. Second, characterization of the shaped charges under this new paradigm shows that a shaped charge that performs better in a weaker rock may not necessarily perform better in stronger rocks. Therefore, tests are needed to identify the optimal charge(s) in these very strong rocks.
With these objectives in mind, cores obtained from the ultrastrong Amin formation in Oman underwent laboratory testing. Performance results of a series of tests designed in general agreement with the procedures of the American Petroleum Institue Recommended Practice (API RP) 19B Section 2 exceeded expectation based on extrapolation of previously available laboratory data. These new data provide valuable calibration points for the penetration model in ultrahigh-strength rocks.
This paper presents the methodology, results, and observations of this test program and discusses the way forward, which should add value to perforation performance not only in Oman, but also worldwide in ultrahigh-strength formations. Although previous studies have briefly addressed high-strength formations, this is the first known work that systematically evaluates perforator performance in ultrastrong formations.
Event-driven Information Integration for the Digital Oilfield
Authors: Patri Om Prasad , Sorathia Vikrambhai S. , Prasanna Viktor K. 
Published: October 2012

Abstract
Several operations in the Exploration and Production (E&P) sector are event-driven in nature and are supported by specialized systems and applications. Narrow focus of applications results in application silos that restrict the information sharing across verticals, which is a critical requirement for coordinated cross-functional efforts. Effective response to events warrants due emphasis on an integration strategy that facilitates desired information flow across verticals. Event-driven methods can be used to make strategic asset management decisions across silos in real-time, thus reducing response time and costs while improving asset performance.
Complex event processing is an emerging research area that involves detecting complex events, processing the events, deciding actions for each event and notifying the relevant personnel about the event. In the E&P sector, the adoption of CEP and messaging-based systems in conjunction with semantic methods can facilitate components of the oilfield to communicate in real-time across different software platforms. Such an approach helps not only in detecting complex events across various sources, but also in processing them and deciding the actions to be taken, with the help of a knowledge base – thereby reducing information overload.
Consider a typical application scenario - a pump failure event in an oilfield, which should elicit response not only by the pump operator but also by the maintenance engineers, production managers, reservoir engineers and other involved personnel. A proactive event-driven system enables quick detection of the failure across heterogeneous data sources and takes corrective actions while notifying the appropriate personnel. This facilitates effective communication across the teams and software systems involved.
We propose a semantic complex event processing architecture for the digital oilfield that facilitates enterprise information integration. We delineate an illustrative use case of such integration for production optimization. Value propositions of the proposed framework include efficient interaction patterns, reduction in data seeking efforts, faster response times, building of consistent best practices and management by exception.
Technology Innovation and Integration Enabling More Flexible, Adaptive, and Reliable Sand Control in Openhole Completions
Authors: Yeh Charles S. , Grueschow Eric R. , Bhargava Peeyush , Burdette Jason A. , Barry Michael D. , Hecker Michael T. , Dale Bruce A. 
Published: October 2012

Abstract
Long, multi-zone openhole completions have the benefits of maximizing reservoir contact and reserve captures with fewer wells, particularly for deepwater or remote environments. When producing from loosely consolidated or unconsolidated reservoirs, openhole completions are challenged by well longevity, zonal isolation, and subsurface control. Conventional gravel packs and standalone screen applications, along with the selection and design guidelines are being pushed to the limit. A new generation of sand control technologies is needed to meet these challenges.
This paper highlights ExxonMobil's technology integration and hardware innovation in bringing flexibility, adaptability, and reliability to openhole sand control. Technology integration reduces uncertainties in conventional sand control selection and design guidelines, which have been based on sand prediction, well design, and grain size from selected formation samples. An analytical, log-based grain size analysis was introduced to link a Rosin-Rammler formula to formation properties. A limit-based analysis links formation strength or sanding potential to operating conditions including production rate, influx, drawdown, and depletion. Integrating log-based grain size, limit-based analysis, and conventional guidelines to the entire completion interval enables a more flexible and reliable sand control design. Further integration with Well Operability Limits allows production throughout well life without geomechanical failure of the completion.
A series of innovative, enabling hardware has been developed in collaboration with service suppliers. The internal shunt Alternate Path® technology with true zonal isolation enables gravel packing multi-zones and extended lengths in openholes. The self-mitigating MazeFlo® technology enhances sand screen reliability in standalone screen completions or workovers. Both hardware technologies adapt to downhole uncertainties to achieve more reliable sand control. Emerging technologies like inflow control devices and sliding sleeves can be incorporated to control production flow in selective zones.
ExxonMobil's technology integration and innovation provide a distinguishing platform for openhole sand control. This platform positions openhole sand control completions for extended lengths, multiple zones, as well as production control.
Thermodynamics of Multiphase Flow in Unconventional Liquids-Rich Reservoirs
Authors: Firincioglu T. , Ozkan E. , Ozgen C. 
Published: October 2012

Abstract
The average pore size in currently producing unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary and surface disjoining force interactions (like van der Waals, structural, and adsorption) play an important role on phase behavior that is not considered in conventional PVT studies. In this paper, a comprehensive discussion of thermodynamics required to adequately model phase behavior that can impact multiphase flow in unconventional, liquids-rich reservoirs is presented. Three oil samples from different unconventional reservoirs are used to generate results. The impact of confinement manifests itself in the form of reduction (suppression) of the liquid pressure that the first bubble can form when compared to the bulk fluid measurements that are conducted in PVT cells. It is shown that the suppression of the bubble-point pressure impacts saturated portion of the liquid formation volume factor and extends the undersaturated portion of the curve. The gas composition is different for each supersaturation level and the gas is composed of lighter components as the supersaturation (bubble point suppression) increases.