bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Approach to Deliver Highly Concentrated Surfactants for Chemical Enhanced Oil Recovery
Authors: Barnes Julian , Dirkzwager Henk , Dubey Sheila , Reznik Carmen
Published: October 2012

A novel process has been developed to produce highly concentrated forms of surfactants suitable for chemical Enhanced Oil Recovery (cEOR) in the form of powders. Powders are advantageous for cEOR applications because, through their lower water content (typically 3%), they have the potential to reduce transportation costs and simplify the logistics of transporting surfactants from the production location to field locations.

Data are presented showing the properties and advantages of powder cEOR surfactants and how they compare to the more conventional liquid form of surfactants. The manufacturing route first involves the preparation of higher active matter liquids (around 70% active) that are subsequently converted into powders using dedicated, standard mixing equipment, the same type used for the manufacture of laundry powders. In this work, several surfactant powders were produced on a pilot plant scale using a number of internal olefin sulfonates to establish applicability for different cEOR projects. The blended powders are agglomerates of surfactant and sodium carbonate and were made both with and without polymer (termed ASP and AS powders respectively). The AS and ASP powders were found to easily dissolve in brine, eliminating the need for special field equipment for dissolution, and gave faster polymer dissolution in water compared with dissolving the polymer as a separate component. The powders have acceptable physical properties that facilitate transport and dispersion in brine and have been tested at desired ratios of surfactant to alkali.

This paper also outlines how higher active matter liquids can be manufactured to avoid gel phases, improve their handleability and lower their viscosity.

The surfactant powder approach has the potential to substantially reduce costs for full scale chemical EOR projects where large chemical volumes are manufactured, transported, stored and injected.
Improving Well Placement and Reservoir Characterization with Deep Directional Resistivity Measurements
Authors: Constable Monica V. , Antonsen Frank , Olsen Per Atle , Myhr Gjøril M. , Nygård Atle , Krogh Morten , Spotkaeff Matthew , Mirto Ettore , Dupuis Christophe , Viandante Mauro
Published: October 2012

The last decade has shown a significant development in resistivity measurement technology providing directional resistivity at a larger scale than conventional logging tools. The latest development can identify resistivity contrasts ten's of meters around the wellbore.

Statoil has tested deep look-around resistivity on a range of fields during the last 2 years and recorded data in more than 10 wells on the Norwegian Continental Shelf. The look-around images provides information at a scale that bridges the gap between conventional logging and seismic and adds important new pieces to the reservoir characterization puzzle. In good reservoir conditions, resistivity contrast up to 30 m away from the well-bore has been observed.

This study will focus on results from the Visund and Åsgard fields, and will demonstrate how the device was used in a range of different applications in the geosteering operation:

Detection of the reservoir boundary up to 20m TVD away. Detection of oil bearing reservoir from within underlying shale, through a water zone. Detection of Gas-Oil Contact (GOC). Detection of Oil-Water Contact (OWC) up to 20m TVD away. Detect faulting of the reservoir.

These examples will highlight why deep look-around resistivity is a step change related to the possibility for doing pro-active well placement of highly deviated wellbores as well as for gaining a larger reservoir understanding. The imaged variation in resistivity contrasts can be related to geologic zonation and fluid content on the reservoir scale, which opens up a much better cross-disciplinary communication between geophysicists, geologists, petrophysicists and reservoir engineers. Finally, the deep resistivity images contribute in optimization of completion solutions when incorporating information on the reservoir scale.
World First Riserless Light Well Intervention (RLWI) Technique to Mill and Clean Hard-Packed Debris, and Then Pull a Bridge Plug From a Live Subsea Well Using Electric Wireline
Authors: Delot Quentin , Eikeland Tommy , Gundersen Svein Helge , Skeie Normann
Published: October 2012

A subsea production well in the North Sea was being serviced with a riserless intervention which inadvertently resulted in fill atop a temporary bridge plug. Riserless slickline and traditional e-line attempts to remove the debris and pull the plug were unsuccessful. A rig or intervention vessel with riser for coiled tubing cleanout was unavailable for approximately a year. The operator requested innovative solutions and selected a unique riserless light well intervention consisting of an e-line cleaning tool with a reverse circulating bit and bailer sections to break through the hard-packed debris, vacuum it into the bailers, and retrieve it to surface. The remaining debris in the internal fishing neck of the plug was sucked up by a high-powered e-line cleaning tool and the plug was pulled in the same run. The job was executed without incident from a small, dynamically positioned, vessel with a moon pool and a subsea lubricator, saving the operator about one year's deferred production versus waiting for the coiled tubing solution. This paper discusses the operation of the downhole tools and procedure for riserless deployment to achieve the objectives and create this value.
Successful Application of Venturi Orifice Gas Lift Valve in Kaji-Semoga Field, South Sumatra: A Case Study
Authors: Rilian Nova Arthur , Rohman Adam Fatchur , Hamzah Kamal , Arseto Yoseph Itok , Narso Narso , Kurniawan Candra
Published: October 2012

Continuous gas lift system is currently widely used as artificial lift in Kaji-Semoga Field, in fact at about 46% of total producing wells. The average depth of gas lift wells in Kaji-Semoga is 3,200 ft, utilizing 2 to 5 conventional gas lift valves in a single production string. Common problems experienced when optimizing gas lift wells in Kaji Semoga field are instability of flow due to fluctuation of gas lift injection rate and pressure, limited gas injection volumetric rate, and limited compressor discharge pressure that leads to limited casing head pressure at well head, especially for remote wells with high tubing pressure at injection point.

A new injection valve type, venturi orifice gas lift valve with breaking-out gas device, has been studied and proposed as a solution to the aforementioned problems. This type of valve has been installed as gas lift injection valve at some pilot wells by using slick-line unit. The aim of venturi orifice is to reduce pressure difference between casing (upstream) and tubing (downstream) at injection point and to deliver a greater amount of gas lift injection at the same casing head pressure (compared to traditional orifice valve). Meanwhile, the aim of the breaking-out gas device is to break the injected gas into very small bubbles and homogenize with the liquid so that flow stability can be achieved.

Selected candidates for pilot wells are the ones with high productivity index (PI), high flowing pressure gradient (above 0.18 psi/ft) and limited gas lift manifold pressure. Well modeling and simulation have been conducted for these selected wells using production optimization software to predict gas lift well performance after installation of new injection valve, whereupon the simulation result is matched with actual data.

Applying venturi orifice gas lift valve has produced successful results: the liquid rate of the pilot wells has increased by about 40%, with 30% gas injection rate increment under the same conditions. Computer simulation also provided similar results to the actual well performance and met expectations. The pay-out time (POT) of this project was less than 2 days.
Experimental and Computational Investigations of Viscous Fingering at High Mobility Contrasts
Authors: Dawson M. A. , Yale D. P. , Kushnick A. P.
Published: October 2012

Viscous fingering arising from adverse mobility contrasts is encountered in numerous oil recovery processes and may present challenges to efficient operation. As the mobility contrast between fluids increases, these challenges, such as bypassed oil, become more severe. This paper examines the phenomenon of viscous fingering at high mobility contrast from both an experimental and a modeling perspective. The experimental studies are carried out in a state-of-the-art apparatus, which simulates realistic subsurface conditions. The apparatus is designed to accurately capture the effects of geomechanics at reservoir conditions in a 3D chamber that is over two meters in diameter, enabling examination of the viscous fingering under previously untested conditions. The results of a high mobility contrast experiment with mobility contrast of approximately 25,000 are presented. A simulation of the experiment is also provided. The simulation demonstrates the potential to sufficiently model this complex phenomenon even at high mobility contrast. As enhanced oil recovery methods become more pervasive, understanding and modeling viscous fingering under realistic reservoir conditions is becoming an increasingly important area of research, and the experimental and computational investigations presented herein provide new insight into this complex phenomenon.
A Study on the Remaining Oil After Strong Base ASP flooding
Authors: Zuo Xiwen , Li shiyong , Li Weiyan , Song Rue , Wang Tongwei , Xu He
Published: October 2012

ASP flooding tests in Daqing oilfield show that it can greatly enhance oil recovery and provide a powerful technical support for sustainable development of the oilfield.At present, ASP flooding in Daqing oil field has entered commercial popularization stage and the supporting technologies such as reservoir engineering, production engineering, surface engineering involved with multi-disciplinary, chemical agent quality inspection and field injection have been formed.However, there still lacks in-depth recognition about reservoir developing conditions and remaining oil distribution after alkali ASP flooding. Therefore, on the basis of analysis of dynamic and static data, application data from newly drilled wells and coring data before and after ASP flooding, this paper gives a clear understanding of the reservoir developing condition and oil displacement effect and confirms remaining oil distribution characteristics and its forming causes from macroscopic to microcosmic perspectives and from horizontal to vertical directions then to innerlayers through application of geological research, numerical simulation, lab core detection, nuclear magnetic resonance (NMR) and confocal laser scanning technology. From macroscopic perspective, there is less remaining oil scattering on the plane due to imperfect relationship between injection and production; Vertically, the top of sand body is where remaining oil richly gatheres.Alkali ASP flooding's effect is remarkable for remaining oil and heavy constituents of oil have dramaticly reduced, Especially for membranous remaining oil on the pore surface, and intergranular adsorption of remaining oil has added.

Daqing Oilfield is the earliest one to carry out ASP commercial field test and popularization, and has acquired abundant knowledge about it. But systematic evaluation and analysis of alkali ASP flooding hasn't been formed for there lacks further understanding of reservoirs’producing performance and remaining oil's distribution after alkali ASP flooding. In the A block of thick reservoir alkali ASP commercial field test which has been finished, there are 258 wells newly drilled (including 1 sealed coring well) with well spacing density of 177 wells/ km2.Dynamic data and coring wells’data from the test area are effectively combined with newly-drilled wells’logging information to study microscopic remaining oil in the cores before and after ASP flooding; Meanwile, Methods such as statistic analysis, core displacement, numerical simulation, nuclear magnetic resonance, Carbon/oxygen spectral logging, and dynamic comprehensive analysis are applied with confocal laser scanning technique to ideally detect and analyze remaining oil's type and distribution. It will provide guidance for further adjustments during alkali ASP flooding and for EOR research after ASP flooding.
Assessment of Post-Expanded Mechanical Performance of Materials and Evaluation of Material Expandability Limit
Authors: Bufalini A. , Morana R. , Nice P. I. , Bailey B. M.
Published: October 2012

The expandable tubular technology has seen an increased diffusion in the well construction process. However, while it is accepted in well remediation activities, the consideration given to expandable technology as a primary option for well design is limited. The confidence of the casing material performance after expansion remains one of the main factors in preventing a larger adoption rate. Extreme expandable applications require very high expansion ratios, thus exceeding the elongation to failure of conventional casing materials; even specially selected casing materials are close to the limit of their deformation capability.

Consequently, Statoil decided to extend the scope of a previous research program on materials for expandable applications to include an initial investigation into defining a material's expandability limit. A selected carbon steel grade was analyzed using specific experimental test methods and Finite Element Analysis (FEA), and employing previous results of other carbon steel grades and alloys.

The experimental activities involved tensile tests on post-expanded material using optical systems for the strain measurement, a technique previously adopted for as received material. This method allowed the determination of the true stress-strain curve far beyond the range of standard methods. The uniformity of mechanical properties after expansion was also investigated. The test results showed the carbon steel grade investigated maintained a significant deformation capability even after large expansions.

The FEA campaign analyzed the same materials using a 3D model, which incorporated the pipe eccentricity, to explore other cases and to verify the initial outcomes of expandability limits. The results allowed for the determination of a maximum deformation limit for the materials allowing a successful expansion.
Productivity Index and Inflow performance of Hydraulically Fractured Formations
Authors: Al Rbeawi S.. , Tiab D..
Published: October 2012

Productivity index and inflow performance of horizontal wells intersecting multiple hydraulic fractures are of great importance. This importance comes from the fact that the fracturing process has become a common stimulation technique in the petroleum industry. However, few models for the productivity index and inflow performance have been presented in the literatures due to the complexity governing this topic.

This paper introduces a new technique for estimating the pseudo-steady state productivity index of horizontal wells intersecting multiple hydraulic fractures. Based on the instantaneous source solutions for the diffusivity equation, seven analytical models have been derived for different source solutions. Four of them represent the effect of the formation height and fracture height (the vertical direction), while the other three represent the solution for the horizontal plane. For vertical hydraulic fractures, the four solutions of the vertical direction, representing the pseudo-skin factor, are almost neglected. The three horizontal plane solutions are the main parameters that control the productivity index and inflow performance of the fractured formations. In this technique, the horizontal wells are acting in finite reservoirs where the pseudo-steady state flow is expected to develop. Reservoir geometry, reservoir properties, and fracture dimensions were considered in this technique. The number of fractures and the spacing between them were also investigated in this study. A new analytical model for estimating the required number of hydraulic fractures has been introduced in this study based on the reservoir drainage area and the surface area of fractures.

The models have been used to establish several plots to estimate the shape factor group based on the number of fractures and the half fracture length. This group is one of the main terms in the productivity index model. Several plots for the shape factor of fractured formations have been introduced in this study. The results obtained from the new technique have been compared with the results from previous models. Several numerical examples will be included in the paper.
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

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

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

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

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

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

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

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

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

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

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

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.
Investigation of Shale Gas at Nanoscale Using Scan Electron Microscopy, Transmission Electron Microscopy and Atomic Force Microscopy, and Up-scaling to a Petrophysical Model for Water Saturation Evaluation in Shales
Authors: Wu Peng , Aguilera Roberto
Published: October 2012

Due to quick development in horizontal drilling and fracturing technologies, shale gas, formerly considered very difficult if not impossible to recover, has become one of the hottest energy topics. As a significant number of studies focus on fracture stimulation, drilling and completion optimization, only a limited number of studies have been carried out aiming at the investigation of shale structure at nanometer scale due to limited access to scanning electron microscopy (SEM), transmission electron microscopy (TEM) and atomic force microscopy (AFM), and also due to less experience using these instruments in studies of formation rocks.

SEM and TEM are all capable of revealing nano-scale structures of rock samples. AFM also offers some possibilities. In order to obtain images of high quality and ultra-high magnification, sample preparation is the initial and probably most important step in the whole imaging process. Images from low and ultra low permeability formations in the Western Canada Sedimentary Basin are compared with images from other low and ultra low permeability formations reported in the literature. As powerful as these nanoscale capable microscopes are, they all have limitations due to the high instrument cost, limited access and time consuming imaging process. As a result it is difficult and impractical to obtain statistical significant data. To make these instruments of practical value to geoscientists and petroleum engineers, methods and models need to be developed to build a bridge from detailed nanoscale structures to typical lab/field measurements and practical geoscience and engineering-scale applications. In this paper, we propose the concept of a multiple porosity model for evaluation of shale formation based on our observations of the nanopore structure of shales. This includes a model for determining the porosity exponent m in shales and water saturation evaluation. Water saturation curves based on this model are plotted on Pickett Plots for both tight gas and shale formations.

Continuous studies in this area are needed to further explore shale structure in fine detail in order to understand the role of nanopores on shale gas production.
Integrated Multiwell Formation Evaluation for Diagnosing Reservoir Dynamics
Authors: Ma S. Mark , Al-Belowi Ali R. , Al-Mudhhi Mohammed A. , Al-Ali Zaki A. , Zeybek Murat
Published: October 2012

In this paper, a multiwell data integration approach for improved formation evaluation is presented to describe: (1) Mixing between injected fresh water and saline formation water, (2) Water salinity variation vertically across reservoir intervals, and (3) Injected water movement in the reservoir. Data used included static and dynamic time lapse well data as well as a crosswell electromagnetic (CWEM) survey. With this integrated approach, we can answer critical formation evaluation and reservoir management questions, such as why the formation tester (FT) water sample salinity can be very different from the produced water salinity, and why a well located farthest from the injectors can produce water several years earlier than a well located nearest the injectors. Gaining a complete knowledge of water salinity, distribution, both vertically and areally, and water movement in-situ allows better assessment of reservoir saturation changes with time, thereby improving reservoir management.
Hydraulic Fracturing Model Based on Nonlinear Fracture Mechanics: Theory and Simulation
Authors: Jin X. , Shah S. N. , Sheng M.
Published: October 2012

Recent advancements of hydraulic fracturing in complex formations indicate the limitations of traditional fracturing models stem from Linear Elastic Fracture Mechanics (LEFM) theory, which obeys small-scale yielding rule. This rule breaks down in the crack tip region where the strain is extremely large, so Nonlinear Fracture Mechanics (NLFM) is required in studying fracture initiation and propagation phenomena for ductile rocks and pseudo-brittle rocks. The model in this paper studies fracture initiation angle of an inclined fracture/perforation (the term "inclined" is defined as the crack or perforation that does not coincide with the principal stress direction) based on R-criterion, which assumes that fracture propagates in a direction where the distance from crack tip to the elastic/plastic boundary is minimum. The crack tip opening displacement is solved with the combination of Dugdale model and R-criterion. The simulation results indicate that fracture initiation angle for the ductile and pseudo-brittle rock is less than that of a brittle rock. Furthermore, a crack tip opening displacement decreases with inclination angle and minimum in-situ stress and increases with increasing perforation depth. The hydraulic fracturing model presented in this paper opens a door to understanding why/how fracture gets twisted and narrowed near inclined borehole, why/how skin factor increases sharply near wellbore in hydraulic fracturing and helps us learn how to avoid undesired fracture geometry and "screenout" during hydraulic fracturing treatment execution and to maximize ultimate recovery. It is recommended to alleviate fracture twist by increasing pumping pressure and extending perforation depth by about 30% (based on the perforation of 1ft) when the in-situ stresses distribution is not clear. This model finds large application prospect in fracturing formations that are rich in clay or are high pressure high temperature (HPHT) formations.
Lessons Learned from Building a Large Integrated Production Model for Offshore Assets in Nigeria
Authors: Stevenson A. E. , Wanorue E. P. , Okoro E. C. , Ozen Ozgur
Published: October 2012

This paper describes the process and lessons learned from the construction of a large Integrated Production Model (IPM) in Nigeria. The model will be used to determine optimum development plans for connecting the undeveloped and underdeveloped assets in the Joint Venture (JV) Area into the existing producing fields. In addition, it will be used to identify bottlenecks, and to optimize production in the infrastructure for the existing producing assets for a number of years. For this model to be of value for its intended purpose, it needs to be calibrated and maintained over a period of years because this development work is planned over several years. The process used to assemble and calibrate the models, some of the challenges encountered including keeping the models "evergreen", and our results are presented.

A large IPM model was built for the JV Area assets in offshore Nigeria. The model used the existing ten (10) production platform IPM models in the JV Area and added the fluid and gas gathering network to model the entire JV production system infrastructure to the terminal. All of the reservoir and well models were calibrated and the sub-sheet models optimized prior to being combined into the larger model. The large model construction proceeded in stages to ensure the modeling goals could be reached.
Reconciling Retort versus Dean Stark Measurements on Tight Shales
Authors: Handwerger D. A. , Willberg D. , Pagels M. , Rowland B. , Keller J. F.
Published: October 2012

Due to the complexity of tight shale reservoirs, core analysis has become an increasingly important source of data for evaluating these systems. However, as there are no generally agreed upon testing protocols, there are competing methods for obtaining such primary data as fluid saturations and porosity. The two most commonly employed commercial methods are Dean Stark toluene combined thermal and solvent extraction and thermal extraction by retort. However, the impact of these protocols on the rock and its fluid phases is different, primarily due to the abundance of clays. While the Dean Stark extraction produces a total porosity and total water saturation, data suggest significantly elevated values of these parameters relative to what is measured through the retort process, resulting from significantly higher amounts of water recovered. This distinction is fundamentally important for using core analyses in shale for calibrating logs and/or determining reserves, as both methods claim to report the same parameters.

To understand this effect, we have assembled a data set of compatible core analyses from various laboratories from several wells for a tight-gas shale reservoir in the United States. In addition, we conducted thermogravimetric analysis and Karl Fischer Titration with methanol extraction on splits of the same samples. The retort, thermogravimetric, and Karl Fischer data generally agree in the amount of water eluted from the samples (per gram of rock), while the Dean Stark data show significantly more water. We suggest this excess water could be a portion of the structural water in the clays, which should not contribute to porosity and saturation. Additionally, there is a relationship between this excess water and the total clay content from XRD. This correlation to XRD analyses suggests that a correction can be determined, leading to more accurate porosity and saturation values necessary for proper reserves estimations.