bluuebunny/crossref_metadata_2025 huggingface dataset:
Highly Accurate Prediction of Screenouts in the Eagle Ford Shale with the Screenout Index
Authors: Massaras Leon , McNealy Timothy
Published: October 2012

Development of unconventional resource plays, such as the Eagle Ford shale in south Texas, require that complex multiple hydraulic fracture stages be placed in the horizontal section of the wellbore to be economical. Operational complexity is presented during both the completion and the fracturing phases, which are performed in an orchestrated manner by many contributors. A screenout during one of the fracturing stages will place many of the contributors on a standby status, delays the placement of subsequent stages, and causes costs to increase substantially because of standby charges, wellbore cleanout costs, and lost production days.

The screenout index (SOI) is an empirical indicator developed by analyzing thousands of rate step-down tests (RSTs) from around the world, including hundreds from the Eagle Ford shale. Development of the SOI involved (1) following a specific four-step RST procedure, which requires the fourth rate change be about two times larger than the first rate change (to distribute measurement error over a larger span), (2) determining the instantaneous shut-in pressure (ISIP) in a specific and consistent manner, (3) calculating pressure gradients DP1 and DP4, (4) applying a rate correction to DP4, and (5) calculating the SOI = Corr. DP4/DP1.

The SOI provides an advanced warning of an imminent screenout. This is highly beneficial because it allows modification of the remaining steps of the fracture treatment design and preparation of various decision control options to be executed in the event a screenout occurs or extending the treatment becomes necessary.

Often, an SOI value of less than 0.5 indicates that a screenout is unlikely. If the SOI value is between 0.5 and 1.0, the chances of a screenout increase significantly. An SOI value larger than 1.0 signifies that a screenout is probable. The predictive accuracy of the SOI has been greater than 95%.

Modification of the design of the completion configuration and/or elimination of certain types of completions and procedures can help minimize and possibly eliminate screenouts.
The RCA Corrosion Attack in Once Through Steam Generators Tubes Failures: South Oman Steam EOR Case Study
Authors: Nengkoda Ardian , Supranto Supranto , Prasetyo Imam , Purwono Suryo , Amijaya Hendra , Suryono Sugeng
Published: October 2012

Steam EOR pilot project has been deployed in heavy oil field of Petroleum Development Oman, South Operation, and interestingly after more than a year operation, recently failed due to convection tubes ruptured at "Once Through" steam generator facility. It was found that more than 10 tubes have been affected. When the facility inspection deployed, more than 10 Kg unknown grayish color loose solid has been found in the internals part of the tubes. The quick preliminary interpretation narrowed to inorganic scale due to high hardness in the soft water that feeding to the generator, but later, after conducted comprehensive Root Cause Analysis (RCA) study showed that a mix of H2S and Oxygen played as important roles in the damage, where in common systems, the presence of H2S and O2 are eliminating each others and very rare they are exist as one in a close loop systems. This paper pointing about Root Cause Analysis and understanding of Failure Mechanism through some detail damage study and integrated reservoir - process review analysis are able to achieve the objective to secure long term facility integrity and steam supply. After doing a comprehensive surveillance program and applying sophisticated XRF/XRD techniques, showed predominantly solids are Iron products, such as Iron Oxide and Sulfide. Both SRB and GAB Bacteria as the sources of H2S growth from the water supply wells, while the Oxygen are heavily ingress inside the RO Plant and soft water tank facilities. Finally, after injecting a proper biocide and oxygen scavenger and optimize the dosage, the problems have been mitigated successfully.
OML58- Upgrade: Rejuvenating a 40 year old oilfield onshore Nigeria through Heavy Simultaneous Production and Construction Operations.
Authors: Saintpère Stéphane , Ologe Jacob S , Perrono Fabrice , Ikpa Henry , Udodong John Edet , Lys Jean-Yves
Published: October 2012

It is a unique situation amongst the fields operated by Total that has recently taken place on the OML58 Oil and Gas facilities located in the Niger Delta area of Nigeria. Major financial investments over 4 years, and more than 4000 workers at peak on the different locations of the field, for a total of more than 20 millions worked hours, were necessary to complete the first phase of the transformation of an oil producing site into a gas producing site. Eventually, the field will have its life extended for another 30 years, but if it is mainly oil that has been produced so far, 80 % of the future production will be gas.

These few figures illustrate what is at stake in a region where Total has been operating for over 45 years and has confidence to go further and bring the installations to their full production capacity. Right from the beginning, it was decided that Simultaneous Production and Construction Operations (SIMOPS) would be the mode of operations. Large scale SIMOPS on remote existing aging facilities, spreading over years, is definitely not a usual challenge. It is even more difficult when it takes place on running installations where gas under high pressure circulates almost everywhere. Therefore, a dedicated organization allowing a strict control of the SIMOPS was implemented. The paper will describe the advantages of a transversal approach where production operations teams and construction teams are aligned on common shared objectives. It will also show how a challenging operating approach in a difficult context (unknown underground conditions, aging facility challenges, etc) can lead to a significant reduction of production short-falls without compromising safety. Furthermore, the case will also highlight how such a big project can positively impact the development of local communities and participate to their sustainable development.
Reducing Uncertainties in Casing Depth and Formation Evaluation Using Look-Ahead Logging While Drilling Technology
Authors: Deri C. Peter , Peternell Ana , Hebert John , Fisher James L. , Gibbs Rudy B. , Cornell Robert , Moreno Javier
Published: October 2012

Logging while drilling (LWD) technology has been used successfully to overcome the drilling challenges when exploring a caprock hostile environment in the Main Pass area of the Louisiana Gulf Coast. Because of the geological setting, special steps needed to be taken to mitigate the obstacles and uncertainties while drilling. Successful acquisition and application of selected measurements led to achieving the drilling and formation evaluation objectives.

To drill the optimal wellbore, seismic-while-drilling technology was employed to optimize casing depths and minimize drilling risks such as mud losses and potential H2S. Additional techniques were used to help make the decision to set casing and maintain a viable wellbore for logging and completing the well.

For the second challenge, providing formation evaluation without compromising drilling safety and data quality, additional LWD services were applied. A resistivity-at-the-bit laterolog imager and a multifunction formation evaluation platform were employed to satisfy both the drilling demands and the formation evaluation needs. Having drilling mechanics and formation evaluation measurements available provided not only advanced measurements closer to the bit, giving a better chance of reducing invasion effects, but also impacted the drilling time through shorter rathole section. In addition, the laterolog resistivity imaging provided dips and texture information to map the structure and identify different geological features. Using these technologies, 100 ft were drilled into the caprock with enough information to evaluate the economical value of the prospect reservoir. The combination of these technologies and the ability to interpret the data streamed while drilling allowed the operator to successfully set casing at the top of the limestone caprock. In the end, the drilling risks and uncertainties experienced in the past were totally eliminated by the proper use of LWD technology.
Best Practices for Using Flares to Meet Proposed EPA Emissions Regulations for Hydraulically Fractured Natural Gas or Oil Wells
Authors: Reed Scott D.
Published: October 2012

The new 2012 EPA Oil and Natural Gas Air pollution standards, enacted April 17, 2012, are designed to reduce harmful emissions of VOCs from hydraulically fractured wells. VOCs in the presence of sunlight promote the formation of smog (grade-level ozone) near areas where oil and gas production occurs. The four-targeted areas of VOC reduction in oil and gas production will affect some 25,000 wells per year as well as storage tanks and other processing equipment. Flare systems are proposed as one of the preferred control devices to meet these new regulations.

Complicating the hydraulic fracturing production picture further, the industry expects new EPA flare regulations to be proposed shortly. These regulations are currently under review with public comment underway via the TCEQ and EPA Flare Stakeholder Task Force.

This paper will address specifics of both new regulations and provide guidance for cost-efficient and effective flare system designs.
Optimizing Water Injection Rates for a Water-flooding field
Authors: Liu Feilong , Guthrie Charlie , Shipley David
Published: October 2012

Setting proper water injection rates for the injection wells is a key factor to successfully operate an oil field under water flooding. The success of such activity could (a) reduce water cycling at field, section and pattern levels; (b) improve water/oil ratio (WOR) and areal sweep efficiency; (c) improve oil production and recovery by directing water injection to specific zones and areas; and (d) reduce OPEX by improving water utilization.

Typically, the onsite engineers adjust injection rates using heuristics. While this does improve performance we feel that a more systematic approach can be developed which will lead to further gains. In this paper, we present a systematic method, using the linear programming, to optimize the water injection target rates.

In this method, the reservoir is considered to be a system which can be modeled as a collection of continuous-time impulse responses that convert injection rates into a production rate. A very simple two parameter parametric model, like diffusivity-filter, has been used to quantify the injector-producer continuous-time impulse responses channel model and the Extended Kalman Filter has been used to establish the allocation factors between injectors and producers in the water-flooded field. Subject to constraints, including the total available water amount, the maximum and minimum injection rates, the maximum total production fluid for a producer and a gauge setting, a linear programming optimizer has been applied to determine the optimized water injection rate, based on the established allocation factors.

This method was pilot tested on a Chevron oilfield for 3 months. The decline curve for 6 months and for 2 months of historical oil production data have been calculated. The 3 month pilot test result indicated that the optimized oil production matches the historical 6-month decline curve very well with about 22% less total daily water injection. Also we saw about 2% incremental production above the historical 2- month decline curve (again with about 22% less total daily water injection). These results suggest that this systematic method may provide a way to optimize the water injection target rates.
Getting Ahead of the Regulators by Building Your Own Emissions Profile
Authors: Stuver Susan , Alonzo Jesse , Holditch Stephen , Mills Skip
Published: October 2012

abstract

Research Objective

Development of improved air emissions management through better emissions estimation methodologies and best available estimation techniques for hydraulic fracturing phases.

Problem Statement - Policy without data

Federal and State regulators are developing air emissions regulations that will have an impact on the oil and gas industry. In the near future, regulatory requirements will be put in place that entail the measurement and reporting of such air emissions as NOx, VOCs, Greenhouse gases (such as methane), NO2, SO2 and more.1 Historically, air emissions studies have been conducted using methods that sample off site, ambient air. Much of the data gathered in this fashion falls short because this collection method fails to consider emissions transport from other industry such as power generation, waste water treatment, or even emissions that blow in from other countries. It also falls short of being helpful to the industry since the operators and service providers are left questioning which pieces of equipment are producing these emissions if any.

Solution

If properly characterized, these sources may be eliminated from regulatory compliance requirements by simply identifying and demonstrating their minimal contributions as de minimis sources. The research team traveled to a hydraulic fracturing site on the Eagle Ford Shale Play and collected real time activity data from equipment that has the potential to release large amounts of air pollutants. Actual run times and load factors of the engines were measured. The activity data was then compared to data collected in the traditional manner of conservative off-site emission assumptions. Regulators performing offsite estimates will typically default to the conservative assumption that engines are operating at 100% load and 24 hours a day, and every day that the operation occurs.
The Core Analysis Elephant in the Formation Evaluation Room
Authors: McPhee Colin
Published: October 2012

Core analysis provides the only direct and quantitative measurement of reservoir petrophysical properties and should provide the ground truth for integrated formation evaluation. However variable data quality, the sensitivity of results to different test methods, poor reporting standards, and the reluctance of some vendors to share experience and expertise have all contributed to basic mistakes and poor data quality. It is easy to blame the vendors, but in too many cases, an inconsistent or inappropriate approach to the design, management and interpretation of the core analysis programme has been adopted and exacerbated by the conflicting requests of the end users. In combination, this has led to a situation where around 70% of legacy SCAL data are not fit for purpose.

We present a core analysis management road map which is designed to increase the value from core analysis investments by enabling a more pro-active, more coherent and more consistent approach to programme design and data acquisition. Firstly, this involves reviewing legacy data and understanding the impact of rarely-reported experimental artifacts on fundamental rock property measurements. Can data be corrected or re-interpreted or are new tests required? Secondly, a multi-disciplinary core analysis management strategy is described. This is designed to encourage more effective engagement between stakeholders and the data acquisition laboratory through improved test and reporting specifications, pro-active test programme management, and real time quality control.
Acoustic Induced Vibration (AIV) Case Study for WDDM Onshore Facilities
Authors: Moussa Atef Mahmoud
Published: October 2012

In gas applications with high-pressure drops and/or high-velocity gas flow, Acoustic Induced Vibration (AIV) occurs when very high sound levels are propagated in piping. If the sound levels are high enough, they will excite the circumferential vibration modes of the pipe. This allows the pipe to vibrate in and out as the sound wave moves through the piping. Most often this occurs downstream of pressure-reducing valves or safety-relief valves PSV‘s but AIV can occur at any location where the pressure drop or mass flow rate is sufficiently large. The level of pipe wall vibration is so high that it can induce fatigue cracking of the pipe and potentially cause catastrophic pipe failure. West Delta Deep Marine (WDDM) onshore of the slug catcher M9001 had a recent failure in the flare header as result of accumulating AIV effect. As a consequence of this failure Enppi/Burullus & Foster Wheeler undertaken an engineering assessment study to investigate the risk of AIV (Acoustic Inducted Vibration) for hall the plant & find out the corrective & engineering solution to protect the plant from any failure could be occurred as resulting of AIV affect.
Eagle Ford Shale - An Early Look at Ultimate Recovery
Authors: Swindell Gary S.
Published: October 2012

Although the Eagle Ford shale is early in its history, the study provides a comprehensive examination of per well recovery and decline data in the South Texas trend using the latest production information up to early 2012.

Individual forecasts of the estimated ultimate recovery (EUR) were made for more than 1,000 horizontal wells in the South Texas Eagle Ford shale trend and statistics were developed for EUR in the 10 primary counties where development is occurring. The study used rate vs. time plots and included all the producing wells in the trend which have decline data believed to be sufficient to project EUR. Normalized decline curves were developed for each county and distributions of EUR were produced. In addition, for a portion of the wells, correlations were made between EUR, frac size, horizontal length and the date of first production.

The results show that for the 10 county trend, the average and median EUR per well were 206,779 barrels of oil equivalent (BOE) and 160,519 BOE, respectively. Of the counties with more than 50 wells, the best are DeWitt (403,715 BOE) and Karnes (210,801 BOE). Live Oak, with only 28 wells averages 248,818 BOE. The normalized rate vs. time plots show minor hyperbolic behavior. In fact, for all the wells in the study, the normalized oil decline was 76% and the gas 60%, with hyperbolic exponents of .25 and .40, respectively. The wells have clearly become better since the start of horizontal drilling, but the average performance has not shown much improvement since mid-2010 even as the frac sizes became larger. The best well performance has generally come from wells with horizontal legs in the 4,000 to 5,500 ft. range.

The South Texas Eagle Ford shale trend is one of the most active in the US, adding approximately 100 new producing leases each month. Although a great deal is being written about the trend, there is a lack of independent, hard data on per well reserves. This study provides an early look at individual well ultimate recovery.
Field Application of Polymer Microspheres Flooding: A Pilot Test in Offshore Heavy Oil Reservoir
Authors: Liu Chao , Liao Xinwu , Zhang Yunlai , Chang Ming-Ming , Mu Chunrong , Li Tingli , Qin Runsen , Fu Rong , Bie Xvwei , Zheng Jianjun
Published: October 2012

Chemical injection has been used to combat reservoir sweeping and water-control problems in the last two decades with different degrees of success. Many of the methods face the challenges of chemical durability, penetration depth, rock-fluid compatibility, and economical justification. Polymer microsphere injection is a new method developed recently to address these challenges in controlling waterflood conformance to enhance recovery efficiency. Made by emulsion synthetic technique the polymer microsphere expands at contact with reservoir water resulting in plugging of high permeability pore throat deep into the formation to divert the water flow path. The laboratory experiments showed an improvement of recovery factor by 14 to 16%. This paper presents the first field test in an offshore environment of a heavy oil reservoir Q in Bohai Bay in China.

Q oilfield is a heterogeneous heavy oil reservoir suffering from fast water breakthrough with poor recovery. The polymer microsphere was injected into an eleven-well pilot. The injection pressure increased following injection of microsphere solution. Multiple fall-off tests were performed to monitor the plugging of flow channels at different times. The time taken to reach the reservoir pressure in the fall-off test increased with flooding time for four months demonstrating an effective channel plugging. Most of surrounding producers showed responses to microsphere injection in both pressure and oil production. The incremental recovery benefit to the test cost is estimated to be 4:1 to 6:1.

The encouraging pilot test demonstrated the potential of polymer microsphere flooding to combat reservoir conformance challenge. This test needed simple equipments which were easy to be operated in the offshore platform environment. Further polymer microsphere flooding tests are in plan in China Bohai Bay area.
The Wafra Field First Eocene Carbonate Reservoir Steamflood Pilots: Geology, Heterogeneity, Steam/Rock Interaction, and Reservoir Response
Authors: Meddaugh W. Scott , Osterloh W. Terry , Gupta Ipsita , Champenoy Nicole , Rowan Dana , Toomey Niall , Aziz Shamsul , Hoadley Steve , Brown Joel , Al-Yami Falah
Published: October 2012

The Paleocene/Eocene First Eocene dolomite reservoir is a candidate for continuous steamflooding due to its large resource base and low estimated primary recovery. There are two steamflood pilot projects in operation to evaluate reservoir response to steam injection: a single pattern pilot (SST) and a 40-acre, 16 pattern pilot (LSP). At the SST an interval with abundant tidal flat cycle caps characterized by muddy, finely crystalline dolomites with low porosity and permeability may be the observed vertical barrier to steam migration. Detailed studies, including micropermeameter measurements and micro-CT scans were used to characterize the heterogeneity. Data suggest that similar vertical barriers may exist at the LSP. Early steamflooding results show a positive response to injection and multiple thermal events (likely baffles rather than barriers). The data also shows the occurrence and distribution of some lateral high permeability pathways between injectors and producers as well as between producers. While the rapid temperature response observed in a few wells may reflect fractures or karst-like zones, simulation using very fine grids shows that some wells will experience very short breakthrough times without fracture or karst-like zones.

Injection of high temperature, high pH fluids may induce fluid/rock interactions that affect reservoir fluid flow near-well and in-depth. This in turn could affect storage capacity, production and injectivity. Reactive transport models (2D-RTM) were run to simulate high pH steam injection into the First Eocene reservoir for a continuous injection period of 6-12 months to understand possible changes in mineralogy, coupled with porosity change and potential scaling. Initial results predict precipitation of calcite and brucite, dissolution of dolomite and anhydrite, and conversion of gypsum to anhydrite. Sensitivity studies examined the impact of steam quality, pH, rock surface area, reaction rates, and mineralogy.
Workflow to Evaluate Maximum Allowable Treating Pressures, Tubing Movement, and Tubular Limits for Deepwater Subsea and Dry-Tree Fracpacks
Authors: Strobel Marshal , Oubre Brennan , Holley Alan
Published: October 2012

Deepwater wells using fracpack stimulation are progressively moving to ultradeep water depths and total depths; the bottomhole pressures (BHPs) and temperatures of future reservoirs could exceed 20,000 psi and 250°F. To safely perform deepwater fracpack treatments, the following pressure and tubular limitations should be considered:

Maximum surface tubing pressure because of pipe limitations and gravel pack assembly component ratings. Maximum surface annulus pressure because of blowout preventer (BOP) ratings. Maximum allowable tubing movement while pumping to help prevent premature job cessation. Maximum allowable downhole slackoff and overpull because of well path, pipe, pipe connections, and downhole component ratings.

Depending on the well depth, pressure, temperatures, and BOP type (subsea or dry-tree), various pipe, connection, or equipment limitations might be exceeded during multistage fracpack stimulation operations. Initial pipe loading as well as pre-fracpack stages, such as the pickle, acid treatment, or minifrac calibration treatment, will alter the pipe failure and movement conditions and must be accounted for in the final completion design.

Because of these concerns, a workflow process has been delineated to evaluate the maximum allowable treating pressures, tubing movement, and tubular limits for deepwater subsea and dry-tree fracpacks across four components:

Input component to consolidate well and stimulation data for further workflow analysis. Surface treating pressure evaluation component to analyze certain treating pressure limitations. Commercial wellbore, casing, and tubing simulator to evaluate work string safety factors, tubing movement, and downhole forces. Commercial torque and drag simulator to evaluate surface slackoff requirements and allowable work string overpull.

A description of the variables, range of values, and other considerations for each of these four components is discussed, and the benefits of using this process to evaluate fracpack stimulation are shown. Well case histories are also used to support this process.
Field Application Results of Water Permeability Modifier in Fracture Stimulation Treatments in Western Siberia
Authors: Ladut'ko Alex , Goss Michael , Dalrymple E. Dwyann , Chang K. T.
Published: October 2012

Historically, hydraulic-fracture stimulation of zone zones with directly underlying waters has not been considered a practical method for improved oil recovery. This was because the stimulation treatment could result in water cuts from 90-100%.

Many of the oil and gas reservoirs in Western Siberia have production zones that fall into this scenario. The zones contain high-permeability streaks of mobile water and have water bearing layers above and/or below the producing zone. When a hydraulic-fracturing treatment is performed on such production zones, unintentional stimulation of the adjacent water bearing layers occurs. As a result, high water production is observed from the high permeability streaks of water or the adjacent water-bearing layers. Over a period of time, those wells will continue to lose hydrocarbon production rate, while the water cut continues to increase. Water separation and disposal of the produced water is expensive and not always successful.

Using recent water permeability modifier (WPM) chemistry advances, the hydraulic-fracture stimulation of such zones has now been shown to be an effective way to stimulate and produce the mature oil and gas fields such as those found in Western Siberia. The incorporation of a water permeability modifier with a hydrophobic backbone containing hydrophilic branches with the hydraulic fracture stimulation has proven to be very effective in obtaining oil production above what was anticipated based upon comparison with offset wells fracture stimulated without the WPM. It was further observed that not only was the produced water rate typically less than previously observed, but that it continues to decline over time instead of increasing.

This paper presents the results of the implementation and analysis of 11 WPM fracture-stimulation treatments that were performed in a field in Western Siberia in 2009. Discussed will be the WPM technology, treatment design, post production analysis, and recommendation selection of candidates and successful implementation of the WPM technology in the western Siberian fields.
New York Field Trial of Ultra-High Salinity Brine Pre-treatment: Texas A&M Environmentally Friendly Drilling Technology for the Marcellus Shale
Authors: Burnett D. B. , Vavra C. A. , Platt F. M. , McLeroy L. K. , Woods R. W.
Published: October 2012

Shale gas development relies heavily on multi-stage hydraulic fracturing to maximize the economic viability of each new well. In recent years, the industry is aiming at re-use of frac flow back brine to reduce costs and environmental impact of operations. The challenge is to identify technologies and approaches for treating the frac water that returns to the surface following a frac job (frac flowback water) for beneficial re-use in other applications, thereby conserving other local freshwater supplies. Field trials in upstate New York have been conducted to test new technology to treat brines characteristic of flow back brines from the Marcellus Shale and make them amenable for re-use in subsequent oil field operations.

The Texas A&M GPRI produced water treatment program began in the year 2000. In the past decade we have shown that produced water and frac flowback brine from shale gas and tight gas well drilling operations can be treated and reused instead of tapping in to additional fresh water resources. Now the program is working to demonstrate that low cost, mobile units can be deployed in field operations to replace the more costly and environmentally questionable practices currently being employed in field operations.

This report describes the field trial in Chenango County New York conducted by the Texas A&M Desalination Program during the 3th quarter of the year 2011. The specific goal of the field trial was to develop and utilize a mobile unit to demonstrate the effectiveness of different membrane technology suitable for use with high salinity flow back brines and produced water from the Herkimer formation the brines deemed the equivalent of Marcellus Shale brine.

The several treatment techniques which have been found to be successful in both pilot plant and field tests have been tested to incorporate into a single multifunctional process train. Eight different components were evaluated during the trials, two types of oil and grease removal, one BTEX removal step, three micro-filters, and two different nanofilters. The performance of each technique was measured by its separation efficiency, power consumption, and ability to withstand fouling overall, the field trial was a success. Of the four field brines evaluated, three were treated with minimal problem. Over 6,000 gallons of brine were processed. Total power cost was approximately $1.00 per barrel of fluid treated.
Vane Pump-Another Promising Artificial Lift Form?
Authors: Wang Tongbin , Shen Zejun , Pei Xiaohan , Hao Zhongxian , Zhang Lixin , Wang Quanbin , Liu He , Qian Jie
Published: October 2012

In thermal production well, beam pumping lifting is still the major artificial lift form in spite of its high cost on surface equipments and huge energy consumption. In conventional progressive cavity pump (PCP), the interior stator is made of synthetic elastomer, the steam temperature is too high for it to work. For the lift in high-temperature wells, in a long time, we did not have a good solution that can balance both mechanical efficiency and high temperature resistance. We developed a new lift manner by using vane pump as the down-hole pump to lift oil to the surface. According to the down-hole conditions, we redesigned the structure of vane pump with small radial size and transporting fluids axially. As same as PCP, the vane pump lift system and its rotor is driven by a surface drive head through the rotating rod strings. There is no initial tightness between the rotor and the stator of the vane pump that are all made up of metal elements. It can resist the temperature of 250 °C and be used in high oil-gas ratio well and heavy oil well. The vane pump's flow rate is about 5 to 100 cubic meters per day, and the pressure rating can reach 20MPa. The vane pumps have been deployed in five steam flooding wells. Compared with the beam pumping unit with the similiar liquid-producing capacity, the energy consumption of vane pump is 30 percent lower. Until now, the longest operation time span is 11 mouths, and all pumps are in good condition. Maybe in the near future, vane pump lift system will become another important artificial lift form. In this paper we will discuss the design of vane pump and its artificial lift system, its benefits and case histories in details.

Key words: Artificial lift, vane pump, multiple-stage vane pump, thermal production well
Cementing Sleeve Fracture Completion in Eagle Ford Shale will Forever Change the Delivery of Hydraulic Fracturing
Authors: Ferguson Kip , Thomas Colton , Wellhoefer Ben , Ingram Stephen , Montes Matthew
Published: October 2012

The completion cycle for the development of unconventional resource plays, such as the Eagle Ford shale in South Texas, requires multiple hydraulic fracture stages to be placed in the horizontal section of the wellbore to effectively stimulate the reservoir. Inefficiencies in the completion design caused by conventional "plug-and-perf" (P-n-P) methodologies can increase the costs associated with the delivery of hydraulic fracturing. However, new methodologies have recently been developed to mimic the P-n-P process that allow the operator to fracture stimulate the reservoir in a more economic and time-efficient manner.

The Eagle Ford shale in Lavaca/Gonzales Counties, Texas is similar to many high-carbonate-content oil shale formations. In South Texas, the industry has a preference for cementing the lateral section for fracture stage isolation. This case study explores the successful implementation of a cemented multientry point sliding sleeve technology (CMEPT) in the Eagle Ford shale. The combination of these technologies was the first ever of its kind. This study also illustrates some of the lessons learned during the years of development of this integrated service technology.

This paper highlights the key well that successfully implemented these technologies. The Kudu Hunter No. 1H well was drilled to a measured depth of 16,302 ft with a lateral length of over 6,000 ft. The integrated service design proposed a hybrid completion design with 2,000 ft of lateral completed by means of a nine-stage CMEPT and the remaining 4,000 ft of lateral completion by means of the P-n-P method.

The CMEPT allowed the placement of ~1,840,000 lbm of premium white sand with surface modification agent (SMA) by means of 1,740,000 gal of guar-based hybrid fluid over nine stages in 22 hr, and the remaining 11 stages of P-n-P completion placed ~2,310,000 lbm of premium white sand and SMA by means of 1,940,000 gal of guar-based hybrid fluid in ~80 hr.

The stand-alone conventional P-n-P process has become a barrier to the economic delivery of fracture stimulation. This case study illustrates how the adoption of the CMEPT integrated service process provides efficiencies in the completion cycle and maximizes stimulated reservoir volume (SRV) along the well path.
Event Detection for Managed-Pressure Drilling: A New Paradigm
Authors: Saeed Saad , Lovorn Randy , Davis Nancy
Published: October 2012

Effective event detection has traditionally been a largely manual process, exclusively in the realm of experienced personnel, who not only continuously monitor drilling parameters but also identify the current state of operations based on this data. Owing to the large number of variables and inherent uncertainties in drilling operations today, this approach still provides one of the most reliable methods. However, as a result of the advent of managed-pressure drilling and the need to carefully control and manipulate bottomhole pressures within a specified "window," the proper diagnosis and management of well events has become even more critical. Furthermore, with the popularization of an "automated" control philosophy, this can only be fully realized with an integrated event-detection system. Because a manual approach to event detection does not provide the mechanisms required to support such a philosophy, a real-time automated event-detection system is essential.

A number of approaches have been tried in the industry to implement such an event-detection system with varying, but limited, success. The approach has typically been based on a collection of rigid and archaic logic-based statements, which attempt to overly simplify and abstract operational complexity, leading to a superficial, limited, and inefficient system.

This paper presents a new, novel, and efficient approach to a real-time, automated event-detection system for managed-pressure drilling operations. Events will be discussed and followed by a detailed description of the system, algorithms, and approaches.
Precipitation Squeeze and the Use of Modeling to Maintain Production and Extend Squeeze Life Time for Marginal Wells
Authors: Guan Hua , Davis Steve
Published: October 2012

Scale inhibitor squeezes are used to prevent or control scale formation in producing wells. Most studies focus on the challenges and impacts of executing squeezes in difficult environments like those found offshore in the North Sea. However, squeeze studies on land-based wells with economic challenges can also be rewarding. In difficult economic environments service companies are actively involved in developing pilot squeeze programs to increase or sustain production from marginal wells. Results from these pilot squeezes must be justified economically if the programs are to be extended to other wells or fields.

This paper demonstrates how the use of additives, the forced precipitation technique and sophisticated scale modeling programs can be successfully applied to wells that are economically marginal. The example is a two-zone, forced precipitation squeeze using additives for both pre-flush and overflush packages. Following the successful application of the squeeze package, the resulting squeeze life for this well is 12 months. Average oil production from both zones for the 12 months after the squeeze is much higher than the production for the preceding 12 months. There is no evidence of formation damage in either zone. Squeeze modeling is used to simulate and optimize this squeeze to determine if the squeeze life can be extended further. This paper illustrates a successful field squeeze using additives in a forced precipitation squeeze which resulted in improved oil production and extended squeeze lifetime in a marginal well.
Design, Qualification, and Installation of Openhole Gravel Packs: Mari B Field, Offshore Israel
Authors: Healy John , Sanford Jack , Reeves Donald , Dufrene Kerby , Luyster Mark , Offenbacher Matt , Ezeigbo Eze
Published: October 2012

A case history from Offshore Israel is presented that describes the successful delivery of two ultra high-rate gas wells (>200 MMscf/D) completed in a depleted gas reservoir with 9⅝-in. production tubing and an openhole gravel pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possesses high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝-in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process with particular emphasis on the sand control design, testing and execution. The completions were installed with minimal issues (NPT ≈ 9%) and have produced without incident. The two wells, Mari-B #9 and #10, achieved a peak gas rate of 223 and 246 MMscf/D, respectively.
Sensitive New NMR Hybrid T1 Measurements for Gas Shale, Heavy Oil, and Microporosity Characterization
Authors: Li Lilong , Chen Songhua
Published: October 2012

For NMR-based formation evaluation, measurement of the longitudinal relaxation time, T1 is a preferred technique for LWD because it is less vulnerable to vibration as compared to T2 measurements. For wireline NMR logging, interpreting T1 data is simpler than T2 because T1 is not affected by the additional signal decay caused by the molecular diffusion in magnetic field gradients. Moreover, T1/T2 provides additional formation and fluid information than T2 alone. Despite these benefits, the commonly used T1 measurements may suffer from either very long measurement times using the inversion-recovery (IR) data-acquisition method or reduced sensitivity in the short-relaxation time range using the saturation-recovery (SR) method. Therefore, there is an increased interest in developing more efficient T1 measurements that have adequate sensitivity for fast- relaxing components abundant in gas shale, heavy oil, and carbonates with microporosity present.

We describe a new approach of using a hybrid saturation-inversion-recovery (HSIR) sequence that takes advantage of the higher sensitivity for the short inversion times in the IR sequence and the efficient data-acquisition feature in the SR sequence. To demonstrate the benefit, we simulated many cases representative to gas shale, heavy oil, and carbonate rocks using the standard SR and new HSIR methods. We used Fréchet distance to quantitatively determine the resemblance between the input models and the inversion results and found that HSIR is consistently better in terms of the fidelity to the model. Core measurements are also presented to support the simulation studies. It is shown that HSIR is able to differentiate signal from organic matter in shale samples from other signals, while SR method is not; it is also demonstrated that HSIR can better separate microporosities in carbonate samples than SR, while using a fraction of the time used in IR method.
Evaluation of Reservoir Connectivity from Downhole Fluid Analysis, Asphaltene Equation of State Model and Advanced Laboratory Fluid Analyses
Authors: Dong Chengli , Petro David , Latifzai Ahmad S. , Zuo Julian , Pomerantz Andrew E. , Mullins Oliver C.
Published: October 2012

Characterization of complicated reservoir architecture with multiple compartments, baffles and tortuous connectivity is critical; additionally, reservoir fluids undergo dynamic processes (multiple charging, biodegradation and water/gas washes) that lead to complex fluid columns with significant property variation. Accurate understanding of both reservoir and fluids is critical for reserve assessment, field management and production planning. In this paper, a methodology is presented for reservoir connectivity analysis, which integrates reservoir fluid property distributions with an asphaltene Equation of State (EoS) model developed recently. The implications of reservoir fluid equilibrium are treated within laboratory experimentation and equation of state modeling. In addition to cubic EoS modeling for light end gradients, the industry's first asphaltene EoS the Flory-Huggins-Zuo EoS is successfully utilized for asphaltene gradients. This new EoS has been enabled by the resolution of asphaltene nanoscience embodied in the Yen-Mullins model. Specific reservoir fluid gradients, such as gas-oil ratio (GOR), composition and asphaltene content, can be measured in real time and under downhole conditions with downhole fluid analysis (DFA) conveyed by formation tester tools. Integration of the DFA methods with the asphaltene EoS model provides an effective method to analyze connectivity at the field scale, for both volatile oil/condensate gas reservoirs with large GOR variation, and black oil/mobile heavy oil fields with asphaltene variation in dominant.

A field case study is presented that involves multiple stacked sands in five wells in a complicated offshore field. Formation pressure analysis is inconclusive in determining formation connectivity due to measurement uncertainties; furthermore, conventional PVT laboratory analysis does not indicate significant fluid property variation. In this highly under-saturated black oil field, measurement of asphaltene content using DFA shows significant variation and is critical for understanding the reservoir fluid distribution. When integrated with the asphaltene EoS model, connectivity across multiple sands and wells is determined with high confidence, and the results are confirmed by actual production data. Advanced laboratory fluid analysis, such as two-dimensional gas chromatography, is also conducted on fluid samples, which further confirms the result of the DFA and asphaltene EoS model.
Engineering Approach to Optimize Development Strategy in the Oil Segment of the Eagle Ford Shale: A Case Study
Authors: Stegent Neil , Wagner Albert , Stringer Chuck , Tompkins Rick , Smith Nick
Published: October 2012

This paper presents a case study of the implementation of an integrated engineering approach to drill, complete, evaluate, and optimize multiple sets of parallel horizontal wells in the oil segment of the Eagle Ford Shale.

Two sets of horizontal wells were drilled parallel to each other in the Eagle Ford Shale. Chemostratigraphic analysis was utilized during the drilling process to assist in understanding the placement of the horizontal wellbores with regard to the target pay interval as well as assess area faulting. This data was used in designing the stimulation stage intervals and to evaluate surface injection responses during the fracture treatments. Ball-activated fracture valves and plug-and-perf completion strategies were tested to determine whether one is superior to the other. Oil-soluble tracers were used to understand the efficiency of these different completion strategies and aided in the production comparisons. Downhole microseismic mapping was also used to assist in the completion evaluation.

The integration of various engineering data allowed for interesting conclusions about horizontal wellbore placement and the effect it has on the fracture stimulation treatments, as well as the resulting production from the comparative wells. These insights provide important information for optimizing infill drilling, well placement, and fracture completion strategies in the Eagle Ford Shale. The lessons learned were implemented on additional wells in the same field and all of these results will be discussed.
Modeling System Improves Salt Drilling Technique with Concentric Reamer/RSS, Deepwater GoM
Authors: Edwards Hal , Noort Roger Van , Clairmont Brian , Compton Molly , Davis Patrick , Fitzmorris David , Franco Mariana , Nagaraj Mahavir , Nelson Gail
Published: October 2012

Development of subsalt pay zones in deepwater GoM typically includes drilling long intervals of halite formation. Despite the relatively low UCS, salt drilling presents a unique challenge due to its plastic nature and tendency to creep. These factors coupled with complex deepwater casing programs necessitate the use of hole enlargement while drilling techniques. The difficulties of HEWD in salt is further magnified in deviated wellbores where maintaining the directional wellplan becomes a key performance objective.

Using a 4D modeling program has resulted in improved HEWD ROP and directional control in salt on several deepwater GoM projects. The software allows engineers to model various RSS BHAs, optimize the bit/reamer cutting structure and prepare operating parameter recommendations tailored for the directional plan.

Well A

A Mississippi Canyon j-shaped well called for maintaining tangent at 44degrees through a 100% salt 14.5 ×16.5 interval. Using a new reamer cutting structure design with a selected PDC allowed the operator to drill 7852ft at an ROP of 54.7ft/hr. The directional objective in the 12.25×14.75 interval of the same MC well was to hold tangent at 44 degrees before dropping to 15degrees. A new cutting structure design with a selected PDC was employed on the RSS/BHA. The 6022ft interval was drilled in one-run with an average ROP of 80ft/hr.

Well B

Maximum ROP was the primary objective in an 8877ft, 14.75×16.5 section of a s-shaped well which included building and holding at 35 degrees before dropping back to vertical in 100% salt. Bit and reamer recommendations and drilling parameter recommendations to maximize ROP were developed by calibrating the data from the offset well, Well A. The new cutting structure and pre-job planning resulted in a total run ROP of 97.5 ft/hr with an average on-bottom ROP of 129.1 ft/hr, an 80% improvement compared to offset.