bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Fitness Program in the Workplace: The Unocal Philippines Inc. Experience
Authors: Surara R. C. , Lacsa R. P.
Published: December 2007

Introduction

To improve employees' interest and participation on the fitness program and maximize utilization of the company's fitness gym equipment, the company's aerobics program was improved to a new fitness program that emphasized cardio- endurance exercise and overall muscle conditioning.

Method

The program was offered to all employees targeting those who were under the cardiovascular/diabetes programs and with weight problems. Lecture on the Benefits of Exercise Nutrition were conducted by the Health & Medical Services. Enrollees were referred to a nutritionist for dietary prescription. A demonstration and return-demonstration of body exercises were facilitated. A two-week daily close monitoring on proper exercise execution was observed to assure efficiency and safety of the training.

Each enrollee has an individual 3-month exercise program developed. The 20-minute aerobics exercise or an equivalent exercise/activity is to be done at least three times per week alternate with weight training exercises for 45 minutes to an hour.

A Fitness Diary was designed and given to each participant as a guide to track their progress after the two-week rigid hands-on training. Participants were advised to visit the clinic on a weekly basis to review their compliance and deficiencies on the program. A baseline measurement of an employee's HRA and weight were taken before the start of the program and after three months.

Results

Thirty-seven employees voluntarily enrolled to the 1st batch of the company's Fitness Program. Out of 37 volunteers, 33 employees completed the program. Compliance - 10 (30.3%) had good compliance to the exercise schedule; 17 (51.5%) with declining compliance or intermittent exercise after two months of good compliance; and 6 (18%) had skipped the weight training portion of the fitness program. HRA results

- 2 employees (6%) have improved their heart risk score; (from moderate to low); 29 (88%) have maintained their risk score; and 2 (6%) had higher scores. Weight - 19 employees (57.5%) have improved from their baselines; 7 (21.2%) have maintained and 7 (21.2%) gained weight.

Conclusion

The enhanced UPI fitness program was well received and more appreciated by the employees, specifically the enrollees. Improved attendance of employees utilizing the fitness gym was noticeably significant. The program is more flexible compared to the previous aerobics program, thus employees were able to perform the prescribed exercises in the company's fitness gym and can also do the exercise program at a local gym or even at their own home. Improvements or reinforcement to sustain participation: strict adherence to the prescribed diet by the participants; an improved monitoring compliance of the parameters; a bigger gym area to accommodate more employees; training for other nurses as gym facilitators; and incentives to enrollees are strongly recommended.
Successful Gas Shutoff With Gel: Evaluation and Implementation, Northeast Venezuela
Authors: Llamedo C. M. A. , Mejias C. F. V. , González C. E. R. , Espinoza R. J. , Valero E. M. , Calis N.
Published: December 2007

Non- Conventional Enhanced Oil Recovery Methods are important for PDVSA in Venezuela in order to increase oil production.

Active improved oil recovery projects in PDVSA oilfields are mainly done by water injection in reservoir flanks, water injection by pattern, and by gas injection in the crest. Most of the production associated to these projects represents more than 40% of the total oil production, which includes condensate, light and medium oil production. In most of the cases, the recovery factor of the water injection projects do not exceeds 30% of original oil in place; whereas in projects under gas injection they can reach a recovery of 45%.

Over the last 7 years, more than 50 wells have been treated with gels formulated at PDVSA-Intevep. The application is considered a successful alternative to improve injection profiles and/or productivity.

In this work the effectiveness of Multigel® for gas shut off is tested. We included the diagnosis, design, and treatment in a producing oil well with a high gas to oil ratio located in North East Venezuela. The design of the treatment with both Multigel® and cement was done to isolate producing gas zones. The selective treatment and the results of the application of the technology are described. In the case of gel treatments a criterion adapted for the calculation of the volume must be used, in order to ensure the success of the application. The selection of a stable polymeric gel system at reservoir conditions is very important to guarantee a secure application and the operational sequence of the treatment. The main conclusion of this work is that there are three essential steps in a successful gel application treatment: diagnosis, design of the treatment and injection of the system in the field. In this application the combined gel-cement technique was used for gas blockade; it showed more effectiveness and assurance the complete seal to gas flow. The well was re-open to production with a low and permissible gas-oil relation, and now it is almost a half of the previous ratio before the treatment.
Formation-Tester-While-Drilling Experience in Caspian Development Projects
Authors: Finneran J. M. , Green C. , Roed H. , Burinda B. J. , Mitchell I. D. C. , Proett M. A.
Published: December 2007

A new formation-tester-while-drilling tool (FTWD) introduced to the Chirag field, in the Caspian Sea, in December 2003 has resulted in significant time savings. As of 1 December 2004, it had been run in two additional wells at Chirag, including the longest well with the greatest step out drilled to date in the Caspian region. Prior its use in this particular well, the tool had been qualified by comparison to wireline measurements which have established its ability to make accurate formation pressure measurements in the high-permeability formations of the field.

Use of the tool has involved improvement and optimization of test procedures to consider better depth control, the possibility of stuck pipe risk, and mud cake integrity. Recent Caspian experience has also included the use of a new 8-in. diameter multi-drawdown version of the tool at the Central Azeri field.

The Chirag field has been producing since 1997 and has been under water flood since 1999. To date, the Pereriv reservoir has produced over 300 million BO from 14 wells. Current oil production is 142 thousand BOPD, and water injection is 135 thousand BWPD.

The reservoir is in a very dynamic state, and FTWD pressure data are critical to reservoir management. Specifically, layer pressure data is used to tune the reservoir simulator, monitor injection response, and map dynamic fluid gradients in the field.

This paper focuses on experience from the use of GeoTap tool compared to wireline tester results at the subject fields including highlights of operational learning points.
Survival Analysis: The Statistically Rigorous Method for Analyzing Electrical Submersible Pump System Performance
Authors: Bailey W. J. , Weir I. S. , Couët B. , Hogan J.
Published: December 2007

A rigorous statistical methodology using survival analysis was developed and applied to electrical submersible pump (ESP) system performance data. The approach extracts unbiased information from performance data and permits lifetime modelling using parameter combinations employing all available data. The analysis explicitly accounts for ESPs that are still operational at the time of the study, thus removing a historical source of statistical bias. The analysis uses Kaplan-Meier and Cox proportional hazards modelling to determine statistical significance of explanatory variables. Methods developed to facilitate explanatory variable factor collapsing are also discussed (the partitioning of levels of each factor into nonempty subsets of statistically similar response) so that an acceptable degree of parsimony is achieved. Essential definitions necessary for preliminary data structure are also covered.

We demonstrate the practical utility of this methodology on a comprehensive data set to enable unbiased and conclusive appraisal of ESP performance, thereby resolving a common concern about comparative system reckoning. The paper concludes that survival analysis, suitably applied to properly censored data, is essentially the only reliable method of evaluating ESP system performance (and other types of time-to-event data).
Limiting Scale Risk at Production Wells by Management of PWRI Wells
Authors: Mackay Eric J.
Published: December 2007

Mixing of injected seawater with formation brines may cause scale precipitation at production wells and surface facilities, but does not generally cause significant damage within the formation itself. Indeed, mixing within the reservoir may be beneficial, if the concentration of scaling ions is reduced due to ion stripping as the brine mixture approaches the production well1. One potential exception to this is when the availability of produced water for re-injection (PWRI) is insufficient to maintain voidage replacement, and must be supplemented with seawater. Under such circumstances, seawater and formation brine may be completely mixed before injection. This will not lead to a loss of injectivity if scale inhibitor chemicals are appropriately applied to the injected brine stream2.

However, scale inhibitors are retained by the reservoir rock as they are displaced away from the wellbore, resulting in the inhibitor front propagating more slowly than the saturation front - usually referred to as chemical retardation. As brine is displaced away from the injection well, the upshot is a growing zone of mixed brine with chemical concentration below the threshold required to inhibit the scaling reaction.

The question this paper considers that has not been addressed before is whether the ratio of produced water to seawater that is injected, the possibility of treating the injection brine mix with inhibitor, and field specific details such as the location of the injection wells relative to production wells and the aquifer can impact how this zone of unprotected mixed brine is displaced and reacts deep within the reservoir, away from both injection and production wells. If the scaling reaction can be limited to a region deep within the reservoir where the volume of rock is large compared with the potential mass of scale that may deposit, then the sulphate ions associated with seawater may be stripped from the brine mixture before the water is produced. Thus, by considered yet straightforward management of the PWRI scheme, it may be possible to protect the production wells from scale damage in a way that is not possible under conventional seawater injection. This hypothesis is tested using conventional reservoir simulators and reaction-transport modelling. Various conditions are considered, including brine reactions, extent of brine displacement through the oil leg or aquifer, as well as management of the PWRI wells. Prediction of scale damage potential at production wells is made for an example field system.
Valhall Field: Microfracture Acquisition Using Wireline-Formation-Tester Tools To Validate Fracture Confinement
Authors: Olson K. E. , O'Keefe M. , Nicholyasen A. , Cameron D.
Published: December 2007

Proppant fractures have been performed in the Valhall Field since 1986 with over 200 proppant fractures completed to date. Prior to the development of the flank regions of the Valhall field in April of 2003 the majority of the proppant fractures were executed in the crest of the field and were confined to the producing interval due to considerable pressure depletion. It was identified that 50% of the new wells in the flank would be completed in near original reservoir pressure regimes. A critical component to designing and optimizing the proppant fractures for the high pressure flank wells was to have a good understanding of fracture confinement. A stress profile between the overburden and producing interval was generated using leak off test (LOT) in the overburden and closure pressures from previous fracture stimulations. Interpretation of the data was unclear due to the scatter in the LOT. Front end work to optimize the proppant fracture spacing and size along the horizontal laterals clearly showed the need for better closure pressure data, especially in the overburden.

A wireline formation test (WFT) MicroFrac operation performed on a Valhall Flank well in January 2004 confirmed that proppant fractures in flank wells with close to original pore pressure would grow unconfined into the overburden. This confirmation caused a revision in the Valhall stimulation strategy for high pore pressure wells. It also yielded savings of potentially more than $500,000 per well by further optimizing the number of proppant fractures and stimulation size.

The MicroFrac's were performed in both the overburden and producing zones in combination with planned WFT operations to obtain formation pressures, water samples and determine movable water if an oil water contact (OWC) was encountered. The operations were monitored real time in the BP Onshore Operations Center with feedback provided to the logging engineer offshore via video link. Due to rig time constraints all planned WFT data acquisition objectives were to be realized in a single run. The value of the WFT operation was maximized when planned and executed by a multi-disciplinary team with real time operational input from the end user of the data.
Pressure Transient Model Characterization of Sealing and Partially Communicating Strike-Slip Faults
Authors: Charles D. D. , Rieke H. H. , Pal S.
Published: December 2007

Strike-slip faults are prevalent in petroleum reservoir accumulations. Understanding of flow dynamics of sealing and non-sealing strike-slip faults is necessary for offshore producing companies to evaluate the number of wells required to efficiently drain a given hydrocarbon reservoir.

A comprehensive pressure transient model characterization study of sealing and partially communicating strike-slip faults was conducted using a commercially available welltest software package. Emphasis was on the use of the log-log pressure derivative (LPD) as the key diagnostic tool, considering that the LPD is, perhaps, the most widely used welltest interpretation technique.

The research problem was reduced to running numerous numerical simulations on several strike-slip fault configurations that studied three key variables, such as the magnitude of the strike-slip displacement, the degree of leakiness of the fault and the position of the wellbore relative to the leaky fault.

Our results demonstrate that all three key variables affect the resulting LPD and the LPD can be complex, which in the absence of adequate understanding of reservoir geology could lead to misdiagnosis or erroneous reservoir behavior inference. It appears that buildup data interpretation is more severely affected than drawdown data interpretation.

Quantitative analysis of the data, assuming no prior knowledge of the presence of a leaky fault, indicate reasonable estimate of formation capacity and total skin factor, but estimate of reservoir boundaries or size can suffer, depending on the level of the three factors considered.
You Cannot Be Ethical if You Do Not Know the Rules
Authors: Merryman A.
Published: December 2007

A supervisor is comparing a projection prepared following traditional department procedures to a significantly higher projection from a computer model. The traditional procedures include structure maps and isopach maps of net pay. The isopach maps incorporate "cut-offs" for porosity, water saturation, and shale; and recognize reservoir boundaries based on lease lines. The computer model was constructed by using available data for input and allowing the computer to predict recovery without artificial "cut-offs" and without an intermediate step to construct maps.

Before trying to select the "right" projection, the supervisor will want to review the rules. Rules from academic training might help validate each projection and perhaps resolve some of the differences. Rules based on experience and judgment might help. Finally, reflection on the purpose of the report, the intended use, and the intended audience will reveal other rules. For instance, projections to support development on a concession outside the United States should follow the rules of the host country and the terms of the concession agreement.

This paper is the result of discussion with friends that led to a survey of engineers working in producing companies, consulting firms, and universities. The most common responses suggested management can do a better job of disseminating and enforcing the rules.

This paper will demonstrate that many rules are involved, some will conflict with others, and some will change. Reflection on the rules reminds managers that there is a purpose for every evaluation, and potentially, a different "right" answer for each purpose. Only by disseminating and enforcing the rules can management know that ethical decisions are being made, based on projections of evaluation engineers.
Restoring Investor Confidence Through Improved Reserves Estimation and Reporting
Authors: Hodgin J. E. , Harrell D. R.
Published: December 2007

This paper contains observations, suggestions and recommendations from the perspective of an international reserves consultant on improving the reserves estimation and reporting process within publicly-owned oil and gas producers. Specifically addressed are the establishment and oversight of (1) an internal network of qualified reserves estimators having access to a secure database (2) an internal reserves audit team to ensure consistency, independence and compliance (SEC/ASC/Others) and (3) provision (if applicable) for ensuring efficient reserves verification by one or more independent third parties. Also addressed are several levels of third-party reserves authentication measures ranging from the design of internal processes through complete "grass roots" reserves determinations. These recommendations arise from experience gained through consulting assignments with more than 50 companies reporting reserves to the US SEC and other regulatory agencies as well as process controls and transparency standards arising from the Sarbanes-Oxley Act of 2002. The ultimate beneficiary of improved estimation, verification and reporting is the investor.
Casing Drilling vs. Liner Drilling: Critical Analysis of an Operation in the Gulf of Mexico
Authors: Steppe R. J. , Clark L. , Johns R.
Published: December 2007

Increasingly, operators are looking for simple and effective methods to overcome the hazards and limitations imposed by depleted reservoirs, rubble zones or thief zones. One method is to utilize casing or liner drilling to isolate the problem area by combining drilling and casing in one operation. This can take on many forms from simple drill-in systems to full retrievable directional BHA's connected below the casing or liner string.

A major independent operator has recently drilled two 12-1/4" hole sections in different wells to isolate a problem thief zone (Well A-2 BP01 and A-3). The drilling of one of these sections with liner (A-2 BP01)1 and the other with casing (A-produced many operational and equipment learning that will increase efficiency in future applications. To drill the problem interval of the A3 well, the operator chose a tried and proven Casing Drive System, together with a new PDC casing bit2 to drill down a full string of 9-5/8" casing.

The choice of drilling with liner or casing is examined along with the equipment and operational practices required. Comparisons will be drawn with the offset well which was drilled conventionally and led to mud losses of over 3,000 barrels, the effectiveness of a smear or plastering effect while drilling with liner and casing is investigated.
A Strategic Gasfield Development Case in Sandstones Using Seismic Amplitudes and Dynamic Reservoir Characterization
Authors: Arévalo-Villagrán J. A. , Cinco-Ley H. , Samaniego-Verduzco F. , Martínez-Romero N.
Published: December 2007

The objective of this paper is to present a process for improving the planning of gas field development. We discuss how seismic amplitudes and dynamic characterization can be combined to optimize gas field development. The main concepts, methodologies, and tool used, as well as results obtained are shown for an actual Mexican gas field. A series of amplitude seismic maps were constructed by using 3D seiesmic interpretation. These maps were the essential part for detecting significant volumes of gas in place. Afterwards, calibrations of these maps with production data used in reserve evaluation studies resulted in a low risk development strategy for the field. The gas field example is comprised of three producing sandstones at different depths (E, G, and M), and has 14 producing wells. Hydraulic communication and the drainage areas for each reservoir, in both E and M sandstones, were evaluated through a combination of the amplitude in the seismic anomalies and production data analysis. A good agreement between the seismic amplitude and dynamic characterization of the pressure and production data was obtained, which improved the evaluation of the reservoir quality and the estimation of drainage area, original gas in place, and proved reserves. In E and M sandstones, four and three independent reservoirs have been detected, respectively. The E sandstone has an estimated value of 62 Bscf of original gas in place and the M sandstone has an estimated value of 110 Bscf of original gas in place. By using the reservoir dynamic model in combination with information of logs, cores, and production data, the economic optimum strategy for the field development was designed, that included the drilling of wells in areas with the best seismic amplitude.
Benchmarking Heterogeneity of Simulation Models
Authors: Sahni A. , Dehghani K. , Prieditis J.
Published: December 2007

This paper presents a workflow for benchmarking reservoir model heterogeneity with classical heterogeneity indicators. The advent of parallel simulation with multi-processors has resulted in the building of super giant geo-statistical earth models, which are subsequently up-scaled for simulation. Prior to running predictions, the models may be history matched or calibrated against available rate/pressure data by altering model properties like permeability, porosity, saturation, compressibility etc. But does the end product have the desired heterogeneity to adequately model a displacement process?

Ideally, one would like to have several models with varying heterogeneity levels that all honor the historical data. We describe a methodology for obtaining a desired heterogeneity level in the up-scaled and history matched simulation model. The desired heterogeneity level could be related to observed production log, core and pulse test data and also with analogs. The workflow described in this paper shows how a history matched simulation model (where primary production history is matched) could be used to predict displacement performance at any desired heterogeneity level, as described by a classical heterogeneity indicator like the Dykstra Parsons coefficient.
Fracture Skin: A Primary Cause of Stimulation Ineffectiveness in Gas Wells
Authors: Cramer D. D.
Published: December 2007

Fracture skin is a flow impediment that can exist in two distinct forms (Cinco-Ley and Samaniego-V.) The form considered in this paper is fluid loss damage (SFS). It can occur when capillary pressure exceeds drawdown pressure (i.e., initial or average reservoir pressure minus pressure in the fracture) and there is an excess of water in the system. Imbibing water can then cause a stable increase in water saturation, often dramatically reducing the relative permeability to gas in the area of the reservoir immediately adjacent to the hydraulic fracture faces. SFS is a function of fracture half-length (xF), damage-zone width (bS) and the ratio of k (undamaged permeability) to kS (permeability in the damage zone.) It results in a measurable pressure drop in the immediate vicinity of the fracture but not within the fracture itself. Yet the extra pressure drop near the fracture serves to make the fracture appear shorter or less conductive than it is physically and can dramatically reduce well productivity.

This paper is an in-depth study of the existence and consequences of the fluid loss damage form of fracture skin. The focus is a hydraulically-fractured well completed in a low-permeability (i.e. k=0.03 md) gas sand. Drawdown analysis of 12 months of daily rate and pressure data was correlated with a pressure buildup test done at the end of this flow period. A downhole shut-in configuration significantly reduced the duration of wellbore storage during the buildup test, allowing detailed characterization of the fracture and surrounding reservoir rock. The derived SFS from pressure buildup analysis was found to be +3, much higher than evaluated in examples shown by Cinco-Ley and Samaniego-V. The analytic results were verified by numerical evaluation with a multi-cell compositional reservoir simulator. It was found that a moderate conductivity fracture (FCD=7) with a xF of 160 ft was connected to the wellbore, but over time a 70-fold reduction in permeability to gas occurred in a 4-5 ft zone surrounding the fracture (non-unique solution.) The extra pressure drop caused by this damage zone reduced the effectiveness of the fracture to a zero-skin equivalent xF of approximately 5 ft. It is shown that the fracture skin probably existed from the onset of production but intensified with late-time water influx from the wellbore to the fracture. Remedial measures are described and evaluated for effectiveness in reducing the skin and improving well productivity.
The Conundrum of Formation Evaluation in High-Angle/Horizontal Wells: Observations and Recommendations
Authors: Rendeiro C. , Passey Q. , Yin H.
Published: December 2007

Over the last two decades the process of drilling high-angle and horizontal (HA/HZ) wells has changed from cutting-edge to almost routine. While the industry has developed technologies to log and acquire data from these wells, it has not yet developed the technology to interpret the data quantitatively on a routine basis. Generally, hydrocarbon pore volume (HPV) is calculated from the height, porosity, and water saturation derived from logs in near-vertical wells. Case studies have shown that application of similar procedures in high-angle and horizontal wells can result in values significantly different than those calculated from near-vertical wells. As the apparent wellbore deviation angle increases, so increases the uncertainty in the log-derived properties. Using currently available technology, our observation is that in wells with a relative angle to the formation greater then 80°, HPV cannot be calculated from logs with the same confidence as from near-vertical wells. While historically this has not been a problem, the impact of increased uncertainty associated with the reliance on HA/HZ wells for reservoir assessment needs to be recognized and addressed.
Techniques for Extracting Reliable Density and Porosity Data From Cuttings
Authors: Siddiqui S. , Grader A. S. , Touati M. , Loermans A. M. , Funk J. J.
Published: December 2007

The collection of core samples from a reservoir is essential for its proper characterization. Core data play very important roles in the following: log calibration, well treatment and performance prediction, reservoir modeling and simulation, and production and development planning. Coring is time-consuming, expensive and risky. It is difficult, if not impossible, to retrieve whole cores from horizontal and maximum reservoir contact (MRC) wells — which form the bulk of wells being drilled at present. As an alternative to coring, the use of cuttings has been proposed by many, as cuttings are always available from wells. Aside from some loss, contamination and depth-uncertainty (typically within 10 ft), cuttings show strong potential to represent all the formations encountered during the drilling of a well.

This paper discusses the capabilities of various laboratory instruments to extract reliable density and porosity data from cuttings. The methodology used involves full characterization of a carbonate core plug using several laboratory tools followed by crushing the plug into cuttings of different mesh sizes. Samples of different mesh sizes were then scanned with a CT-scanner and bulk densities and porosities were calculated using advanced histogram-based analysis techniques. Results for individual cuttings sizes were compared against those for the whole plug. Additional data on the same cuttings were generated using micro-CT, Environmental Scanning Electron Microscope (ESEM), Nuclear Magnetic Resonance (NMR) spectrometer and APEX (Apparatus for Pore Examination) mercury porosimeter, which were also used for comparison. A set of procedures was developed for generating porosity data based on image processing of SEM and micro-CT generated images. The work helped establish the size of about 2.5 mm as the limit of detectability of medical-based CT-scanners to generate reliable density and porosity data from drilled cuttings. Comparison between the micro-CT and ESEM data showed the range of application for each tool in determining porosities from cuttings. Comparison between the pore size distributions generated by the NMR and APEX mercury porosity instruments and their visual comparisons with ESEM images provide important insights for the pore network modeling efforts.
Limitations of Using Urea as a Nitrogen Source in Biodegradation of Petroleum Wastes
Authors: Jin S. , Fallgren P. H. , Li M.
Published: December 2007

Nutrient addition is important to achieving the carbon/nitrogen balance and successful biodegradation of petroleum contaminants. Urea has been considered as a preferred nitrogen source in enhancing biodegradation, because of its high nitrogen content and availability. This study investigated urea in the biodegradation of petroleum-contaminated soils collected from an arid and sandy location in Egypt. Ammonium nitrate served as the nitrogen amendment control in this study. Biodegradation of petroleum-contaminated soils from Wyoming was monitored as a comparison. Performance of urea was poor in the enhancement of biodegradation of petroleum-impacted soil from the Egyptian site, in addition, urea demonstrates an adverse effect on the biodegradation rates. Results indicate that urea may inhibit the microorganisms involved in petroleum degradation. Data from this study suggest that the application of urea in the enhancement of biodegradation of petroleum compounds may not be applicable in geological areas or soils structures similar to those in this study.
Are Slick-Water Fracturing Applications Effective in the J-Sand Formation?
Authors: Shaefer M.
Published: December 2007

Since the early 1970s, fracturing fluid systems utilized in the J-Sand treatments in the Wattenberg field have ranged from poly emulsion to cross link gels with and without an inert gas phase (e.g. N2, CO2). Current treatments typically consist of large proppant volumes and crosslinked fluid volumes (e.g. 500,000 lbs and 7,000 barrels). Large treatment volumes results in large job costs for the well operators who have searched for ways to reduce treatment costs without sacrificing well production. Also in early 2000, large treatments were resulting in poorer productive J-Sand wells due to suspected pressure depletion. In 2002, one well operator in the Wattenberg field implemented an alternative method to stimulate the J-Sand: (1) substituting the slick water based fluid for the massive crosslinked gel based fluid and (2) reducing the proppant volume by as much as 4.5 fold. This strategy reduced job costs significantly without impacting ultimate gas recovery. At the end of 2002, the well operator completely switched over to the slick water treatments (SWT) for the J-Sand interval. By lowering the completion costs of a J-Sand well, many additional wells will be drilled that otherwise would not be economic.

In this paper, the production from eight J-Sand wells stimulated with SWT will be compared to the 15 offsetting wells stimulated with crosslinked gel treatments (CGT). Production analysis methods will be utilized to determine reservoir and fracture flow capacity (e.g. drainage area, kh, effective fracture half length) for the wells considered in this case study. Also, treatment pressure history matching will be performed for selected wells to evaluate the resultant fracture geometry of the different styles of treatments.
Relative Permeability Modifier Treatments on Gulf of Mexico Frac-Packed and Gravel-Packed Oil and Gas Wells
Authors: Pietrak M. J. , Stanley F. O. , Weber B. J. , Fontenot J. S.
Published: December 2007

Estimates of worldwide oilfield water production are as high as 300 to 400 million barrels of water per day (bwpd), while oil production is only 75 million barrels per day (bopd)1. Put in different terms: for every 1 bopd produced, our industry produces approximately 4 to 6 bwpd, and for many depleted areas of the world this oil-to-water ratio can be much higher, reaching up to 1:100. Excessive water production from oil and gas wells can cause serious reductions in well productivity and significantly increases operating expenses.

In an attempt to reduce the oil industry's dilemma related to water production, there has recently been an increased interest in water control treatments using relative permeability modifiers (RPM). A new and unique RPM polymer is yielding significant economic benefits by increasing hydrocarbon production from treated wells.

Generally, RPMs are designed to control water production from high permeability streaks or due to coning issues. The polymer adheres to formation rock exposing its hydrophilic (water-loving) side to the pore throats. The RPM restricts water movement through the pore throat by reducing the effective size of the throat in the presence of water and by increasing drag on formation water flowing through the reservoir matrix. Because it deforms in the presence of hydrocarbons, the RPM typically does not adversely effect oil or gas flow. The newly developed RPM (along with careful selection of well candidates, correct treatment design, and proper placement) is helping increase the success of RPM treatments.

This paper will discuss the application and economic benefits from using the new low-risk RPM polymer. Multi-well RPM matrix treatments were performed on offshore Gulf of Mexico (GoM) frac-packed and gravel-packed wells. One particular RPM treated gas well showed a significant decrease in water production, a five fold increase in gas production and double the amount of oil. Payout for the entire treatment was just 7 days.
The Effects of Proppant Selection Upon Well Productivity—A Review of Over 650 Treatments in the Cardium Formation
Authors: Rightmire C. M. , Leshchyshyn T. T. , Vincent M. C.
Published: December 2007

Effects of proppant selection on well productivity are demonstrated in a large case study covering 2,300 square miles [6,000 square kilometers] in Alberta, Canada. In 80% of cases studied, wells fractured with ceramic proppant provided significantly higher gas production rates compared to wells propped with sand or other materials. The most frequently stimulated formation in the Western Canadian Sedimentary Basin (WCSB) is the Cardium formation of the Late Cretaceous period. Records indicate that across the basin the Cardium formation has received over 12,500 fracture stimulations during the last 50 years.

This study includes a review of 1,600 wells operated by 96 companies. On average, 156 new wells have been drilled annually since 2000. Record numbers of new wells were completed in 2004, and the number of Cardium wells completed in the last four years exceeds the total from the preceding two decades. A detailed database containing available fracture treatment and production data was compiled from government records and service industry sources. This paper summarizes a study of over 750 well stimulations.

Various stimulation strategies have been employed in the Cardium development. This paper examines productivity of hydraulic fractures propped with various materials and placed with a variety of fluid systems. Wells in this study were stimulated with as low as 2,200 lbm [1 tonne] to nearly 407,000 lbm [185 tonne] of proppant per well in one to five stages.

Analyses suggest that significantly greater economic return has been achieved when fracture designs are optimized. In this study, the most common design was 132,000 lbm [60 tonne] of proppant placed with a hydrocarbon-based fluid. For this treatment design, the average first year production for wells receiving 132,000 lbm [60 tonne] of sand was 302 MMscf [8.5 × 106 m3] of gas. Wells stimulated with 132,000 lbm [60 tonne] of ceramic proppant averaged 420 MMscf [11.9 × 106 m3] production during the first year. Benefits vary with job size, fluid type, and other factors. The incremental cost of ceramic proppant is usually recovered within 30 days, generating a significant increase in profitability. At current gas prices, average return on investment achieved by optimizing proppant selection greatly exceeds 100%.

Production from Cardium oil wells was also found to increase with proppant concentration and with proppant size. A preliminary review suggests that oil production has been significantly improved with higher conductivity fractures. While a full statistical review remains underway, the initial comparisons suggest that further increases in proppant conductivity should be considered. Additional information is provided to assist fracture optimization strategy for both oil and gas wells in the Cardium formation.
Optimal Field Development Planning of Well Locations With Reservoir Uncertainty
Authors: Cullick A. S. , Narayanan K. , Gorell S.
Published: December 2007

The paper presents a process for determining optimal subsurface locations for producing and injecting wells in a field to improve reservoir performance and value. The process is illustrated by optimizing well locations in an initial development planning context. The process involves planning a set of wells on a static reservoir model using an automated well planner. These locations are then optimized with dynamic flow simulation to achieve higher recovery or economic benefit. In this work, we present the framework for optimizing many well locations simultaneously, with reservoir simulation and economic analysis. This method is demonstrated byapplying it to a field-scale simulation model with water injection.
A New Method for the Determination of Foam Capillary Pressures in Porous Media
Authors: van der Net A. , Zitha P. L. J.
Published: December 2007

This paper reports a new implementation of X-ray computed tomography (CT) to investigate capillary pressures during foam flow in porous media. The method is based on the dependence of X-ray attenuation coefficient of gas on its pressure. Gas pressureare obtained from the CT images, together with water saturations, while water pressure is measured classically using pressure sensors. The research shows that the X-ray attenuation coefficient of a core containing gas varies linearly with gas pressure, over a wide range of pressures. A similar dependence is found in presence of irreducible water, which allows determination of the residual water saturation. More significantly, during transient foam flow in porous media the gas and capillary pressures have been determined accurately, using the newly established relation between the attenuation coefficient and pressure. The capillary pressure derived from the proposed method, reveals new aspects of foam behavior, and provides for the first time direct evidence that the secondary liquid desaturation is due to gas expansion, as was suggest in earlier studies.
Case Study: Successful Implementation of ESPs in a High-GOR, Poorly Consolidated, Corrosive Field
Authors: Guevara L. A. , Rincón P. R. , McKee J. P. , Marin H. , Sanmiguel M. , Rincon G. , Vera L.
Published: December 2007

This paper describes the successful experience obtained in the use of electric submersible pumps (ESP) in the production of abrasive and corrosive fluids.

The study covers 114 ESP wells completed by Harvest Vinccler, in the Uracoa and Tucupita Fields, located in the state of Monagas, Venezuela.

This artificial lift method was initiated in July of 1996. Most of the failures were due to electrical failure, erosion (sand) and corrosion problems. The initial mean-time-between-failure (MTBF) of 250 days, has improved over time to 1752 days.

The following are actions, which have improved the ESP MTBF: 1-An exhaustive study of the root cause of failure.2-A new ESP design.3-Monitoring of ESP performance.4-The use of special abrasion/corrosion resistant alloy materials in ESP components and completion equipment.5-Down-hole injection of de-emulsifiers, corrosion and scale inhibitors through capillary tubing, coupled with a well integrity monitoring program.6-Improved quality and reliability of the electrical power source.

All of these actions combined have enabled optimization of ESP applications in these fields.

This study will present the details of the actions and their results, to achieve the optimization of ESP's in Uracoa-Tucupita Fields.
Feasibility of Supercritical Carbon Dioxide as a Drilling Fluid for Deep Underbalanced Drilling Operations
Authors: Gupta A. P. , Gupta A. , Langlinais J.
Published: December 2007

Feasibility of drilling with pure supercritical carbon dioxide to serve the needs of deep underbalanced drilling operations has been analyzed. A case study involving underbalanced drilling to access a depleted gas reservoir illustrates the need for such a study. For this well, nitrogen was initially considered as the drilling fluid. Dry nitrogen, due to its low density, was unable to generate sufficient torque in the downhole motor. Mixture of nitrogen and water, stabilized as foam, generated sufficient torque, but made it difficult to maintain underbalanced conditions. This diminished the intended benefit of using nitrogen as the drilling fluid.

CO2 is likely to be supercritical at downhole pressure and temperature conditions, with density similar to that of a liquid and viscosity comparable to a gas. A computational model was developed to calculate the variation of density and viscosity in the tubing and the annulus with pressure, temperature and depth. A circulation model was developed to calculate the frictional pressure losses in the tubing and the annulus, and also calculates important parameters such as the jet impact force and the cuttings transport ratio. An attempt was made to model the temperatures in the well using an analytical model. Corrosion aspects of a CO2 based drilling system are critical and were addressed in this study.

The results show that the unique properties of CO2, which is supercritical in the tubing and changes to vapor phase in the annulus, are advantageous in its role as a drilling fluid. It has the necessary density in the tubing to turn the downhole motor and the necessary density and viscosity to maintain underbalanced conditions in the annulus. The role of a surface choke is crucial in controlling the annular pressures for this system. A carefully designed corrosion control program is essential for such a system. Results of this study are also important for CO2 sequestration and CO2 based enhanced oil recovery operations.
Applications of Pinpoint Fracturing in the Cooper Basin, Australia
Authors: Gilbert J. , Greenstreet C.
Published: December 2007

Cooper Basin reservoirs commonly contain low-permeability reservoirs that require stimulation to flow. However, conventional multi-layer stimulation techniques has been shown to leave some sands untreated and not contributing, leaving potential to further increase flow rate and reserves through the use of new technology.

Pinpoint fracturing technology allows multiple precisely-targeted fracs to be economically treated, which can increase flow rates and reserves, reduce incremental per-frac costs and significantly shorten cycle time compared to multi-stage conventional treatments

Eight wells in the Cooper Basin of Australia have been Pin-Point stimulated using coiled tubing producing a 30% increase in well productivity compared with AFE expectations. Production logs run over the fractured zones show markedly improved completion efficiency with production from the majority of Pin-Point fractured zones.
Core-to-Log Comparison—What's A Good Match?
Authors: Adams S. J.
Published: December 2007

It is common practice in the petrophysical community to either calibrate log porosities to core measurements or to use the porosities, permeabilities and water saturations measured on core to verify that the log interpretation models used are appropriate. This paper advocates the latter approach, since such "tested" or "verified" models are more likely to be valid away from the cored wells and intervals. Using the core data to verify the log interpretation models also allows the log and core data to be compared and the uncertainties in the log-derived properties to be quantified.

This paper describes quantitative methodologies for comparing log-derived porosities, permeabilities and water saturations with their core-based equivalents. The methodology uses the differences between the log and core-based estimates to quantify uncertainty ranges at any arbitrary level (e.g. P90, P50 and P10).

Quantitative comparisons are at their most useful when the uncertainty ranges derived can be placed within a known framework so that it is apparent whether or not the match is a "good" one. This paper uses experience gained from a number of Fields spread through a variety of Basins to show sort of comparisons are common. From this "Field experience" it is possible to determine whether or not log-to-core matches are within the expected range i.e. whether or not the match is "good". If it is not "good" then additional refinements may be required to improve the comparison to an acceptable level. In any case, the uncertainties associated with the log-derived estimates can be quantified.

In general, the mean difference between log and core porosities should be less than 0.6 p.u., that between log and core permeabilities should be less than a factor of 1.5 and between log and capillary pressure (saturation-height) based water saturations should be less than 6 s.u.
Evaluation of Equivalent Circulating Density of Drilling Fluids under High-Pressure/High-Temperature Conditions
Authors: Harris O. O. , Osisanya S. O.
Published: December 2007

The results of a study of the effects of the temperature and pressure conditions in high temperature/high pressure wells on drilling fluid equivalent circulating density and consequently bottom-hole pressure are presented in this paper. High temperature conditions cause the fluid in the wellbore to expand, while high pressure conditions in deep wells cause fluid compression. Failure to take these two opposing effects into account can lead to errors in the estimation of bottom-hole pressure. The rheological behavior drilling fluids is also affected by the temperature and pressure conditions.

A simulator called DDSimulator was developed to simulate the wellbore during circulation. A Bingham plastic model was employed to express the rheological behavior of the drilling fluids studied, with rheological parameters expressed as functions of temperature and pressure. The Crank-Nicolson numerical discretizing scheme was employed in the DDSimulator for the evaluation of the wellbore temperature profile. The results of the simulation show that higher geothermal gradients lead to lower bottom-hole pressure. The inlet pipe temperature did not have a significant effect on the bottom-hole temperature and pressure, and higher circulation rates result in lower bottom-hole temperature and higher bottom-hole pressure.