bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing Water-flooding Effectiveness of the Heavy Oil Reservoirs by Using the Viscosity Reducer
Authors: Zhang Fusheng , Ouyang Jian , Wu Muxi , Wang Guijiang 
Published: February 2011

Abstract
On the basis of analysis of components and structure of the heavy oil from the 109-1 block in the Dagang oilfield, the high effectiveness viscosity reducer, which can make the mixture of water and heavy oil to become the stable O/W emulsion and decrease viscosity of the heavy oil by above 97% in the case of above 30% water cut and above 1000mg/L dosage of viscosity reducer (for total amount of water and heavy oil), have been developed according to the characteristic of high temperature 80, high mineral salt 20693.75mg/L (especially Ca2+/Mg2+ 805.38 mg/L) and the lower recovery percent of reserves of the 109-1 block heavy oil reservoir in the Dagang oilfield. The viscosity reducer in the produced liquid did not bring unfavorable influence on demulsification. The core displacement experiments show that displacement system containing viscosity reducer can enhance oil recovery by above 22% comparing to water-flooding, and prove that decreasing heavy oil viscosity can improve the oil-water mobility ratio, enhance sweep efficiency and enhance oil recovery.
ICD Design: Revisiting Objectives and Techniques
Authors: Daneshy A. Ali , Guo Boyun , Krasnov Vitaly A. , Zimin Sergey V. 
Published: February 2011

Abstract
Inflow Control Devices (ICD) were developed in response to early water break-through from the heel of prolific horizontal wells. In their initial applications, the design of ICD installations was based on equalizing flux (flow rate per unit length) along the length of a horizontal well, which required "choking" of flux in the heel region. In practice, these tools are often installed along the entire length of a horizontal well, with the logic that since choking level is proportional to flow, the tool will automatically produce a more uniform flow profile.
In this paper we will re-examine the technical validity of attempting to achieve equal flux along the length of the horizontal well. We will show that in reservoirs with uniform permeability the flux from the toe and heel regions should in fact be larger than the mid-section. We will also show that delaying water or gas breakthrough is not a sufficient reason for use of ICDs. We will discuss the benefits of a new design philosophy whereby each well segment is choked at a level that regulates its flux to a level that produces an outcome more suitable for optimum reservoir management. This gives the operator the flexibility to design ICD layout to optimize various flow parameters, including time or cumulative production at water/gas breakthrough, location of first water/gas breakthrough, etc. This will be especially valuable for wells in variable permeability reservoirs. A new design simulator developed based on above concept will be presented and its benefits demonstrated through a case history.
How good is the P90 Value as a measure of the Reserves Downside?
Authors: Gupta Sandeep , Gupta Ritu , van Elk Jan , Vijayan K 
Published: February 2011

Abstract
Probabilistic methods for reserves estimation, including uncertainty quantification and probabilistic aggregation, have gained widespread recognition in the oil and gas industry, since the first comprehensive guidelines were issued by the SPE in 2001. The probabilistic methods now used, as proposed in these guidelines, are similar to those also used in portfolio theory by the finance industry. A lot can be learned from the extensive experience with probabilistic methods and quantification of risk with measures like Value-at-Risk in portfolio theory. Especially, the guidelines issued by the Basel II Accord and since the recent financial crisis contain important lessons.
As a first step, we examine a fundamental question. Is the P90 reserves value an appropriate measure for quantifying the reserves downside? For the P90 value to be considered a good measure of the reserves downside, it needs to possess a number of basic characteristics involving P90 for each field and the probabilistically aggregated P90 value for the portfolio of fields. We define these characteristics and through examples will demonstrate that the P90 reserves estimate, in general, meets the requirements of a good measure of reserves downside. A possible uncertainty scenario, where some of these characteristics do not hold, is also given. An alternative measure of risk, specified as the average reserves over the confidence interval higher than P90, for quantifying reserves downside is presented.
In this paper, we will highlight the appropriateness and limits of using the P90 reserves estimate as a measure of the reserves downside. Understanding of the limitations posed by using the P90 value is vital in management of reserves risk.
Quality Check of Gas-Condensate Pvt Studies and Eos Modelling under Input Data Uncertainty
Authors: Schebetov A. , Rimoldi A. , Piana M. 
Published: February 2011

Abstract
Reservoir simulation is the key tool to design a field development plan and to evaluate field production performances. Various software products have been created and Oil&Gas industry has gained a broad experience of their application. Creation of the reservoir fluid PVT model (PVT table for reservoir simulators) is an essential part of any integrated reservoir studies. PVT models are usually generated using mathematical algorithms by means of equations of state (EOS).
Whenever fluid PVT models are created for the reservoir simulation a variety of uncertainties in the input data arises due to deficiencies of laboratory equipment, low accuracy and quality of sampling techniques, especially for gas-condensate fields. This paper presents a unique know-how in quality control of PVT studies and application of advanced modeling methods using the EOS.
After identification of main uncertainty sources, a quality check procedure was developed to assess the consistency of PVT samples and to select the most reliable ones for EOS modeling. This procedure is based on simple criteria and should be used to handle with uncertainties in PVT studies.
A generalized EOS tuning algorithm was designed and hereby presented in a form of step by step flowchart which summarizes authors’ experience in EOS modeling. Additionally a new method to modify a reservoir gas composition for a proper initialization of the reservoir simulation model as well as for removing possible inconsistencies in the input data is proposed.
The workflow suggested by the authors was successfully implemented in several reservoir simulation models of the gas-condensate assets managed by LLC SeverEnergia, in West Siberia.
Remedial Cementing in Limestone Formation Using Bradenhead Squeeze: A Case History of KS-X22
Authors: Aprilianto E. C. 
Published: February 2011

Abstract
The high porosity of the limestone formation of Kaji-Semoga Field, Indonesia, caused a vast amount of lost circulation during the waterflood drilling campaign. An example of major lost circulation was at KS-X22, which caused a major failure in the primary cementing. This failure resulted in a significant increase in water cut, from 45 % to 96 %, within 6 months.
To make KS-X22 economically viable again, it was decided to improve the primary cement quality by remedial cementing. The job was designed as low-pressure balanced plug placement, with 15.8 ppg G class cement pumped down on open-ended tubing. The limited capacity of the onsite batch mixer restricted the cementing process, which could not be done in one stage. But, to our advantage, this limitation enabled us to control the amount of cement required for the following stage, based on the results of the previous stage.
When the job was finished, the cement bond log showed that it had been done perfectly, indicated by the significant change in the free pipe reading (62 mV) to an excellent cement bond (&lt;20mV). The producing phase after the job showed a slower rate in the water cut increase, and currently the well is still producing using ESP, more than 2 years after the remedial cementing job.
This paper will discuss the planning, implementation, and results of remedial cementing at KS-X22 and the lessons learned
Risk Tolerance and Risk Neutrality (You Can Live With More Risk Than You Think)
Authors: Leach Patrick E. 
Published: February 2011

Abstract
Many exploration and production companies impose a risk threshold on major capital projects (one common such hurdle is a maximum acceptable probability of negative NPV). Projects which fail to meet the threshold are not usually rejected outright; rather, the project team is instructed to gather more information and perform more analyses, so as to reduce the range of economic uncertainty associated with the project. This wastes capital and decreases economic efficiency.
The primary arena in which risk tolerance is applied is the development stage of a project. Companies are comfortable with the notion of failed exploration wells, but not failed developments. Stringent probability-of-success hurdles often result. Unless the failure of a single project could put a firm into financial distress, companies should be risk-neutral when making decisions at the project level – i.e., they should make project optimization decisions based on the mean values of the economic metrics of interest (NPV, P/I, etc.) with no further consideration taken of the probability of success. Value-of-information (VOI) analyses should be used to determine when additional information or analysis adds value to a project and when it does not. Risk tolerance should be applied at the portfolio level, not the project level. The question to ask is not, "Am I comfortable with the risk associated with this project?"; rather, it is, "Am I comfortable with the risk associated with my portfolio of projects when this project is included?"
Projects are routinely delayed while unnecessary appraisal wells are drilled and analyses are conducted, thus eroding millions of dollars from the NPV of these projects. Correcting this issue will require a change in the way many project managers are evaluated and compensated, but the potential benefit to the companies – and the industry – is huge.
Prediction of Uncertainty in Exploration of Unconventional Gas Reservoirs
Authors: Kelkar Mohan , Bonney Kyle , Bonney Phillip 
Published: February 2011

Abstract
Once a new unconventional play is identified, companies would start acquiring sizable land holdings within the same play. Before acquiring, the companies would like to answer several questions: how much to pay for the bonus; what is the strategy to initiate the drilling program and how to determine the uncertainty related to EUR from these wells. Most companies would use the data from existing wells within the same play or similar play to estimate what type of production to be expected from the land to be acquired. Based on the results, they will determine the bonus as well as expected uncertainties.
We approach this problem using a novel method. We use the analog EUR data to develop the spatial relationships for the analog field. By assuming log-normal distribution for EUR data, we build the equations for the EUR for the new area. Appropriate scaling considerations can be included in these equations. For example, the newly acquired area may have smaller thickness than the analog or would use longer horizontal wells. We generate a graph of p10, p50 and p90 EUR values for the initial drilling program, starting with the first well. Knowing the uncertainty in EUR values, the initial bonus, based on appropriate economic criteria, can be determined. Once the land is acquired, as the initial drilling program is initiated, the method will allow the company to compare the performance of actual well with the expected uncertainty range. Depending on the locations of the wells and spatial relationship, the uncertainty will change differently. By using the method, the company can evaluate if the average performance of the drilled wells is within the realm of acceptable uncertainties or should the model be changed based on the new data available. We validated the proposed method for a shale play in Oklahoma.
Coalbed Methane Production: Why Coal Permeability Matters
Authors: Chen Dong , Liu Jishan , Pan Zhejun , Connell Luke D. 
Published: February 2011

Abstract
When coalbed methane is recovered, complex interactions of stress and chemistry have a strong influence on the properties of the coal. These include influences on gas desorption and flow, coal deformation, porosity change and permeability modification. Although coal-gas interactions have been comprehensively investigated, all of these prior studies usually assume that these interactions are under conditions of invariant total stress where effective stresses scale inversely with applied pore pressures.
Here we develop a novel coal permeability model that defines the relations between directional permeabilities and strains, and implement a FE model that couples desorption of the coalbed methane and water flow within a deformable medium (coal) where the effects of deformation are rigorously accommodated. This relaxes the prior assumption that total stresses remain constant and allows exploration of the coalbed methane production under the full range of mechanical boundary conditions from invariant stress to restrained displacement.
We apply this model to investigate the productivity of coalbed methane production under in situ conditions. The results show that increasing the absolute permeability could shorten the dewatering stage of the coalbed methane production, but the shape of the production curves does not change with the absolute permeability. For permeability anisotropy coal seams, the fluids mainly flow in face cleats direction and locating more wells in butt cleats direction is high efficient for coalbed methane production. The relative permeability dominates the fractional flow and thus controls the shape of the production curves. It determines when the commercial gas rate could be achieved and how much water should be coped with during the dewatering stage. Therefore both the absolute permeability and relative permeability are key factors for the dewatering stage of the coalbed methane production.
Horizontal Well Optimization With Inflow Control Devices (ICDs) Application in Heterogeneous and Dipping Gas-Capped Oil Reservoirs
Authors: Rahimah A. K. , Azrul N. M. , GordonGoh K. F. , Asyikin A. N. , Leung E. , Johan M. 
Published: February 2011

Abstract
SS field is located offshore East Malaysia. 2 exploration wells discovered multiple dipping reservoirs, with oil column of about 40 m. The heterogeneous reservoirs, combined with a very large gas cap (i.e. m size of 2) and moderate aquifer strength impose challenges to maximize recovery from this field. Field development study has formulated 14 horizontal wells with 3 water injectors to achieve recovery factor of 30%. Optimum reservoir management strategy requires a delicate balance of gas cap expansion and water injection drive, where the optimum voidage replacement ratio is only 0.25. However, reservoir dynamic modelling shows that all the wells will get early gas and water breakthrough. ICD technology is therefore evaluated to address the above production and recovery dilemma while prolonging the production life.
In this paper, optimization of 12 horizontal ICD wells out of 14 wells will be discussed. This includes the process of qualifying and designing the ICD application in each candidate through static modelling. Full field dynamic modelling was also conducted to quantify the real benefits of ICD, and confirming the robustness of the design throughout field life. In view of high uncertainty of fluid contacts and reservoir quality in unappraised areas, the team has adopted the unique yet challenging approach of field appraisal from pilot holes during the initial implementation stage. This has provided valuable data prior to horizontal drilling and final optimization of ICD. Subsequently, the production performance from the first ICD wells will also be discussed to provide evidence on its effectiveness and lessons learned.
Finally, the paper highlights the importance of seamless teamwork and coordination between project team and service providers to deliver superior performance. This can be an informative workflow source for future applicants of such technology with similar fields’ nature and risks.
Nonchemical Bacteria-Control Process
Authors: Neal Greg , Kleinwolterink Kembe , Abney Laurence , Gloe Lindsey 
Published: February 2011

Abstract
This paper describes a proven method to control bacteria growth in pipeline and process service fluids using irradiation technology. Service fluids are exposed to an irradiation source that disinfects the fluids and eliminates the need for biocide chemistry. The disinfection process can be used as a standalone process or in conjunction with traditional chemical treatments for many oilfield service applications.
The commissioning process for pipelines typically requires hydrostatic-pressure testing. The test fluid is usually treated for potential bacteria accumulation. Using the nonchemical process of irradiation to disinfect the test fluid eliminates the need for hundreds of gallons of bactericide. The service greatly reduces employee exposure to hazard-rated biocides and associated health- and safety-related issues, significantly improving overall environmental aspects of the operation.
Bacteria play an important, although usually detrimental, role in the production and transportation of hydrocarbons. The slime- forming version of bacteria can corrode surface piping and storage facilities. In addition, bacteria have been known to restrict reservoir porosity with "bio-plugging" or "bio-fouling." One anaerobic form of bacteria is sulfate reducing bacteria (SRB), which reduces the sulfate ion to sulfide. This can lead to the corrosion of flow-wetted metal components and to the formation of hydrogen sulfide (H2S) gas, which is extremely hazardous to humans and other animals. Fluids containing H2S can be damaging to production facilities not specifically designed to be H2S resistant.
The nonchemical alternative to biocide has cost and environmental advantages over traditional chemical treatments.
A New Approach to Flowline Active Heating
Authors: Abney Laurence 
Published: February 2011

Abstract
The industry drive to develop marginal fields, heavy oil, or increased oil-recovery options from new or existing fields requires that the design of system components be examined and questioned. Extended-reach (cold water) flowlines that transport unprocessed fluids from the wellbore through to a receiving or processing facility require effective insulation systems or an active heating system to assure the integrity of the fluids in the line. Additionally, to meet flow-assurance requirements, production chemistry is used at the inlet of a flowline to prevent the formation of hydrates and to manage paraffin wax or scale formation. The production chemicals are usually injected through chemical-transportation facilities in an electrical/hydraulic-control umbilical that is laid parallel to the flowline.
Flowline active-heating systems and high-performance insulation systems add significantly to the capital cost of a project; additionally, the design and fabrication of control umbilicals that include multiple chemical-injection conduits increase the capital required to develop a field.
This paper presents a new concept in flowline active-heating and chemical-injection systems that will reduce the capital cost of flowline and umbilical infrastructure while enabling significant flexibility in the application of production chemistry. The system challenges of existing flowline design, umbilical design, and the philosophies of field operational maintenance/pigging are reviewed.
Sand Production Prediction for a Mature Oil Field Offshore East Malaysia - A Case Study
Authors: Wu B. , Bahri C. , Tan C. P. , Li Q. , Rahim H. , Kartoatmodjo G. , Friedel T. 
Published: February 2011

Abstract
As an oil field depletes, stress and pressure change in the reservoir. Water and gas breakthrough are also expected to occur. These increase sand production propensity, limit production rates and bring forward the abandonment of the field. This paper presents a sand production case study for a mature oil field offshore Malaysia. The field has been on production for more than 20 years, and an infill drilling program was recently initiated. Sand production risk for the planned horizontal wells in this mature field was a concern for the program. The objective of the study reported in this paper was to quantify sanding risks and recommend sandface completion options for the planned horizontal wells.
An integrated workflow was applied to the study, encompassing mechanical earth modeling, sand production model development and validation, and prediction of sand production propensity for the planned wells. Relevant wireline logs were utilized to derive formation mechanical properties which were calibrated with laboratory-measured values. Leakoff tests and borehole breakout information were utilized to constrain horizontal stress magnitudes. Sand production model was developed and validated based on sand production experienced in the field to date. Sand production risks were assessed for the planned horizontal wells with various completion options. Sand production propensity, presented as critical drawdown pressure was established for all the reservoir formations. It was concluded that sand production risks exist for most of the completion scenarios studied, and downhole sand control would be needed. The study provides a solid basis to optimize sandface completion for the planned wells.