bluuebunny/crossref_metadata_2025_split huggingface dataset:
Plans for Chemical Enhanced Oil Recovery in a North Oman Carbonate Field
Authors: Soek Harry , Jaboob Musallam , Singh Maniesh , Jabri Ahmed , Stoll Martin , Faber Rien , Al Harthy Khalfan , Al Mjeni Rifaat , Wunnik John van 
Published: September 2011

Abstract
Most of PDO’s carbonate fields in North Oman have been producing for many years, initially on depletion in the early days but were quickly put on water injection to maintain reservoir pressure and safeguard long term ultimate recovery. As these fields mature into early middle age, EOR options have been under review to further increase recovery.
Given the reservoir properties and the prevailing fluid & gas conditions for these carbonate fields, thermal technologies are not considered an optimal choice. Gas floods would potentially feature but were screened out due to the overall balance between gas requirements, cost and potential reward. Chemical floods with potentially attractive high recoveries were selected for further assessment.
The goal is to demonstrate that chemical technology can produce economic incremental oil from a waterflooded carbonate reservoir containing a low-viscous light oil. The reservoir selected has undergone a successful waterflood implementation with good control on historical voidage and production allocation. The potential follow up chemical flood is then planned to be introduced in a phased manner. This starts with phase behaviour and core flow experiments in the lab to find a suitable chemical formulation to optimally mobilize waterflood residual oil. This is then followed by field trials such as a Single Well Chemical Field Test to back up lab experiments, extensive logging, a MicroPilot test and a planned potential multi-well pilot. Full field implementation is then dependant on the results of the earlier project phases and will have to balance against the perceived rewards, risk and cost. The results to date, learning's and key findings along with the selection strategy and challenges will be discussed in this paper. This study and field work will provide a foundation upon which the future potential for chemical flooding in North Oman carbonate fields can be evaluated and implemented.
Experimental and Simulation Study On Use Of Surfactant and De-Emulsifier Blend Additives In Steam Flood As EOR Technique In Heavy Oil Reservoir
Authors: Tiamiyu Olanrewaju M. , Boukadi Fathi 
Published: September 2011

Abstract
Continued research and field application of steam flooding have confirmed an early conclusion that the process is a powerful method for recovering heavy and intermediate gravity crude oils. This experimental study investigates the feasibility of using low concentrate solution of blend of surfactant and de-emulsifier as an additive to steam flooding. This research is also designed to search for optimization of the process of steam flood through recovering additional oil via using a steam with low concentration of surfactant and de-emulsifier mixture without the production of oil-water emulsion. To achieve these goals, four flow experiments are conducted as follows: (1) conventional water flood (2) surfactant solution flood (3) conventional steam flood and (4) low concentration surfactant added steam flood (SASF). Injection of steam with low concentration surfactant improved oil recovery compared to either surfactant solution or conventional steam flood. A comparison of the obtained results of the four undertaken experiments results in three major conclusions, which are (1) addition of 0.1% volume of surfactant and de-emulsifier blend into steam drive improves its performance and consequently recovers 13% OIIP additional oil compared to conventional steam flood, (2) using higher concentration of surfactant (0.1% vol.) into steam flood will not produce any significant increase in additional oil recovery and (3) the inclusion of de-emulsifier in the surfactant added steam run results in non production of oil-water emulsion. The results of this study have validated the proposed technique of surfactant and de-emulsifier blend additives in steam flood as an EOR process. Furthermore, this technique is expected to have significant impact to attain potential incremental oil recovery, if applied in current projects of conventional steam flood and/or water flooded reservoirs.
Challenges in Interpreting Well Testing Data from Fractured Water Injection Wells with a Dual Storage Phenomenon
Authors: BinAkresh Saud A. , Anisur Rahman N. M. 
Published: September 2011

Abstract
Injection wells are widely used in the petroleum industry to support oil production. Water is injected into the reservoir for filling in the void space left by produced oil and to maintain the reservoir pressure. These injectors are frequently tested by means of falloff tests to assess their injectivity. In most of the injectors, water is injected under fracturing conditions, which induce large fractures over time; however, most falloff tests on these wells do not exhibit any clear fracture behavior. Instead, prolonged storage effects with a long unit-slope line on the log-log plot are observed in the data. The observed storage coefficient values are found larger than the typical values in regular wellbores by one or two orders of magnitude.
In this paper, we will show and discuss several falloff tests from water injection wells in giant oil fields in the Middle East. These tests were conducted over the years to show how the entire test duration is progressively dominated by larger wellbore storage with increasing fracture volume around the wellbore. As a result, the radial flow regime on the pressure derivative plot gets a little chance to develop within the stipulated test period. This abnormal behavior suggests that the wellbore is connected to additional storage volume due to a fracture system around the well, having been intersected by a section of it. Apparently, these fractures close gradually after shutting in the well for a pressure falloff test, manifesting as a prolonged storage effect in the data. The examples with real data will also illustrate the phenomenon of dual storage effect – one due to the wellbore, followed by another one due to the fracture volume. We will show how to use the appropriate fracture storage coefficients to estimate fracture dimensions.
A Comprehensive Look at the CRI Project Pilot Test in KSA
Authors: Al-Dossary Abdulla Faleh , Ahmad Iqbal , Al-Ghamdi Mohammed , Al-Hendi Adel , Al-Haj Haider 
Published: September 2011

Abstract
The current practice for offshore drilling operations requires dumping cuttings immediately after being treated at the site into the sea. In shallow waters; this practice will jeopardize the lives of sea creatures and hinder the marine traffic. Therefore, this method is not applicable for this field. There are three waste disposal methods to replace the existing method; first, the cuttings are treated on site and then shipped to land where they are dumped in special mud disposal pits. Ultimately, those pits are buried. The second option is to dump the cuttings after being treated in a sea trench near wells to be drilled. The third solution is to utilize the advanced waste management technology where the cuttings are injected back into its original environment. The last is considered to be the safest and most cost-effective method. Therefore, the company planned to implement this technique. As a step forward, Saudi Armco elected to test the feasibility of this technology. An old onshore disposal well was selected for this test. In this test, four formations were tested one after another to find out the most appropriate one for hosting the cuttings. This paper discusses and explains the test in detail. Moreover, the injection capacity of each zone tested will be projected against the test results using IPR (Inflow Performance Relationship) and OPR (Outflow Performance Relationship) curves methods.
Production Forecasting in Heterogeneous Reservoirs without Reservoir Simulation
Authors: Akram A. H. , Camilleri L. , Badr A. 
Published: September 2011

Abstract
As an increasing percentage of the world’s production comes from mature fields, there is a growing need for production enhancement techniques that are both rapid and easy to use for the practicing production engineers. For mature waterfloods, the ln(WOR) versus Np plot enables rapid well screening on the basis of incremental recovery factor, where WOR is the producing Water Oil Ratio and Np is the cumulative oil production. Published in-depth information on application of this tool is sparse. Yet, this is often the only tool available to the production engineer for evaluating development options, where a history-matched simulation model has not been maintained.
In this paper, the theoretical basis for the use of the ln(WOR) versus Np is reviewed and studied, and is used to arrive at practical guidelines for interpreting production data. Its applicability as a forecasting tool to single-layered and multilayered clastic, waterflooded reservoirs of varying heterogeneity is demonstrated. Numerical simulation models then predict the behaviour of this plot for a wide range of heterogeneities.
Production data is then analysed to show the applications of the theory for multilayered reservoirs. The ln(WOR) versus Np plots are analysed, and the impact of various factors is observed. The authors also demonstrate that, where applicable, this plot is the preferred decline curve for the following reasons: –Ln(WOR) versus Np does not require any pressure data; only surface well test production history is required.–It can be assumed that the ln(WOR) versus Np function is an approximate function of the reservoir only, and is decoupled from the outflow and facility constraints. This is especially useful when comparing artificial lift and drawdown strategies.–It is a decline curve model that provides a forecast of water cut, which is indispensable on waterflood projects.
Analysis of "Lower Limit Formation" in Low Permeability Sands of Ordos Basin
Authors: Xiao Liang , Mao Zhi-qiang , Shi Yu-jiang , Guo Hao-peng 
Published: September 2011

Abstract
With the analysis of reservoir resistivity and diagenetic facies, the reasons of causing "lower limit formation" are expounded in low permeability sandstones of Ordos basin, northwest China. The difference between dry layers and lower limit formations and corresponding recognition method are displayed. In dry layers, the formations undergo the destructive diagenic metamorphism, such as the kaolinite packing action and dense compaction, this lead the formation poor pore structure, low porosity and low permeability, in these kinds of layers, no fluids can be produced. In lower limit formations, the main diagenetic facies are positive, for example, the chlorite line edge feeble denudation diagenetic facies and unstable component denudation diagenetic facies, but some interlayers with destructive diagenetic facies (kaolinite packing action diagenetic facies, dense compaction diagenetic facies or carbonate cementation diagenetic facies) exist, these make formations’ porosity and permeability decrease and are lower than the conventional reservoirs, the physical property parameters are nearly the same with dry layers. The resistivities of lower limit formations are a little higher than dry layers, the resistivity boundary of them is 42 ohm.m. In reservoirs with porosity and permeability lower than the lower limit value of conventional formations, if the main diagenetic facies are positive (although they contain the interlayers with destructive diagenetic facies) and formation resistivity is higher than 42 ohm.m, oil or water can be extracted after some steps are taken.
Contractor HSE Management via Effective Mitigation of Risk in the Tendering Process
Authors: Elkhair Gamal Abou , Al-Haidar Adnan 
Published: September 2011

Abstract

Description
Effective Management of the Contractor HSE performance starts from an Effective Mitigation of risks in the Tendering Process. In Contracts for Oil & Gas Industry, the work force was mainly Company employees and since 1990 there has been a significant increase in the use of contractor staff which resulting shift in responsibilities/risk from the company to contractor.
International Association of OIL and Gas Producers (OGP) published "HSE Management Guidelines for Working Together in a Contract Environment" (Report No. 6.64/291, September 1999). Most Operators’ HSE Management Systems follow these Guidelines.

Application
Is the following sentence is true?
"There is a very little that Contracts Professionals can do to drive the Best Safety & Environmental Performance on Site." If it is true, HOW can they do it? Is this a paradigm that they should challenge?
How risk assessment is performed and how results are translated into Practical Contract Strategy?

Results, Observations & Conclusions

Significance of Subject Matter
Contracts Professionals can do the followings to drive the Best Safety & Environmental Performance on Site: Include a step in the Tender's process requiring specific technical outputs from Risk Assessment (for input into Tender requirements)Include a step in the Contract award process requiring specific technical output from HSE evaluation (for input to final contract)
Management of HSE in a business environment where two or more companies work together requires co-operation between them and a clear definition of the tasks and responsibilities of each of the parties.
Integrated Pre-Well Planning Process Improves Service Quality and Decreases Risk through Cooperation between Drilling and Geosciences
Authors: Aldawood J. M. , Ahmed K. , Al-Ansari Y. S. , Zubairi B. A. , Hanafi M. X. 
Published: September 2011

Abstract
Drilling complex wells with minimum risk and optimizing well placement with the least possible cost are key goals that oil companies strive to achieve. Service companies and operators apply several pre-well planning processes and methods to enhance drilling operations effectively and attain objectives. One of these processes involves a thorough understanding and application of the geological structure, not only within the reservoir section, but also in the over-burden where typically most of the time efficiency gains can be achieved. This can be best accomplished by fostering intense and effective communication between all stakeholders.
In this paper, the authors present the latest integrated pre-well planning (IPWP) process that defines a methodology for conducting a formal planning, a process incorporating all aspects of drilling, well design, formation evaluation, bit selection and bottom hole assembly proposal. It also lists key considerations required in planning, coordination, and successful implementation of these services on the customer’s well with a means to assess potential technical risks that may influence the success of the job.
The paper also describes a complex water injection well drilled in a Middle East onshore field where the integrated pre-well-planning process played a significant part in successfully achieving the aim of this challenging job.
Measuring the Reaction Rate of Lactic Acid with Calcite Using the Rotating Disk Apparatus
Authors: Rabie Ahmed I. , Nasr-El-Din Hisham A. 
Published: September 2011

Abstract
Lactic acid has been tested in various laboratories and applied in the field for acid fracturing. However, the rate of reaction of lactic acid with calcite has not been addressed before. This is mainly because of the complexity of the reaction kinetics and the thermodynamic equilibrium that limits the acid reactivity. Determination the reaction rate is a critical step for any successful matrix acidizing or acid fracturing. Therefore, the aim of this work is to conduct a detailed study on the reaction of lactic acid with calcite. Mass transport properties and the reaction kinetics are reported for such system for the first time using the rotating disk apparatus.
Core samples of 1.5 in. diameter and 1 in. length were cut from Indiana limestone and were used in the reaction rate experiments. The effect of lactic acid concentration (1, 5, and 10 wt%), temperature (80–250°F), disk rotational speed (100–1800 rpm), and different inorganic salts on the reaction rate was investigated. The diffusion coefficient of 5 wt% lactic acid was determined at low rotational speeds and reported at 80, 200, and 250°F. The data of the reaction rate measured at 1500 rpm and in a temperature range 80–250°F was used to determine the reaction kinetics. The activation energy and the reaction rate constant for the reaction of lactic acid with Indiana limestone was reported at 80, 150, 200, and 250°F.
The reaction of lactic acids with calcite was controlled by mass transfer at low disk rotational speeds (up to 500 rpm) and surface reaction limited at higher speeds. The acid diffusion coefficient increased with increasing the reaction temperature. The presence of inorganic salts significantly reduced the reaction rate.
Successful Field Application of Surfactant Additives to Enhance Thermal Recovery of Heavy Oil
Authors: Srivastava P. , Castro L. 
Published: September 2011

Abstract
In this paper, we will describe successful field applications of a class of surfactants called Thin Film Spreading Agents (TFSA) to enhance thermal recovery of heavy oil. TFSA has been successfully applied in cyclic steam stimulation (CSS) applications in California and Alberta, Canada and three such case histories will be presented. In Canada, three oilsands CSS wells were treated with 250ppm of TFSA. After a certain number of steam cycles, all wells decline in production relative to the previous steam cycle. After 500 days of production the TFSA treated wells only declined 1.0%. The primary control group of wells declined 39%. The cumlative increase in production of the TFSA treated wells was 20% (6718 bbls/well) greater than the control group. In California, 17 vertical CSS wells in a sandstone formation were treated with TFSA to realize incremental oil recovery. Out of 17 wells, 14 showed an average incremental oil recovery of 5411bbls translating into a success rate of 82%. The average payout period was 13 days. The producer realized a net revenue increase of USD 26 million. In another field application in California, 44 vertical CSS wells in a sandstone formation were treated with TFSA to realize incremental oil recovery. Out of 44 wells, 32 showed an average incremental oil recovery of 720bbls translating into a success rate of 73%. The average payout period was three days and the producer realized a net revenue increase of USD 11.8 million. These field results establish the efficacy of TFSA in increasing recovery in thermal applications.
Unified, Automated and Map-based E&P Data Management
Authors: Waked Sahal , Al-Ghamdi Yasser , Al-Zahrani Abdulkarim , Al-Radhi Yassir 
Published: September 2011

Abstract
Increased demand for energy has placed oil and gas companies like Saudi Aramco at the forefront to meet market needs and has required expanded exploration and production activities. As a result, the amount of new exploration data acquired has grown exponentially. This unprecedented expansion of data requires the introduction of new and novel methods and solutions to ensure the value of this vast data is realized.
Saudi Aramco is implementing a unified seismic & well data management system that allows geoscientists and engineers to easily find, access, visualize and transfer data stored in distributed vendor and corporate data repositories. As an example, the Seismic Volume Management web-based system (SVM) was developed to optimize and streamline the E&P data stored across the enterprise. Geoscientists and engineers can now find seismic data using three types of searches: single/multi-field metadata queries, Google like search, or through a GIS map. Users also have the ability to subscribe to email notifications when any selected data located in vendor or corporate databases is changed or updated. Extending SVM features to manage well data will provide a significant improvement to current workflows. This unified data access solution will ensure that geoscientists and engineers spend more time performing E&P activities rather than searching and analyzing data.
An Economic Evaluation Model for Selecting Sand Management Technology
Authors: Lixin Ren , Xiaodong Wu , Benjing Dong 
Published: September 2011

Abstract
As we know, sand production can bring about both positive and negative effects. For example, besides borehole problems, sand production can improve the porosity and permeability of reservoirs. This is why the strategy to handle sanding problems can vary from stimulating sand production to sand control. So far, the industry has developed all kinds of sand management technologies, including treatments both on surface and downhole.
When we meet sand production problems in oil field development, we need to find a solution based on certain of sand management technologies. Conventionally, we conduct an analysis on sand production reasons and possibilities first, and then we pick a technical solution from some known technical alternates. However, generally, it is difficult to tell which option is the best, because when we make a technical decision, the main factor or even the only factor we take into consideration is the technical feasibility or technical advantages of a system. Some operators like to use high-tech solutions, some like to use normal ones. High-tech does not mean definitely to bring a bigger benefit than normal-tech. Unless we have compared the economic benefit of each technical solution within a given term, we cannot tell which one is the best solution.
Economic evaluation model (EEM) for sand management tech selection is seldom discussed in previous references. This paper launches an independent EEM that can help us select the sand management solution by economic benefit evaluation instead of by technical factors solely. Factors related to the model are detailed in the paper. Examples are given to show how to use the model.
In addition, some common issues in sand prediction models are discussed herein, suggestions on how to improve the models given. The paper believes the classification of sanding severity is quite necessary. A classification of sanding severity is proposed.