bluuebunny/crossref_metadata_2025_split huggingface dataset:
WAG Performance in a Low Porosity and Low Permeability Reservoir, Sirri-A Field, Iran
Authors: Taheri A. , Sajjadian V. A. 
Published: December 2007

Abstract
Sirri-A is a large offshore producing field which is located in the Persian Gulf, in Iranian sector, with an OOIP of about 2 MMMSTB. Its reservoir with porosity range of 3-21 percent and a permeability range of 0.1-3 md is situated in Ilam formation which is a complex limestone formation. Because of these range of porosity and permeability, specific strategy that was used includes the use of horizontal injectors and producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. The main production mechanism during natural depletion scenario is rock and fluid expansion. Recently, during this production scenario, the field initial production rate of around 20000 BOPD declined rapidly to around 9000 BOPD within four years. The sharp decline was common in all wells. Therefore, it can not be considered to be local well and/or formation damage. So this reservoir is a candidate for an EOR process. Simulation results show that the most economical method to produce this reservoir is WAG. This production strategy has resulted in better efficiency and therefore higher oil recovery and good economics.
The simulation results illustrate the influence of WAG injection parameters like WAG ratio, WAG half-cycle period and injection rates on recovery process. Also the effect of some uncertain parameters like three phase relative permeability model and anisotropy on WAG performance in this low porosity and low permeability reservoir is investigated.
Fracture Design Considerations for the Development of Tight Gas Formations
Authors: Ionescu G. F. , Awemo K. N. , Pusch G. 
Published: December 2007

AbstractTight gas reservoirs bear large resources of gas all over the world. Due to their very low matrix permeability (&lt; 1mD), the production from these formations is usually below an economical limit, if the reservoir does not contain natural fractures. The use of horizontal wells alone can not significantly improve the economics of tight gas projects. A promising combination is the use of horizontal wells and vertical fractures in order to enlarge the drainage area and improve the reservoir sweep efficiency. For the successful application of this technology the design of the well patterns and fracture design shows an important impact on the production rate and recovery factor.This paper describes the field development options based on a numerical simulation of the production forecast and recovery of multiple hydraulically fractured horizontal wells. Practical formation damage problems, as for example mechanical and hydraulic skin effects are taken into account.The design procedure is a multi-variant analysis of the key parameters, as fracture length, conductivity, fracture spacing and number, length of the horizontal well and well spacing. Water based fracture fluids do not represent an ideal operating solution if the rock contains large quantities of fine dispersed clay cements (illite). Fracture damage may drastically reduce the flow capacity in the fracture. The practical considerations include the different options to stimulate the reservoir with packed and un-packed fractures, to avoid formation damage from fracture fluids and improve reservoir sweep efficiency.The paper underlines the needs to improve hydraulic fracture performance in water sensitive reservoir rocks, as for example the illite cement type of Rotliegendes sandstone.
Revival of Openhole DST: Compromising Between Wireline-Formation Testing and Cased-Hole DST
Authors: Ostrowski L. P. 
Published: December 2007

Abstract
Exploration well testing has gone through several changes over the past twenty years. While open hole Drill Stem Testing (DST) based on conventional technology with mechanically set packer was gradually replaced by inflatable packer based DST tools, cased hole DST became a standard for many exploration companies, particularly offshore. Today, some companies still avoid open hole testing based result of poor success ratios of outdated conventional tools. Also, wireline formation testing has become more frequent due to advances made in wireline test tools.
However, because of greater ability to obtain reservoir productivity and skin measurements, DST continues to be widely used, though cost and environmental issues limit its application in certain areas. Land rigs are natural candidates for open hole DST due to the content and quality of information obtained, as well as well as lower cost of the open hole DST service compared to wireline formation testing. Open hole DSTs are quick and simple to run. Hydrocarbons do not need to be produced to the surface, but a significant volume of reservoir fluid can be produced. Due to these advantages we see an increasing trend to deploy inflatable open hole DST tools on on-shore exploration rigs. The benefits are so convincing that operators using small jack-up rigs consider performing this type of tests as well.
This paper summarizes all aspects of open hole DST with respect to information gained, time needed and related cost. The differences between old type of conventional DST and inflatable DST are highlighted and success ratios provided. Safety aspects are discussed by comparing with wireline formation tester and cased hole DST operations as well as the basic economics.
History Matching of a Tight Gas Reservoir Stochastic Model Using Semiautomated Methods
Authors: Schaaf T. , Martin A. , Coureaud B. , Clay C. 
Published: December 2007

AbstractThis paper presents an integrated methodology (using versatile history matching software) for constraining 3D stochastic reservoir models to well data and production history and its application to a real case (a tight-gas reservoir in the Southern North Sea).The approach is to formulate the history matching problem as a minimization problem where the objective function to be minimized is the squared difference of the real production data values and the corresponding simulated data. To resolve this inverse problem, we use gradient based optimization techniques to update the entire simulation workflow, thanks to advanced parametrization techniques. The set of model parameters characterizes the stochastic geological model (including the diagenetic modeling) and the fluid flow simulator, which allows the facies distributions (and their associated petrophysical properties), diagenetic overprint and well properties (such as skin) to be modified until an acceptable match is obtained.The parametrization technique is coupled to constrained optimization algorithms to ensure that model parameters remain within realistic bounds of the geological settings and ensures that the geologically derived stochastic properties of the initial reservoir are preserved throughout the history matching process.This application shows how the combination of a versatile history matching tool with efficient parametrization techniques can improve the quality and efficiency of a geologically driven history matching process. The speed of this process will be valuable when analyzing a set of history matched models allowing a better assessment to be made of the risk and uncertainty associated with predictions of future performance.
Development of the Strasshof Tief Sour-Gas Field Including Acid-Gas Injection Into Adjacent Producing Sour-Gas Reservoirs
Authors: Behrend J. , Chugh S. , McKishnie R. A. 
Published: December 2007

Abstract
OMV operates two producing sour gas reservoirs in Lower Austria: the Reyersdorfer Dolomite (shallow reservoir) and the Schoenkirchen Uebertief Dolomite (deep reservoir). A new, separate reservoir called the Perchtoldsdorfer Dolomite (Strasshof Tief Field) has been discovered, and options for how its acid gas can be handled are being investigated. The two currently producing reservoirs deliver to a gas plant with a 30 t/d sulphur plant. The sulphur plant is too small to accommodate the additional production. OMV has evaluated acid gas injection as an alternative to a new, larger sulphur plant. Acid gas injection could be into either the Reyersdorfer Dolomite or the Schoenkirchen Uebertief Dolomite. In either case, injection would be occurring concurrently with production. Three injection scenarios are contemplated: 200, 400 and 800 103 Sm3/d (6.4, 12.8 and 25.6 MMcf/d). The applied acid gas composition is CO2 (80 %), H2S (16 %), N2 (3 %) and CH4 or C1 (1 %).
The intent of this project was to determine if sufficient injectivity and storativity is available in either the Reyersdorfer Dolomite or the Schoenkirchen Uebertief Dolomite. Compositional modelling and the prognosis of the breakthrough time at the producing wells was carried out to determine the contamination risk to existing production.
The simulation work included 1)Generating compositional numerical simulation forecasts of production rate/composition forecasts under concurrent injection/production scenario 2)Modeling in-situ miscibility and gravity separation effects of acid gas 3)Evaluating risk scenarios for existing production and determine optimal solution.
Case History of the Matzen Field/Matzen Sand (16th TH): A Story of Success—Where is the End?
Authors: Kienberger G. , Fuchs R. 
Published: December 2007

Abstract
The Matzen Sand (16th TH) was discovered in 1949. To date, some 42.3 million m3 (266 million STB) oil and 3.75 billion m3(Vn) (140 billion scft) gas were produced which leads to a recovery factor of 48.5 %. Average water cut is 93.5 %. Mean porosity is 27 %. The oil has 25°API gravity. The sand is relatively homogeneous and exhibits a pay thickness between 1 m up to 70 m (3.3 ft to 230 ft). ‘Hard layers’ (tight streaks) reduce vertical permeability in certain areas.
1968 a peripheral water injection project was commenced. Discontinuous hard layers distributed throughout the reservoir affect water flooding. Sweep efficiency is related to these hard layers. Areas of unswept oil between these tight layers have been proved by reperforation of certain producing wells.
In 1996 natural gas injection started into the gas cap which caused a reduction of the oil production decline by 50 %.
Successful production history of the 16th TH results from proper reservoir management through 55 years of field life.
Application of Real Time Surveillance and Optimisation Tools on a Large Asset
Authors: van Zandvoord Walrick E. J. J. , Maskery Ali Abdullah , Schmid Tom 
Published: December 2007

Abstract
This paper demonstrates the use of real time well surveillance and optimization tools in the Northern Fields of Petroleum Development Oman LLC (abbreviated as PDO in the rest of this paper). The use of such software as part of the Real-Time Infrastructure (including a data historian and PDO's in-house developed Production Portal for long term real time data trends) has been one of the key enablers to create renewed focus in Well & Reservoir Management. Furthermore it was one of the contributing factors in significantly reducing unscheduled well deferment.
The software that was used is highly modular, hence was used to target specific PDO problems quickly and cost-effectively. Monitoring, reporting and alarming functionality was used to identify problems, while the analysis functionality was used to find causes of those problems. In some fields real time flow estimation was implemented based on data driven well models (i.e. empirical as opposed to physical well models), which give a continuous real time estimate of oil, gas and water.
Intensive use of the data has led to reduced deferment, early identification of well problems and lower decline rates by e.g. identifying fracturing and short-cutting of injectors to producers. PDO's Real-Time Infrastructure has built in data integration capabilities, which allow easy integration of the data throughout the company without requiring duplication of the data.
The combination of effective use of all the applications in and around the Real-time Infrastructure and complementary initiatives (mostly with a focus on wells) have improved production and mitigated decline, equivalent to a sustainable production improvement of around 7,000 bpd.
Real-Time Transmission of High-Resolution Images
Authors: Fulda C. , Akimov O. , Baule A. , Bethge J. , Roessel T. , Tilsley-Baker R. 
Published: December 2007

Abstract
Recent advances in high-resolution imaging are well perceived by the oilfield industry as an aid to refine reservoir characterization. The availability of high resolution image data in real-time allows for improved decision making and more optimal wellbore placement when navigating through the reservoir. However, the transmission of high resolution image data to surface is limited by the bandwidth offered by mud pulse telemetry systems.
This paper describes a new concept for transmitting imaging data to surface in real-time. The concept includes a highly flexible and effective compression scheme that can be used for all currently available and future telemetry systems. Image transmission parameters can be modified via downlink commands at any time without interruption of the drilling process. In this way, image parameters can be optimally adjusted to suit the available telemetry rates and proportion of the bandwith dedicated to image transmission. This flexibility allows customization of the real-time imaging service to optimize the geosteering process and the ability to provide high resolution data over specific zones of interest.
The relationship of pixel size, telemetry rate and the real-time image parameters of latency and redundancy are discussed with reference to real-time resistivity images from field measurements transmitted at different telemetry rates and the corresponding memory images.
Field Case Studies: Damage Preventions Through Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas Reserviors
Authors: Paktinat J. , Pinkhouse J. A. , Williams C. , Clark G. A. , Penny G. S. 
Published: December 2007

Abstract
The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension, contact angle and leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out reducing their effectiveness in post fracturing fluid recovery.
This study describes experimental and field case studies of various surfactants used in the oilfield. Several different surfactants including a nonionic ethoxylated linear alcohol, nonyl phenol ethoxylate, an amphoteric, a cationic and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sand packed column. A laboratory simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and water recovery properties from gas wells.
Field data collected from Bradford, Balltown and Speechley sandstone formations confirmed experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage.
Near-Surface External Casing Corrosion in Alaska: Cause and Mitigation
Authors: Dethlefs J. C. , Blount C. G. , Bollinger J. C. 
Published: December 2007

Abstract
Recently, a number of external casing failures on a group of relatively new wells in the Kuparuk field of Alaska prompted an investigation into the cause. The investigation determined that external surface casing corrosion failures had occurred near the top of the casing cement within the conductor.
The surface casing corrosion was found to be caused by repetitive events of surface water entering into the top of the annulus between the surface casing and the conductor above the primary cement top. Testing of water and cement samples taken from the field indicate that the addition of oxygenated water and chemical salts that leach from the cement creates a low-resistance electrolyte resulting in an extremely corrosive environment. The yearly replenishment of oxygenated water in this environment sets up an electro-chemical cell that corrodes the surface casing. Elevated casing temperatures (~125 deg. F) accelerate the corrosion rates as well as the temperature gradient between the casing and the conductor creating a thermogalvanic corrosion cell.
Although damaged surface casing has been mechanically repaired on numerous wells by excavation and installation of welded sleeve patches, accessing the damaged surface casing can be difficult. Inhibiting the corrosion mechanism is considered a more tenable solution.
This paper will:Provide an outline of extent of shallow external casing corrosion seen in the field;Detail the mechanisms for the external corrosion;Detail the mechanical repair procedures used to return the wells to service;Discuss possible mitigation methods to inhibit corrosion on existing wells;Discuss the treatment chosen to stop the corrosion;Provide details of the first treatments to inhibit further shallow casing corrosion.
Case Study: Modeling of a Large-Scale Tight-Gas Gathering System
Authors: Stevenson B. K. , O'Shea C. D. 
Published: December 2007

Abstract
This case study outlines the techniques used to model the Williams Production RMT Grand Valley gas gathering system in the Piceance Basin. The results of the modeling exemplify how a nodal analysis model can become an invaluable tool for optimizing the performance of gas gathering systems and planning future system expansion.
Field production in the Grand Valley gathering system varies minute by minute, creating a dynamic system that is difficult to model with standard practice. Using an innovative statistical method to handle the scale and complexity of the system, the model has consistently and accurately simulated the true flowing conditions of the system over the last five years. The model has been used to successfully locate and quantify substantial static and frictional pressure losses. As the field develops, proposed drilling programs are added to forecast the impact of the new wells on the system. Various pipeline and compressor expansion scenarios are tested to determine the most effective locations and cost viable options.
Recommendations from the model have been successfully implemented and have played an integral role in the expansion of the gathering system. The model has been used to identify exact locations of pressure losses, help plan for incremental drilling volumes, and quantify the additional costs incurred from third party gas entering the system.
This paper explains how a model can assist in the successful development of a large scale, high volume, and dynamic gas gathering system. Details of the modeling procedure and highlights of the innovations implemented to meet the challenging operating conditions and aggressive development of this field are presented.
Effect of Environmental Contamination on the Susceptibility of Corrosion-Resistant Alloys to Stress Corrosion Cracking in High-Density Completion Brines
Authors: Downs J. D. , Leth-Olsen H. 
Published: December 2007

Abstract
There has been renewed interest in the corrosivity of high-density well completion and packer fluids in recent years following a series of failures of Corrosion Resistant Alloy (CRA) tubing strings from the annular side as a result of stress corrosion cracking (SCC). It is now realised that the original corrosion testing carried out on traditional halide-based completion and packer brines may have been too cursory, and missed some important environmental factors that make CRA susceptible to SCC in these fluids. New studies have shown that some CRA become susceptible to SCC in halide brines charged with CO2 and H2S, but there remain some uncertainties about the boundary conditions that trigger the SCC.
The objective of the laboratory experiments described in this paper was to examine how the contamination of high-density brines with oxygen, chlorides and CO2 might influence the susceptibility of CRA to SCC under high temperature-high pressure (HTHP) conditions. Our results highlight the increased risk of SCC occurring in CRA tubular materials when bromide-based completion brines become contaminated with oxygen or CO2 during field use in HTHP wells. Our tests also indicate that similar contamination of formate-based completion brines is less likely to create SCC problems in CRA tubular materials in HTHP wells. We conclude that the current North Sea trend for using formate-based completion fluids in place of bromides may provide better insurance against SCC-related tubing failures.
Inhibitor Performance on Corrosion and Erosion-Corrosion Under Turbulent Flow With Sand and CO2—An AC Impedance Study
Authors: Wang C. , Neville A. 
Published: December 2007

Abstract
Erosion-corrosion is a severe problem in oil and gas producing wells due to high flow velocity and sand particles entrained in the system. Using corrosion inhibitors to reduce erosion-corrosion has recently been proposed as an economically viable solution for carbon steel piping systems [1]. In the literature, most studies using inhibitors to mitigate corrosion have been conducted under stagnant or low flow rate (&lt;1 m/s) conditions. However severe erosion-corrosion may occur when inhibitor films are removed from the steel by high liquid shear forces under actual oil and gas production conditions.
The inhibiting effect of a commercial inhibitor (named inhibitor A [2]) on the behaviour of carbon steel in CO2 saturated media has been examined under high flow velocity with sand by electrochemical and gravimetric measurements. Experiments were performed using a Rotating Cylinder Electrode (RCE). The AC impedance technique was used to study the effect of inhibitor adsorption onto the metal surface. The study clearly reveals the fact that the addition of the inhibitor moves the corrosion potential towards positive values and reduces the corrosion rate. Changes in impedance parameters (Rct and Cdl) are indicative of adsorption of inhibitor on the metal surface leading to the formation of protective films.
Effect of Fracture Compressibility on Gas-in-Place Calculations of Stress-Sensitive Naturally Fractured Reservoirs
Authors: Aguilera R. 
Published: December 2007

Abstract
The tank material balance (MB) equation for gas reservoirs has been written taking into account the effective compressibility of matrix and fractures.
The method has direct application on stress-sensitive naturally fractured reservoirs (nfr's). Under some conditions ignoring the effect of fracture compressibility (cf) can lead to over-estimating the volume of original gas in place using a cross-plot of p/z vs. Gp. The equation presented in this paper has been developed to overcome this weakness. The use of this MB is illustrated with an example.
It is concluded that fracture compressibility can play an important role in the calculation of gas in place in naturally fractured reservoirs.
The subject matter is significant because historically formation and water compressibilities have been neglected when carrying out MB calculations of conventional gas reservoir. This assumes that these compressibilities are negligible compared to gas. The assumption implies that the reservoir strata are static. When water influx is ignored, the assumption leads to a straight line in a cross-plot of p/z vs. cumulative gas production (Gp). However, this study shows that in those instances where fracture compressibility is large, the assumptions can lead to significant error.