bluuebunny/crossref_metadata_2025 huggingface dataset:
Design, Development and Testing of a Slimhole Rotary Steerable System
Authors: Jones S. , Sugiura J. , Das P.
Published: July 2010

The first commercially successful Rotary Steerable Systems (RSS) were introduced in the mid-1990's for 8 ½-in. and 12 ¼-in. sections on high-end drilling applications. As the systems have matured and day rates reduced, they have been adapted to drill all borehole sizes from surface to the target depth.

RSS are highly complex tools consisting of mechanical, hydraulic and electrical systems all functioning simultaneously. Because of their complexity, systems designed for slimhole applications (5 ¾-in. to 6 ¾-in. sections with 4 ¾-in. collars) have typically been challenged with poor reliability. As these slimhole systems have matured, reliability and durability have increased through continuous improvements in some of the most challenging drilling conditions.

This paper presents the design, development and testing phases of a new slimhole RSS. The design stage describes the use of existing experience from larger RSS and methodology to make the assembly adaptable to all drilling applications. The development and testing phases of the project will be described in detail from workshop and drilling facility testing to semi-commercial applications to evaluate performance.

The confidential drilling facility testing was used to evaluate and enhance directional performance and reliability with a wide range of formations, drill bits, bottom-hole assemblies (BHA) and parameters. The testing format was designed around current directional well profiles for 5 7/8-in. to 6 1/8-in. hole where RSS are typically deployed. Reliability improvement was established by gradually step changing drilling and directional parameters to maximum or beyond the design specification of the system.

The initial customer trial phase of the system in established RSS environments is used as a proving ground to further develop the product for superior performance in challenging drilling applications.
Development of Test Method and Inhibitors for Lead Sulfide
Authors: Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Jeffrey Catharine
Published: July 2010

Lead sulphide (PbS) is one of ‘exotic’ scales deposited in the oil and gas industry. The inhibition of lead sulfide scale deposition is notoriously difficult compared to calcium carbonate and barium sulphate. In addition, it is extremely difficult to test lead sulfide formation and inhibition in laboratory with the conventional static jar and dynamic loop tests and very little is still understood about its mechanism of formation and inhibition.

In this paper, a novel stress test method has been developed and applied to test the performance and understand mechanisms of lead sulphide inhibition. Compared with the traditional static jar and dynamic loop tests, this test method shows good reproducibility and provides a quick and effective way to evaluate the performance of lead sulphide scale inhibitors.

Typical commercial scale inhibitors, including six phosphonate based scale inhibitors, PPCA, polymaleic acid, polyacrylic acid, polyaspartate, PVS and patented environmentally friendly polyacrylic copolymers have been tested based on this newly developed method. The performance of scale inhibitors on PbS inhibition can be classified as three types:

Type 1: Dispersion inhibitors. These scale inhibitors showed a dispersion effect on PbS formation. The turbidity in stress curve in the presence of these inhibitors is slightly higher than that in the absence of scale inhibitors.

Type 2: Nucleation/growth dominated scale inhibitors. These scale inhibitors inhibit nucleation and growth of PbS formation, where the test can be stressed further in the presence of these inhibitors.

Type 3: Scale inhibitors with poor performance on PbS inhibition. These inhibitors showed less PbS inhibition performance. The turbidity in stress curve did not change obviously in the presence of these scale inhibitors.

This paper will give the comprehensive study of lead sulfide formation and inhibition, which includes development of the test method and scale inhibitors for lead sulphide inhibition.
Investigation of Various ROP Models and Optimization of Drilling Parameters for PDC and Roller-cone Bits in Shadegan Oil Field
Authors: Bataee Mahmood , Kamyab Mohammadreza , Ashena Rahman
Published: July 2010

According to the field data, there are several methods to reduce the drilling cost of future wells. One of these methods is the optimization of drilling parameters to obtain the maximum rate of penetration (ROP) in each bit run. Many parameters affect ROP like hole cleaning (including drillstring rotation speed (N), weight on bit (WOB), floundering phenomena, mud rheology), tooth wear, formation hardness (including depth and kind of formation), differential pressure (including mud weight (MW)), etc. Considering the geology and rock mechanical parameters, each part of well has different recommended parameters from the other parts. To optimize the drilling parameters, it is required that an appropriate ROP model to be selected until acceptable results are obtained. In literature, there are various applicable models to predict the ROP such as Bourgoyne and Young model, Bingham model and modified Warren model. It is desired to calculate and predict the proper model of ROP for roller-cone and PDC bits in each well by using the mentioned models and then verify the validity of each model by comparing with field data. Analyzing the drilling parameters by computer optimizationyields recommended range of parameters for each bit. The applications of present study are predicting the proper penetration rate, optimizing the drilling parameters, estimating the drilling time of well and eventually reducing the drilling cost for future wells.
Research into Steam Overlay Pattern and Countermeasures for Block Du84 in Liaohe Oilfield
Authors: Aiwu Yuan , Hong Ma , Xianyong Yang , Xiaosong Zheng
Published: July 2010

Numerical simulation method is applied to study the effects of some parameters on steam overriding, including oil layer thickness, crude viscosity, vertical/horizontal permeability ratio, perforation method, etc. Therefore, the change pattern of steam overriding is obtained and the technical conditions for steam overriding are pointed out. Field test results indicate that by taking some measures, such as adopting the "uphole" perforation, profile control, separate or selective steam injection, vertical and horizontal well combined SAGD, etc., the uneven producing of the reservoir vertically due to steam overriding can be further decreased. Moreover, these measures play an important role in increasing oil recovery ration during the later production period of CSS. The successful application of these techniques will provide theoretical support and technical guarantee for the production of similar super heavy oil reservoirs in the world during the later production period of CSS.
Investigation of Steam Injection at Critical Condition and a Pilot Test in 119-52, Chao-601
Authors: Xin Zhao , Yongbin Wu , Baofeng Wu , Panqing Gao , Huiying Zhong , Bateer Hasi , Yu Qian
Published: July 2010

The Chao-601 is a typical low-permeability naturally fractured reservoir of Daqing. Without a primary depletion, the secondary water flood was employed at the beginning of the development. Because of both the complexity of fracture distribution and relatively high oil viscosity, the water flooding could not meet the demand of stable output; the water broke through only a few years after injection. The predicted waterflooding recovery is only 13.4%. In order to improve the recovery, the investigations of steam injection in the Chao-601 field were performed. Correspondingly, a pilot test was conducted in the 119-52.

By combining plenty of geological study and multidisciplinary investigation, a simulation model describing pilot area was established. The simulation study focused on the flow characteristics of injected steam at critical condition and the effects of fractures on sweep efficiency. Furthermore, the injection system was optimized on the basis of the recognition of steam flow behavior. Important factors included the selection of well pattern, well spacing, and injection rate. Based on the optimization of injection system, the pilot test carried out in the 119-52 block.
Smart and Multi-Functional Coatings Based on Micro/Nano Sized Additives and Their Implementation
Authors: Boura S. Hatami , Samadzadeh M. , Peikari M. , Ashrafi A.
Published: July 2010

Coatings and especially organic ones application is the commonest and in many cases, cheapest and easiest method to protect the structures and equipment from corrosion and sometimes provide decorative appearance. There are many aggressive agents which can make disorder in coating performance. In the today's generation of protective coatings, it is important to provide several functionalities with the essential possibility to react on external impact, such as distortion of the coating integrity, surface pollution and bacterial attack, intelligently. Providing smartness for coating is a young novel to mitigate/solve many of these problems, thus the coating shows an adequate response against mechanical/chemical damages or even environmental changes to neutralize the negative results. Self-healing, self-cleaning, pH sensitive, temperature sensitive, selective absorption of gaseous pollutants and corrosion sensing coatings are a small group of large family of smart ones. These properties have been achieved through organic or inorganic additives in micro or nano size. Creation and manipulating these additives in order to achieve smart coatings with new functionality has been extensively described in literature and patents over the last 10 years.

This extensive study describes the principles of this novel multifunctional/smart coating background, concept and advantages and discusses the smartness and performance on the basis of laboratory results which have been presented by different authors up to now (self-healing, anti-bacterial, high temperature resistance and self-cleaning coatings). Also various approaches for achieving smart and multi-functionality are mentioned. The effects of different parameters on their performance and serviceability are also explained.
Application of Horizontal Wells to Reduce Condensate Blockage in Gas Condensate Reservoirs
Authors: Miller Nathan , Nasrabadi Hadi , Zhu Ding
Published: July 2010

Natural gas is an important source for global energy. It will play a more important role in the future due to increasing energy demands, existing constraints in oil production, and environmental concerns for other fossil fuel types. Much of the current gas reserves can be found in gas-condensate reservoirs. These reservoirs, from a recovery and deliverability standpoint, can have significant differences from oil reservoirs. When the pressure, either in the wellbore or in the reservoir, drops below the dew point pressure, a liquid condensate phase appears and reduces gas production significantly. Several methods have been suggested to handle the condensate blockage problem: hydraulic fracturing, wettability alteration, Huff ‘n’ Puff gas injection, and nonconventional wells. In this work, we study the application of horizontal wells in a giant gas-condensate reservoir (North Field-Qatar) to reduce the condensate blockage. We try to address a critical question of what fraction of increased gas production in a horizontal well is due to increased formation contact and what fraction results from condensate blockage reduction. Horizontal wells have smaller drawdown pressures than vertical wells, which leads to a delay in reaching the dew point pressure compared to vertical wells. Our results indicate that once the dew point pressure is reached and oil saturation is formed in the reservoir, the magnitude of oil saturation buildup in the near wellbore is lower in a horizontal well than a vertical well. The ratio of horizontal well PI to vertical well PI increases after the dew point. The fact that the PI increased after reaching the dew point indicates that this increase in productivity index is directly due to the ability of the horizontal well to reduce condensate blockage in the near wellbore. The PI in the vertical well case is decreasing significantly once the dew point pressure is reached, while the PI in the horizontal well seems to remain steady even after the dew point pressure is reached.
Using Genetic Algorithm to Optimize Well Placement in Gas Condensate Reservoirs
Authors: Morales A. , Gibbs T. , Nasrabadi H. , Zhu D.
Published: July 2010

Well placement within a reservoir is a significant and difficult step in the reservoir development process. Determining the optimal well location is a complex problem involving many factors including geological considerations, reservoir and fluid properties, economic costs, and technical ability. The most thorough approach to this problem is that of an exhaustive search, in which a simulation is run for every conceivable well position in the reservoir. Although thorough and accurate, this approach is typically not used in real world applications due to the time constraints from the excessive number of simulations. This paper suggests the use of a genetic algorithm applied to the horizontal well placement problem in a gas reservoir to reduce the required number of simulations. The objectives are to identify the optimized well placement and then to determine the benefit of optimization. Performance of the genetic algorithm was analyzed through different case scenarios. The genetic algorithm approach is used to evaluate the effect of well placement in heterogeneous and anisotropic reservoirs on reservoir recovery. The wells are constrained by surface gas rate and bottom-hole pressure for each case.

We apply this technique to find the optimal horizontal well location in a gas condensate reservoir in Qatar’s North field. The research provides evidence that well placement optimization is an important criterion during the reservoir development phase for horizontal wells in gas reservoirs, but it is less significant to vertical wells in a homogeneous reservoir. It is also shown that genetic algorithms are an extremely efficient and robust tool to find the optimal location.
Application of Multi-rate Well Tests to Scale Management
Authors: Tjomsland Tore , Sandøy Bernt , Fadnes Finn Hallstein
Published: July 2010

Veslefrikk is a mature oil field in the Norwegian sector of the North Sea. It has a layered structure with several pressure-independent layers and three main fluid systems: the Statfjord Formation, Intra Dunlin Group and Brent Group. Each fluid system has distinct formation water compositions but similar oil compositions. Seawater injection has been used for pressure support and many wells have commingled production. The principal scale control challenges are scaling potential and placement of scale inhibitor into zones with different pressure. Although production logging is performed regularly to aid scale squeeze designs and production allocation, this is costly, involves well intervention risks and it cannot always be undertaken when required.

In this study an innovative approach to obtain ‘production logging type’ information from wells producing from two zones has been evaluated. It involves undertaking multi-rate well tests where produced water samples are collected at each rate. Depending on the conditions for each test, either qualitative or quantitative integrated analysis of the well test results and produced water compositions can be performed. Information obtained from the tests for each zone includes: Pressure, productivity index, water cut, produced water composition and seawater fraction.

The methodologies adopted for the multi-rate tests and the analysis of their results are described, and the results for four multi-rate tests are presented. The multi-rate tests were undertaken under different conditions and the influence of these conditions on the type and quality of results obtained are discussed, and assumptions and associated uncertainties are identified.

The case studies demonstrate that information useful to scale, well and reservoir management can be obtained from multirate tests. In addition, produced water compositions can be obtained from these tests without the need for downhole sampling. However, in each case it is important to assess uncertainties associated with the results.
Wettability Index of Carbonatic Reservoirs and EOR: Laboratory Study to Optimize Alkali and Surfactant Flooding
Authors: Bortolotti V. , Macini P. , Srisuriyachai F.
Published: July 2010

Rock wettability is one of the most important factors driving oil recovery mechanisms, as it controls the location, flow and distribution of reservoir fluids. Wettability affects most of the petrophysical properties of reservoir rocks including capillary pressure, relative permeability, waterflood behavior, electrical properties, and enhanced oil recovery (EOR). Most reservoir rocks are water-wet since they were originally formed in marine or lacustrine sedimentary environments. During hydrocarbons migration, reservoir rocks can be reversed to oil-wet conditions because of surface electrical charges of the grains that attract the oppositely charged components contained in the migrating hydrocarbon phase. Carbonatic reservoir rocks normally show a moderate to strong oil-wet condition. Alkaline substances and some surfactants have the capability to reverse the oil-wet reservoir rocks into a more favorable condition for enhancing oil production. In particular, such mechanism is normally deployed to increase the oil recovery factor of chemical flooding EOR projects. Laboratory testing at reservoir conditions is always required before implementing any field application and the wettability reversal measurement is a key factor for the success of the above EOR application. The present study was performed at the Petroleum Engineering laboratory of the University of Bologna (Italy). Here, it has been clarified that the displacement-by-oil ratio significantly affects the Amott-Harvey wettability index, which affects the final oil recovery expected by the application of alkali and alkali-surfactant flooding EOR technique. On the other hand, only a small change of displacement-by-water ratio can be observed throughout the experiments. This observation can be interpreted as the improvement of oil recovery factor induced by alkali and alkali-surfactant flooding is caused primarily by a lesser preference to oil more than by the complete reversal of previously oil-wet into full water-wet condition. In particular, the maximum relative oil recovery of the strong oil-wet carbonatic rock is obtained when the Amott-Harvey wettability index is close to zero or when the reservoir rock turns into a neutral-wet condition.
Microbial Enhanced Oil Recovery: 3D Simulation with Gravity Effects
Authors: Nielsen S. M. , Jessen K. , Shapiro A. A. , Michelsen M. L. , Stenby E. H.
Published: July 2010

Microbial enhanced oil recovery (MEOR) utilizes the activity of microorganisms, where microorganisms simultaneously grow in a reservoir and convert substrate into recovery enhancing products (usually, surfactants). In order to predict the performance of a MEOR process, a simulation tool is required, with all the relevant physical processes included.

We have developed a mathematical model describing the process of MEOR, where reactive transport is combined with a simple compositional approach. The model describes the displacement of oil by water containing bacteria, substrate, and the produced metabolite, surfactant. The metabolite is allowed to partition between the oil and water phases according to a distribution coefficient. Production of surfactant decreases the oil/water interfacial tension, reduces the residual oil saturation, and provides additional oil recovery.

In this work, we have implemented our MEOR model into a compositional streamline simulator based on the standard IMPEC framework (implicit pressure, explicit composition) to decouple flow and reactive transport. The reaction and transport processes are solved simultaneously along each streamline. Gravity effects are implemented using an operator splitting technique. To the best of our knowledge, this has resulted in the first full 3D MEOR streamline simulator. For verification purposes, we compare results from our streamline MEOR simulator to those of a conventional finite difference approach for 1D and 2D displacement calculations. We investigate the benefit of MEOR relative to water flooding, comparing the processes in multiple dimensions.

The results of our simulations demonstrate that the oil recovery from MEOR processes in relation to water flooding is markedly increased, and the high recovery is achieved much faster. In addition, the compositional streamline simulator is applied to study both microscopic and macroscopic displacement efficiency of MEOR.
Thief Zones and Effectiveness of Water-Shut-Off Treatments under Variable Levels of Gravity and Reservoir Heterogeneity in Carbonate Reservoirs
Authors: Ghedan Shawket , Boloushi Younes , Saleh Moutaz
Published: July 2010

Progressive percentage of total fluids produced in the oil industry is formation brine. Ever, increasing water cut will reduce oil recovery, diminish wells' productivity and increase the cost of eventual artificial lift and produced water handling. In addition to mobility ratio, the predominant factors that cause and aggravate irregular movement of injected water resulting in early water breakthrough and high water cut wells is gravity and reservoir heterogeneity.

Through very comprehensive simulation study, performed on a sector model extracted from a layered and heterogeneous carbonate oil reservoir, this paper investigated the evolution of injected water front and the level at which high permeability layers will act as a thief zone causing early water breakthrough. The paper determined the effect of different reservoir heterogeneity parameters on the behavior thief zones, including thief zone's horizontal permeability, kv/kh ratio, and thickness. The threshold of these parameters and their various combinations that cause a higher permeability layers to act as thief zones were established and for different levels of reservoir permeability (very low, low, medium, high, and very high). Moreover, the paper investigated the effect of gravity on the process by comparing the behavior of top versus bottom thief zones. The difference in the combination of reservoir parameters that cause their different behavior is reported. In order to generalize the outcomes of this paper, all results are presented in terms of dimensionless variables.

Water-shut-off, WSO, treatments were then simulated to determine their effectiveness in delaying the water breakthrough time, and reducing high water cuts, under different thief zones' conditions. Extreme thief zone cases were selected from the first part of the study for this purpose. The paper finally summarizes the applicability of these WSO treatment methods and at which conditions of reservoir heterogeneity and gravity, they are or are not effective.
The Choice of a ‘Best’ Assisted History Matching Algorithm
Authors: Hanea R. G. , Przybysz-Jarnut J. K. , Krymskaya M. V. , Heemink A. W. , Jansen J. D.
Published: July 2010

Computer-assisted history matching is the act of systematically adjusting a ‘prior’ reservoir model using measured data until its simulated production response closely reproduces the past behavior of the reservoir. Thereafter, the updated, ‘posterior’, model is expected to predict future reservoir behavior with a higher degree of confidence, particularly if the adjustments are constrained by known geological properties of the reservoir. The accuracy of the history matching process depends on the quality of the prior reservoir model and the quality and quantity of measured data, typically production data (pressures and flow rates at well locations). The uncertainties in the prior reservoir model and in the measurements have a strong effect on the uncertainty in the parameter values of the posterior model, and thus on the predictions to be made with that model. A common way to include these uncertainties is through the specification of spatial covariance matrices for prior reservoir parameters and measurement errors respectively. Here we consider two assisted history matching techniques that use such a covariance-based uncertainty description, the representer method and the ensemble Kalman filter, both originating from oceanography. In their most simple form, used for state estimation in linear systems, they lead to identical estimates. However, when applied to nonlinear reservoir models their results differ. We compare the quality of the parameter estimates using both methods for a synthetic ‘twin experiment’ where the true parameter field is known allowing for comparison with the estimates. We consider simple two-dimensional water flooding cases with ‘true’ reservoir permeabilities represented by either a Gaussian random field or a channelized geology. The corresponding spatial covariance matrices are obtained with the aid of geostatistical ensembles of prior models, conditioned on known permeability values in the wells. We compare the quality of the history match, the permeability estimates, and the predicted water rates after the history matching period using both methods, starting from two different priors for each of the methods. We conclude, for the cases considered in this study, 1) that because of the limited information present in production data assessing the ‘best’ method to reconstruct the parameter field is not possible; 2) that from the point of view of prediction after the assimilation period, the ‘best’ assisted history matching method appeared to be the representer method, but that this might be related to the particular implementation of the methods in our study, and 3) that further research is required into the effect of treating nonlinearities in the system and output equations, and especially into the effect of iterative procedures.
Achieving Extending Squeeze Life in Challenging Wells - A Non Conventional Approach
Authors: Sorhaug Eyvind , Jordan Myles M. , Marlow David , Stalker Robert , Graham Gordon
Published: July 2010

Over the past 10 years significant improvements in "green" scale inhibitor chemistries have led to considerably increased use in certain regions, notably the Norwegian sector of the North Sea. However, the use of these more environmentally acceptable products can be at the cost of optimum performance. This was the case for the Varg field: an extensive Best-In-Class re-selection of available yellow / green polymeric inhibitors failed to achieve the required improvement in lifetimes. Modelling work conducted for one of the wells had also shown that one of the primary causes of the poor lifetimes was the lack of effective placement of the treatment chemical in the water-producing zones.1 More recent experimental work to be described in this paper has demonstrated that the scaling challenges on this field could be mitigated in part by adopting the less environmentally friendly, but better retaining, ‘red’ phosphonate chemical. Comparison of the predicted inhibitor return profile using laboratory derived data with the subsequent field return showed very good correlation in a well with no placement challenge. In a manner analogous to the polymer-based chemistries,1 application of the phosphonate inhibitor in a well with known placement issues gave less impressive return lifetimes. However the better retention properties meant that the treatment lifetimes remained acceptable despite the poor placement. When the placement issues were taken into account, the previously derived isotherm proved very effective at simulating the field case in this more challenging well. This paper therefore describes an alternative, more rigorous approach to simulating treatments in challenging wells rather than using history matched averaged field return isotherms. The paper then shows the impact on optimisation of future treatments when the different approaches are examined. This work therefore expands considerably on that previously described in SPE 114077.
The Influence of CO2 Solubility in Brine on Simulation of CO2 Injection into Water Flooded Reservoir and CO2 WAG
Authors: Yan Wei , Stenby Erling H.
Published: July 2010

Injection of CO2 into depleted oil reservoirs is not only a traditional way to enhance oil recovery but also a relatively cheaper way to sequester CO2 underground since the increased oil production can offset some sequestration cost. CO2 injection process is often applied to water flooded reservoirs and in many situations alternating injection of water and CO2 is required to stabilize the injection front. Both scenarios involve a large amount of water, making CO2 solubility in brine, which is around ten times higher than methane solubility, a non-negligible factor in the relevant reservoir simulations. In our previous study, a 1-D slimtube simulator, which rigorously accounts for both CO2 solubility in brine and water content in hydrocarbon phases using the Peng-Robinson EoS modified by Soreide and Whitson, has been used to investigate the influence of CO2 solubility on the simulation of continuous CO2 flooding with uniform initial water saturation. As a follow-up of the previous study, this study extends the investigation to two more realistic scenarios (1) CO2 injection into water flooded reservoir and (2) water-alternating-gas (WAG) injection with CO2 as the injection gas. A series of 1-D simulations were made for seven oil samples within a wide range of temperature, pressure and salinity. The results were analyzed in terms of the change in oil recovery due to different phase equilibrium descriptions, the delay in breakthrough and the CO2 lost to the aqueous phase. The influence of different factors, including temperature, pressure, salinity, water injection pore volume, WAG ratio and CO2 slug size, on the simulation results was also discussed. In addition, the results for CO2 injection into water flooded reservoirs were also compared with those from the previous study.
Logging under Harsh Conditions with New Shuttle-Deployed Memory Tools and Impact on Log Quality, Time and Costs
Authors: Miranda Luis Javier , Angel Franklyn
Published: July 2010

Operational conditions in certain fields can cause various difficulties during logging operations. When such situations occur, we usually opt for logging-while-drilling (LWD) tools. In this paper, we present field applications and advantages of a new generation of tools called shuttle-deployed memory (SDM) tools. Because they can operate under critical borehole conditions and highly deviated wells, SDM tools offer a viable alternative to LWD.

We successfully applied this technology to acquire well-log data in two fields of clastic and carbonate reservoirs in the Barinas-Apure Basin, Southwest Venezuela. In this area, conditioning the hole is a required procedure before running logging tools; therefore, the logging system's capacity to get information while conditioning the borehole favored its application when logging under harsh conditions. We show three cases considering wells with angle of deviation up to 40º, dog leg severity up to 4º/100 ft, and several washout and unsteady zones. A comparison with resistivity measurements obtained using an LWD tool is also included in one of the cases, illustrating remarkable improvements in log quality. We also used the acquired information as an input for petrophysical assessment. The results satisfactorily compared against neighbor wells with data obtained from conventional wireline logging tools and rock-core measurements. Likewise, a detailed analysis of time and cost describes the impact of the application of this type of technology on operations in Guafita and La Victoria Fields in Venezuela.

We conclusively found that the application of SDM tools for formation evaluation data acquisition reduces logging time by 62% and logging costs up to 44% in these fields. In addition, we obtained reliable well-log information with significant improvements in log quality. More important, the application of SDM tools allowed us to bypass the limitations in terms of variety and quantity for logs that were commonly acquired with LWD tools.
Polymer Flooding – Flow Properties in Porous Media Versus Rheological Parameters
Authors: Stavland A. , Jonsbråten H. C. , Lohne A. , Moen A. , Giske N. H.
Published: July 2010

Mobility reduction is one of the critical parameters in polymer flooding. The EOR polymers have shear thinning bulk rheology, while core flood experiments with hydrolysed polyacrylamide (HPAM) in this paper show four different viscosity regimes. Through a systematic work, in which the molecular weight and degree of hydrolysis as well as the permeability and brine salinity were varied, the apparent viscosity was well-matched with theoretical models. The following four viscosity regimes were identified: (i) At low shear rates, the apparent Newtonian viscosity is less than the bulk viscosity; this effect is because of the inaccessible pore volume (IPV) with the polymer not entering the entire pore space. (ii) Shear thinning behaviour which is controlled by the polymers relaxation time, λ1. (iii) At high shear rates, the apparent viscosity increases by increasing the shear rate caused by elongation whose onset is controlled by a critical shear rate which depends on the relaxation time. (iv) At very high shear rates, the apparent viscosity decreases by increasing the shear rate because of mechanical polymer degradation caused by polymer rupture.

The controlling parameter is the bulk relaxation time for the polymer. The critical shear rates for elongation and shear degradation increase when the effective molecular weight decreases. Typical injection shear rates in offshore matrix reservoirs exceed the critical shear rate for elongation and shear degradation. Consequently, high molecular weight HPAM will either have poor injectivity or cause fracturing. For injection into fractured wells, the shear rate is substantially reduced and the shear degradation can be avoided. Acrylamido-Propyl-Sulfonate (AMPS) co-polymers have similar apparent viscosity versus shear rate as the HPAM. However, the AMPS co-polymers seem to tolerate higher shear rates before degradation sets in.

For comparison, core flood experiments with Xanthan have been performed. This polymer was shear stable and the shear thinning apparent viscosity was similar to the bulk viscosity.

The polymers reduced the permeability and the permeability reduction is understood by the polymer size, i.e., the permeability reduction increases by increasing the molecular weight.
The Development of a Water-Free and Light Oil-Soluble Scale Squeeze Inhibitor Meeting Environmental Requirements
Authors: Guan Hua , Grinrod Anders , Rohde Hans C
Published: July 2010

The major technical drive for introducing oil-soluble scale inhibitors is to overcome the potential oil production decline caused by conventional aqueous-based scale-inhibitor squeeze packages in situations where relative permeability effects, water blocking, fluid lifting or deep penetration into the near well formation are of major concern. The particular requirement for a true oil-soluble scale inhibitor in a low-pressure reservoir with wells having lifting problems is that the package density needs to be lower than that of water. Additionally in certain geographical regions like Norway, the environmental regulations are very tight.

This paper illustrates the development of a true oil-soluble scale-inhibitor package with zero water content. The product is light with a density of much less than 1 g/cm3 and its environmental category in Norway is yellow. The successful product is the result of numerous formulation trials. Details of chemistry selection and the formulation development will be discussed in the paper. Following the success in formulation, the product has undergone stability, solubility and core flood testing to further evaluate its suitability as a squeeze inhibitor. The core flood results show an extended scale inhibitor return during the post flush; the scale inhibitor is still well above MIC (Minimal Inhibitor Concentration) for > 700 pore volume (PV) of post flush. The possible mechanism for this squeeze lifetime extension is discussed in the paper. No formation damage was observed during the reservoir condition multiphase core flood indicating the nondamaging nature of the true oil-soluble product. Based on this successful development, a field trial is planned.

This paper discloses the development of a true oil-soluble scale-inhibitor formula that is water free, low density and in the yellow environmental category, which can be applied downhole as scale squeeze inhibitor providing a prolonged squeeze lifetime.
Emergence of Diamond-like Carbon Technology: One Step Closer to OCTG Corrosion Prevention
Authors: Gore Mark J. , Boardman Bill
Published: July 2010

Careful consideration of corrosion management during component manufacture is critical to protect assets over their useful field life. Recently, a new technology was introduced that can delay or mitigate the onset of corrosion on oil country tubular goods (OCTG) used in oil and gas production operations. The innovative method produces and applies a layered diamond- like-carbon (DLC) to the internal surface of OCTG tubulars by using a plasma enhanced chemical vapor deposition (PECVD) process. The technique makes use of the hollow cathode effect (HCE) to achieve a high deposition rate and a high ion bombardment rate. Initially developed for the coating of internal surfaces of piping with length:diameter aspect ratios less than 20, the process has recently been extended to high aspect ratio piping including OCTG. Its ion bombardment produces a dense barrier of a hard, wear and corrosion resistant DLC surface coating. The improvement in deposition rate and increase in thickness compared to earlier plasma coatings has enabled new applications such as corrosion and abrasion protection. Corrosion resistance is demonstrated based on exposure to HCl and NaCl environments. Mechanical properties include high hardness, high adhesion, and good wear resistance.

The new technology enables a widespread use of DLC based coating and has significant potential to increase component life in applications where the internal surface of pipes are exposed to corrosive and abrasive environments especially in the oil and gas industry. The described surface treatment provides a new alternative to traditional polymer type coatings and/or increased alloy contents.
The Influence of Maleic Acid Co-polymers on the Growth and Microstructure of Calcite Scale
Authors: Senthilmurugan B. , Ghosh B. , Graham G. M. , Kundu S. S.
Published: July 2010

Additive-mediated crystal growth has been a large area of scientific research over many generations. In oil and gas production crystal growth modifiers (scale inhibitors) are used routinely, although their impact on the structure and morphology of the scale is often overlooked. This work presents results for the inhibition of calcite using specially prepared maleic acid – acrylic acid and maleic acid – acrylamide co-polymers. Performance tests show that the inhibitors provide effective performance against CaCO3 in both static and dynamic conditions. Additive-mediated crystallisation was then progressed at concentrations below the MIC’s. The results show significant changes in the microstructure and morphology of the crystals formed, from typical calcite rhombs in the absence of additives towards needles and aragonite structures as well the formation of almost perfectly formed "micro-rosettes". The trends in the microstructure are tracked as a function of temperature and chemical concentration and are related to the inhibitors ability to influence different crystal growth surfaces under different conditions. More significantly, dramatic differences are recorded under dynamic and static test conditions, indicating that the structures which lead to adherence and blocking of pipework during flow may be different than those which dominate under bulk conditions. The indication is that the most effective inhibitors are those which inhibit crystal morphologies which lend themselves towards adhesion and growth from metal surfaces.

The synthesis and characterisation of the polymers together with calcium carbonate inhibition performance results and crystal microstructures formed in static and dynamic conditions are presented, together with conclusions on their importance when attempting to inhibit scale formation on pipeline walls in dynamic oil production systems. Previous published works in this area will be included to support the conclusions made.
Proactive Well Placement Integrated into a Systematical Approach Enhances Productivity in a Complex Offshore Field, Bohai Bay
Authors: Deng Jian Ming , Liu Peng , Zhao Yong Sheng , Tan Lv , Li Gang , Yang Bin , Xian Cheng Gang , Wang Ruo , Parlindungan M. H.
Published: July 2010

Horizontal wells are being a common practice in offshore field development in Bohai Bay recently. Maintaining well trajectory in sweep spot while drilling is one of the key factors to optimize productivity of horizontal wells. To achieve this, great challenges are often faced in Bohai bay area including bias between the existing model and the actual, including microstructure and fluvial channels, sand-shale inter-bedding, strong permeability heterogeneities, complex special distribution of reservoir fluids (gas cap, bottom water or edge water) and relatively thin hydrocarbon pays. Therefore, the ability to update reservoir model in timely manner and to proactively adjust well trajectory in real time are required.

This paper presents a successful case in Bohai Bay by applying proactive well placement technology into an integrated approach to achieve very promising productivity than the initial prediction from two appraisal wells. This approach includes integrated reservoir study, operation optimization from drilling to completion, proactive well placement, real time interpretation, model updating and decision making. During integrated reservoir study, selected parameters and criteria to plan locations and trajectory of horizontal wells were derived from thorough rock physics and petrophysics studies. Detail geomechanical analysis was applied to optimize drilling and completion strategy. Proactive well placement technology - characterized by up to 15ft depth of investigation, directional measurements, 2D mapping of boundary/contact and 3D visualization was applied to optimize the placement of well trajectory in real time; which was also used to update reservoir model while drilling and close the gap between pre-drill existing model and real time interpretation. As the result, productions of the drilled two pilot horizontal wells are greatly exceeding the initial prediction. This proven approach can be applied to other planed wells in this field and other similar fields in Bohai Bay.
Measurement and Analytical Approach for Geological Core Investigation using Photogrammetic Methods
Authors: Sun Pinghe , Wu Xiaoming , Deng Mike
Published: July 2010

Formation micro imager is applied in geological investigation of borehole which can provid much more properties than core sample collection. In this paper, the photogrammetic method is discussed during the lab test based on images. Photogrammetric technology is the technique of measuring objects (2D or 3D) from images. During the test process, 35 printed target points are set on the plastic clay which is adhere to the simulation borehole surface and taking photos from different locations to get the points’ information. The software of PhotoModeler is used to analyse these photos with fixing the origin point, the direction of 3D coordinate and the distance between any 2 target points. All these points (x, y, z) are obtained in this test by focus length of 18mm, 35mm and 55mm. There are differences between the 3 focus lengths for the same point's x, y and z. The results show that the parameters of RMS (Root Mean Square) marking residual and tightness have negative effection on the precision. We can identify the physical properties of a borehole surface (borehole breakout, fracture, et al.) accurately by this technology to improve exploration and production results utilizing advanced borehole. It also can reduce coring and associated drilling costs (partial core replacement).
Investigation and Application of Multistage Hydrajet-Fracturing in Oil and Gas Well Stimulation in China
Authors: Li Gensheng , Huang Zhongwei , Tian Shouceng , Niu Jilei , Qu Hai , Sheng Mao
Published: July 2010

Multistage hydrajet-fracturing combines abrasive jet perforating and hydraulic fracturing to perform separate, sequential fracture stimulations without mechanical packers. It can reasonably place fractures according to geological condition, and then accurately treat them. Without packer, it uses dynamic isolation to seal flow into target, saving operating time and lowering operating risk. Therefore, the process not only adapts to stimulate open hole, but effectively treats liner or cased completions.

The mechanisms and fluid dynamics of multistage hydrajet-fracturing technology are investigated with numerical simulation and laboratory experiments. More than 30 oil and gas wells have been successfully treated using this technology since 2007. On average, three hydraulic fractures with total 120m3 proppants were placed at strategically selected locations in well, typically several hundred meters apart without sealing equipments. The deepest treatment in oil well 203-19 in Zhongyuan oilfield, using tubing string, was 3692m, and surface pressure reached 88MPa. Significant stimulation results were achieved in these wells. For example, production increased by more than 50 times after stimulation to the gas well XS311H in Sichuan oilfield. The oil well 92-2 in the Zhongyuan oilfield, which had been a dead horizontal well, has been revived using this technology with average oil production of 15 tons per day.

Multistage hydrajet-fracturing stimulation shows promising feature for horizontal, vertical, deviated, and even multilateral wells.
Transport Study of Nanoparticles for Oilfield Application
Authors: Yu Jie , Berlin Jacob M. , Lu Wei , Zhang Lunliang , Kan Amy T. , Zhang Ping , Walsh Erin E. , Work Sara N. , Chen Wei , Tour James M. , Wong Michael S. , Tomson Mason B.
Published: July 2010

Recently, the revolution of nanotechnology has been noticed for its many potential applications in the oil & gas industry such as enhanced oil recovery process and subsurface mapping. Understanding the transport and retention of nanoparticles (NPs) in an oilfield environment, such as high salinity, high temperature, high pressure, and heterogeneous pore distribution is critical to their application. The objective of this study is to investigate the fundamental transport and retention properties of NPs in the challenging oilfield conditions.

In this work, dolomite core material from an oil well in Kuwait and Berea sandstone were used. Carbon NPs were used as model nanomaterials. The core sample was washed with toluene to remove residual oil, ground to 106 – 250 µm grains, and packed into columns. Carbon NP breakthrough curves were collected in synthetic seawater at room temperature. The results showed that the existence of salt ions dramatically delayed NP breakthrough time and increased NP retention. Effects of different types of salts and salt concentrations are discussed. NP transport appears to be highly dependent on the degree of interaction between the NPs, salt ions in solution, and porous medium surface, which affects retardation and retention. NP breakthrough can be significantly improved by avoiding this interaction via NP surface modification. Our preliminary results provided helpful guidelines for NP transport in oil & gas applications. The results are discussed in detail. Furthermore, the experimental results were fitted with a 1-D advective and dispersion equation combined with a first-order removal term to obtain important transport parameters for NPs that did not aggregate. More complicated models are being developed to capture the unusual breakthrough curves associated with NP aggregation.