bluuebunny/crossref_metadata_2025 huggingface dataset:
Controlled Use of Downhole Calcium Carbonate Scaling for Sand Control: Laboratory and Field Results on Gullfaks
Authors: Fleming N.. , Berge E.. , Ridene M.. , Østvold T.. , Jøsang L.O.. O. , Rohde H.C.. C.
Published: April 2012

Gullfaks has been in production since 1986 and produces approximately 11 500 std m3/d of oil from three Condeep platforms. The average water cut is approximately 75 to 80% and gas/oil ratio (GOR) is approximately 200 std m3/std m3. It has been estimated that between 50 and 100 t of sand is produced yearly per platform, with approximately 60 to 70% of the wells in active production (approximately 90) limited by sand production. The typical well completion is cased hole with selective production through perforated liners. Rock-mechanics studies have shown that sand will be produced irrespective of well inclination and perforation design.

On Gullfaks, the sand-management strategy used has been to produce wells at "maximum" or "acceptable" sand rates. This strategy has led to significant gains in production, although there are challenges with this approach that include choke erosion, sand removal from the separators, and oil-in-water quality associated with discharge to sea. In response to this, Statoil has investigated different methods of retaining sand downhole by chemical sand consolidation, of which in-situ calcium carbonate (CaCO3) precipitation will form the basis for this paper. This technology involves squeezing into the near-wellbore formation predefined concentrations of urea and calcium nitrate along with the enzyme urease. After application, the well is shut in, during which the enzyme catalyzes the decomposition of urea to bicarbonate that reacts with calcium to form calcium carbonate.

This paper will provide details of the laboratory evaluation and, in particular, will focus on the field results from the first-ever application of this type. A low-risk candidate well was selected that had a short perforated interval (19 m) and produced 88 std m3/d oil with a water cut of 94%. Results of the operation design and planning, logistics examination, thorough risk evaluation, and post-operation results with lessons learned will be presented.
Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches
Authors: Garmeh R.. , Izadi M.. , Salehi M.. , Romero J.L.. L. , Thomas C.P.. P. , Manrique E.J.. J.
Published: April 2012

A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods.

This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed.

Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation.

The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.
Mechanics of Heavy-Oil and Bitumen Recovery by Hot Solvent Injection
Authors: Pathak V.. , Babadagli T.. , Edmunds N.R.. R.
Published: April 2012

In earlier work (Pathak et al. 2010, 2011), we presented the initial results for heavy-oil and bitumen recovery using heated solvent vapors. The heavy-oil- and bitumen-saturated sandpack samples of different heights were exposed to heated vapors of butane or propane at a constant temperature and pressure for an extended duration of time. The produced oil was analyzed for recovery, asphaltene content, viscosity, composition, and refractive index. Recovery was found to be very sensitive to temperature and pressure.

The current work was undertaken to better understand the physics of the process and to explain the observations of the earlier experiments using additional experiments on tighter samples of different sizes, numerical simulation, and visualization experiments. The effects of temperature and pressure on the recovery were studied using a commercial reservoir simulator. Propane and butane were used as solvents. Asphaltene precipitation was also modeled. A qualitative history match with the experiments on different porous-media types was achieved by mainly considering the permeability reduction caused by asphaltene precipitation; pore plugging; the extent of interaction between the solvent and oil phases; and parameters such as model height, vertical permeability, and gravity. The effect of asphaltene deposition on models of varying permeabilities was also studied.

To investigate the phenomenon further, visualization experiments were performed. 2D Hele-Shaw models of different dimensions were constructed by joining two Plexiglass sheets from three sides, or in some experiments, from all sides. The models were saturated with heavy oil and left open on one side (or all sides) and were exposed to different types of solvents. The setup was monitored continuously to observe fluid fronts and asphaltene precipitation.

By use of this analysis, the mechanics of the process was clarified from the effect of solvent type on the recovery process. The optimum operating temperature for the hot-solvent process and the dominant mechanisms were identified. The dynamics of the asphaltene deposition and its effect on oil recovery were clarified through visual and numerical models.
Experimental Evaluation of Well Perforation Methods as Applied to Hard Limestone
Authors: Lewelling Henry
Published: April 2012

An experimental investigation of the relative effectiveness of standard bullets and "shaped charges" in perforating dense, hard formations is reported. A method is described which simulates the conditions under which a shot is normally fired. Results are evaluated on the basis of depth of penetration, extent of fracturing, extent and nature of formation damage, and other physical characteristics.

Introduction

A study was made of the relative merits of bullets and "shaped charges" as applied to well completions in hard dense formations such as those encountered in the Permian Basin. The planning of the laboratory program stipulated that core samples should he prepared and mounted in such a way that perforation shots of either kind could be fired into them, keeping the factors pertinent to good shooting practice similar to what they would be in a well.

The shooting was done in a buried tank, with the sample and shooting equipment covered with water. The depth of water was calculated to be sufficient to simulate the inertial effects of well fluids for the duration of an explosion (a few micro-seconds).

Flow measurements were attempted on the specimens after perforation. Due to the lack of uniformity of the limestone, shale breaks, etc., these measurements proved to be of little value to the study. The mounting materials were removed, so that the character of the penetration, fracturing, etc., could be observed.

Method

Laboratory samples were selected from the hard, dolomitic sand cores from Block 31 Field. Core pieces having a 3% in. diameter and a useful length of 10 to 12 in. were used. Selection was aimed at those pieces having a minimum of shale streaks and other irregularities. The ends were cut off square with the diamond saw. Prior to being mounted, the cores were soaked in water to prevent them from absorbing water out of the wet concrete, thus weakening it.
Correlation of Radioactive Logs of the Lansing and Kansas City Groups in Central Kansas
Authors: Morgan John V.
Published: April 2012

Although the Lansing-Kansas City groups constitute one of the more important producing horizons of Central Kansas, exploitation has been hindered by inability to consistently identify and correlate the various productive intervals. A study of gamma ray-neutron logs and core data indicates that definite zones exist which are related to production and which may be generally correlated over an appreciable portion of Central Kansas. A suggested system of zoning and nomenclature is developed and illustrated, along with examples of its specific application in overall evaluation and in development of zonal production characteristics. General adoption of the suggested system should aid appreciably in the future development of commercial Lansing-Kansas City production in Central Kansas. It is probable that similar systems might be developed for other regions where production is obtained from various uncorrelated and unnamed zones in thick pay intervals.

Generalized Geology of Central Kansas

The most important large subsurface feature in Central Kansas regarding oil production is the Barton Arch, which is part of the Central Kansas uplift. The Barton Arch is a buried ridge of Pre-Cambrian granite running northwest-southeast, near which the majority of Central Kansas oil fields have been found. To the northeast of this arch, the granite dips sharply into the Salina Basin and similar basin areas to the west and south are termed the Hugoton Embayment and Anadarko Basin, respectively. This report deals primarily with the region of the Central Kansas Uplift and its southwestern flank. Fig. 1 indicates the general location of subsurface structural features along with the oil and gas fields of Central Kansas.

Above basal granite lies the Cambro-Ordovician Arbuckle Dolomite which is the principal oil producing zone in Central Kansas. This formation, as well as those higher in the section, reflects the general underlying granite structure; however, the Arbuckle top is an erosional surface and most oil producing structures are probably topographic hills.
Application of a Hybrid System of Genetic Algorithm & Fuzzy Logic as Optimization Techniques for Improving Oil Recovery in a Sandstone Reservoirs in Iraq
Authors: Al-Mudhafer Wathiq , Alabbas Maytham
Published: April 2012

An Interdisciplinary study for increasing oil recovery has been made in the present paper. This work has been adopted in the Upper Sandstone member/Zubair formation in South Rumaila Oil Field. The work was achieved by using optimization techniques for determining the optimal future reservoir performance regarding to infill drilling. Adaptive Genetic Algorithm (AGA) has been adopted in this paper to optimize the count and locations of infill wells. AGA uses Fuzzy Logic (FL) to determining optimal crossover rate, mutation rate and crossover form for each generation; in order to find accurate prediction. The main parameters depended in this study is the cumulative oil production obtained from the output of reservoir simulation software. This optimization tool depended on using the objective function of Net Present Value (NPV) as economic analysis. The optimal number of infill wells is three wells that have maximum cumulative oil production and maximum value of NPV. The locations of these optimal infill wells located in the crest of the oil field and far away from the east and west flanks because of the strong water drive from the infinite acting aquifer.
Pore Pressure Prediction in Carbonate Reservoirs
Authors: Atashbari V. , Tingay M.
Published: April 2012

Knowledge of pore fluid pressure is essential for safe drilling and efficient reservoir modelling. An accurate estimation of pore pressure allows for more efficient selection of casing points and a reliable mud weight design. Current commonly used methods of pore pressure prediction are based on the difference between a ‘normal trend’ in sonic wave velocity, formation resistivity factor (FRF), or d-exponent (a function of drilling parameters) and the observed value of these parameters in over-pressured zones. The majority of the techniques are based on shale behaviour, which typically exhibits a strong relationship between porosity and pore fluid pressure. However, carbonate rocks are stiffer and may contain over-pressures without any associated influence on porosity. Indeed, the application of common pore pressure prediction methods to carbonate rocks can yield large and potentially dangerous errors, even suggesting absences or decrease in abnormal pressure in zones of high magnitude over-pressure. In some cases, the hypothesises which been in the conventional methods seems to be flawed in some cases where pore pressure decreases by depth.

In this research, a new method for effective stress calculation has been obtained using the compressibility attribute of reservoir rocks. In the case of over-pressure generation by undercompaction (as occurs in most clastic over-pressured sequences), pore pressure is dependent on the changes in pore space, which is a function of rock and pore compressibility. In simple terms, pore space decreases while the formation under goes compaction, and this imposes pressure on the fluid which fills the pores. Carbonate reservoirs in two fields in Iran have been investigated to establish pore fluid pressure generation mechanisms, and to attempt new methods for pore pressure prediction in carbonate rocks.
Fiber Technology Simply and Effectively Cures Total Losses in Southern Mexico Without Knowing Size of Fractures
Authors: de Andrade Alexandre Victor , Diaz Lenin Omar , Bermudez Raul , Bedino Henry Daniel , Carrillo Nixklafe Neil , Vargas Candelario Delgado , Carrillo Angel Pedro , Martinez Ignacio Ramirez
Published: April 2012

Lost circulation is a major problem when drilling oil wells in Southern Mexico, where depths normally reach up to 7,000 meters with a fractured carbonate reservoir as the target. Very high mud losses reduces rate of penetration, increases cost of materials and induces other unwanted drilling events. Many times operators and service companies are forced to apply in-a-hurry lost circulation treatments mostly based on trial and error with very mediocre success.

A Fiber system has been developed to cure lost circulation caused by the presence of natural fractures. The fiber system is deployed either in a spacer ahead of cementing or by spotting a pill during drilling. This Fiber system disperses readily in water-base fluids and is fully compatible with standard surface mixing and pumping equipments.

This field study presents the application in Mexico of this innovative and resilient Fiber lost circulation system designed to mitigate the lack of characterization of the loss zone. Fourteen jobs performed and two applications described include pumping through commonly used BHAs during drilling, and as part of the spacer ahead of the cement slurry, when partial or total losses occurred with casing on bottom.

Implementation of this engineered fiber-based lost circulation solution was extremely successful compared to the average success of other similar purpose systems. Particularly, two features were considered a breakthrough in applications while drilling: first, this solution saved 15 to 24 hours of rig time per operation as the BHA needs not be pulled out; and a second, and perhaps more important advantage consisted in being able to resume drilling quickly after pumping the material without risking to destroy the integrity of the seal. When used in a spacer ahead of cement in wells, where circulation was lost after getting the casing to its landing depth, the Fiber lost circulation solution allowed to successfully getting top of cement at the planned desired depth ensuring effective zonal isolation.
Miscible Gas Injection and Asphaltene Flow Assurance Fluid Characterization: A Laboratory Case Study for a Black Oil Reservoir
Authors: Memon Afzal , Qassim Bashar , Al-Ajmi Moudi , Kumar Tharanivasan Asok , Gao Jinglin , Ratulowski John , Al-Otaibi Basel , Khan Rizwan Ahmed
Published: April 2012

Miscible gas flooding is the most commonly used enhanced oil recovery (EOR) method. One of the most important experimental parameters for miscible gas injection is minimum miscibility pressure (MMP). Many times, the MMP of a system can be very high. Instead of raising the pressure to achieve miscibility, injection gas may be enriched with intermediate components. The enrichment level at which the gas-oil system becomes miscible is called minimum miscibility enrichment (MME). Regardless of the values of MMP and MME, gas injected into a reservoir will most likely induce asphaltene precipitation, which may potentially cause formation damage and reduce flow in the production tubing.

In this paper, reservoir fluid from a Kuwait reservoir was analyzed to check for the feasibility of miscible gas injection. First, a series experiments were conducted to measure MMP with various gases using different techniques and MME testing with slimtube experiments. Moreover, the benefits, disadvantages, and applicability of each experimental method for EOR testing with gas injections were compared. Second, asphaltene precipitation upon gas injection was investigated in detail by measuring the precipitation onset conditions. Asphaltene precipitation onset was measured using a near infrared (NIR) light-scattering technique and a high-pressure microscope system to analyze the measured data. Finally, the asphaltene precipitation locus on a pressure-temperature (PT) diagram and the amount of precipitation were modeled for the reservoir fluid with different concentrations of injection gas. The modeling was carried out using a composition-based cubic equation-of-state approach. The experimental and modeling results indicated that an increase in concentration of injection gas appears to aggravate asphaltene precipitation.
Fracture Aging Evaluation in Tight Sands Using a Snubbing Unit
Authors: Irazuzta G. , Forni P. , Pons M. , Agüero Luis
Published: April 2012

One of the methods used to extend the production level and durability of low permeability gas wells is by conducting re-fractures. Although many case histories have been reported in the literature, limited information reporting the refracs long term performance is available. The reasons for this can be summarized as follows: –Any study conducted to test (Build Up) involves killing the well or at least controlling the production pressure. This condition generates changes in the production regime which generates certain uncertainties in the measurements precision.–The testing procedure may cause some type of formation damage that impedes recovering the original production regime.–Finally, if the well has a high production regime, long testing periods means losses in gas production.

This paper presents a study performed on a low permeability sandstone gas well located at the Neuquina basin, Argentina, were the performance of two fractured zones were evaluated by means of a Build up test conducted without killing the well. A snubbing unit was used to carry out several operations as removing the production installation, applying zonal isolation using plug and packer among other tasks.

Both zones under study had been stimulated three years before conducting the study using a CO2 foam fracture fluid. The operational sequence, stimulation treatments analysis and closure stress interpretation provided valuable information to understand the fractures aging response and to define and design re-fractures.
Improving Flow Assurance in Multi-Zone Fracturing Treatments in Hydrocarbon Reservoirs with High Strength Corrodible Tripping Balls
Authors: Carrejo N. , Welch J. , Solfronk M. , Johnson M. H.
Published: April 2012

Multi point hydraulic fracturing in unconventional hydrocarbon bearing shale reservoirs has been proven to greatly enhance production economics. A major component of these multi point fracturing systems consist of tripping balls used to actuate fracturing sleeves. The sleeves are used to focus fracturing initiation and placement. The tripping balls may experience pressures approaching 10,000psi. Recent technology has allowed as many as 40 individual fracture points. Once the formation has been fractured the tripping balls may hinder production. One potential problem is related to the tripping balls becoming stuck on the fracturing seats. Tripping balls remaining in the lateral can create a choking effect and also lead to problems if wellbore re-entry is required. These risks to production can lead to significant increased costs and potentially lost production. A new high strength corrodible material has been developed and used for tripping balls to alleviate these potential problems in these unconventional reservoirs. This material has yielded a truly intervention-less means of flow assurance. The mechanical properties and corrosion rates of these newly engineered materials have been investigated to determine the downhole performance. The characterization results of these materials will be discussed and compared to other materials currently used for tripping balls. The testing included investigation of the corrosion rates of these materials in brines and acids at various temperatures and pressures. Materials were also functionally tested on multiple ball seat configurations used in the multi-zone fracturing systems.
Quantification of Hydrocarbon Volume: An Example Using Rock Typing Methodology Applied in Cerro Negro Field, Eastern Venezuela Basin
Authors: Moya C. , Gunter G. W. , Mahadevan J. , Wolgemuth K. M.
Published: April 2012

For many years, geologists and engineers have used volumetric methods to quantify or estimate hydrocarbon volume contained in reservoirs. The economic producibility of the reservoirs, also depend on the flow characteristics. The overall level of uncertainty of the estimation depends on the uncertainty of the parameters that determine the oil volume such as porosity and the reservoir characteristics such as pay thickness. However, uncertainty of estimation increases when estimating hydrocarbon in place for complex fluids systems (i.e. heavy oil) since mobility can have an adverse effect on fluid movement. Determination of net pay cut-offs should be based on parameters that include flow and storage capacity.

Considering the requirement to establish a relationship between petrophysical cut-offs and rock types to estimate hydrocarbon in place, five different cases were used to quantify net pay parameters of the reservoir in the Cerro Negro field, Venezuela. The workflow that was applied: Identification of petrophysical rock types (PRT) from porosity and permeability data using core-based and log-derived petrophysical analysis,Definition of the relationship between PRT and faciesDetermination of pay cut-offs for reservoir and each PRT using conventional and contemporary methodologies,Comparison of the conventional and contemporary methodologies results,Estimation of pay cut-offs impact on the prediction of rock types and reservoir petrophysical properties in the estimation of volumetric.

This study demonstrates that the definition of PRT distribution is controlled by pore throat size instead of facies. From the six rock types defined in the field just three rock types (1, 2, and 3) are oil producing rock reservoir. The OOIP results vary significantly over a range of 500 MMstb, depending on which of the parameters are used as pay cut-offs.

In conclusion, estimating OOIP by applying petrophysical rock typing is an improved way to decrease uncertainty than OOIP estimation by reservoir unit. The results demonstrated that the choice of good pay cut-offs was the key to reduce the uncertainty in the estimation of the OOIP in the Cerro Negro field.
Supercritical CO2 Interaction with Montmorillonite Clay
Authors: AlOtaibi Fawaz M. , AlKhaldi Mohammed H. , Funk Jim J. , Shen Shouwen X. , AlQahtani Jassi F.
Published: April 2012

Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated.

The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR).

Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca-montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d-spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
Water Conservation: Reducing Freshwater Consumption by Using Produced Water for Base Fluid in Hydraulic Fracturing–Case Histories in Argentina
Authors: Bonapace J. , Giglio M. , Moggia J. , Krenz A.
Published: April 2012

In the Golfo San Jorge basin (GSJB), in the area of Cerro Dragón, a sustained increase of activity has developed over the past ten years. Further development of the field has been achieved with well stimulations (hydraulic-fracturing treatments), increasing production rates.

This has resulted in increased water consumption for these operations. In an effort to ration water sources, well owners must find alternatives to reduce the volume of fresh water consumed.

Throughout the past five years, one operator has worked to use produced water, or low-quality injection water, as a source of water for stimulation applications. The methodology applied consisted of Identifying different types of water produced in the fieldPerforming tests on the waters (physical-chemical and bacteriological)Performing tests with commonly used fracturing fluids to identify good performanceConducting tests during field operationsEstablishing procedures for water injection from the results obtainedContinuous monitoring, as well as the introduction of new techniques and improvements

The results that were obtained demonstrate how the operations performed have gradually increased by using this methodology (412 of 760 fracturing treatments during 2010). In addition, the reduction in freshwater use was 54.8% of the total amount in 2010 (5.7 of 10.5 million gal).

This work has helped identify sources of produced water in the field that are acceptable for use in fracturing stimulation operations. A procedure has been established to help ensure a reliable fracturing fluid with good performance is always used in these operations. Additionally, new techniques and equipment have been incorporated that contribute to continuous improvements to the process.
Studies On Nitrogen Foam Flooding For Conglomerate Reservoir
Authors: Hou Qingfeng , Zhu Youyi , Luo Yousong , Weng Rui , Guoqing Jian
Published: April 2012

Keshang formation in Karamay oil field belongs to typical conglomerate reservoirs. It is characterized by high water cut, poor sweep efficiency, high heterogeneity and inefficient oil recovery during the end-period of water flooding. The selection of EOR technique is very important for future development of such reservoirs. Foam flooding can improve macroscopic sweep efficiency, which may increase oil recovery for highly heterogeneous reservoirs particularly. In this study, systematic laboratory studies on foam flooding for Keshang formation have been performed.

Both the foamability and stability are the key factors to ensure high incremental oil recovery. The nitrogen foam formulas were optimized which had good performance of foamability and stability. The operating parameters including foam injection modes and gas liquid ratio were investigated by core flooding experiments at reservoir conditions.

The results show that: 1. Injection mode is an important factor and the direct injection of foam is better than co-injection of gas and solution obviously. 2. The gas liquid ratio is another important parameter. The optimized gas liquid ratio was proposed as 3:1-5:1 for direct injection mode. EOR effect evaluation indicated that foam flooding could contribute 40.00% OOIP recovery even if the recovery after water flooding was 41.50% under good operating protocols. The remarkable increasing of injection pressure during the foam flooding indicated that nitrogen foam flooding had excellent profile control ability.

Foam flooding integrates both properties of gas injection technique and chemical flooding. It is a candidate EOR method for highly heterogeneous conglomerate reservoirs.
A Framework for Consolidating Air Injection Experimental Data
Authors: Rodriguez E. , Ordoñez A. , Comas J. , Trujillo M. , Belgrave J. D.
Published: April 2012

Accelerating-Rate Calorimeter (ARC), Ramped-Temperature-Oxidation (RTO), and Combustion Tube (CT) tests are used for screening and designing air injection processes for enhanced oil recovery. These tests use different size samples of reservoir materials, operating under different conditions, have different interpretation requirements, and yield different types of information.

ARC data have been used to provide rapid screening of the suitability of (especially) high pressure light oil reservoirs for air injection. Small reservoir samples are used, air injection displacement efficiency is not captured, but they provide explicit quantitative oxidation rate information. RTO experiments use larger quantities of core and reservoir fluids and allow some fluid displacement and production. Due to the nature of this type of test, a much larger fraction of the oil is consumed compared to field application, and oxidation data over a broad range of temperatures is implicitly provided. Finally, combustion tube tests provide the closest dynamic analog to actual reservoir conditions and have the largest core and fluid requirement.

This paper describes a systematic procedure used to consolidate the data from these tests into a robust kinetic model for the design and implementation of air injection processes in heavy oil mature fields. The model considers both low and high temperature oxidation reactions, thermal cracking, and the compositional changes that the oil undergoes. Application of the model at the field scale shows temperature levels, produced gas compositions, and fuel and air requirements comparable with those derived from the combustion tube tests.
Fluid Analysis and Sampling: The Next Big Step for Logging While Drilling Tools
Authors: Sanchez F. Galvan , Cartellieri A. , Pragt J. , Meister M.
Published: April 2012

The first formation testing tools were introduced as wireline tools in the 1950s. Since then, many technological steps were achieved, starting with simple sampling devices adding different measurement technologies in the 1980s up to formation pressure while drilling (FPWD) tools introduced to the field in 2000. Over the last 20 years wireline technology evolved towards high-quality single-phase sampling that also led to the development of the first formation sampling while drilling (FSWD) tools being introduced just over a year ago.

In this paper we present a new fluid analysis and sampling tool designed for logging while drilling (LWD) applications. As it is built on the widely proven FPWD technology, it includes all its functionality of optimized testing and seal control.

This service operates using a closed-loop control system, integrates real-time downhole analysis of the pressure data, and provides a repeat pressure test with an optimized rate control based on the in-situ derived mobility. This is made possible by the highly accurate pump control system employed. In addition to pressure and mobility capabilities the fluid analysis and sampling tool can analyze and obtain formation fluid samples. The new tool is equipped with high-power pump-out capabilities and highly sophisticated sensors to measure the optical refractive index, the sound speed, the density and the viscosity of the fluid. The innovative pump control prevents alteration of the fluid sample by avoiding pumping below the bubble point.

The tool employs the same sample tanks that are used in our wireline tools. The tanks are approved by the Department of Transportation (DOT) for direct transportation of a sample to a certified pressure-volume-temperature (PVT) lab without transferring the sample into another sample bottle. The tool can collect and preserve up to 16 single-phase samples at surface pressures up to 20,000 psi in a single run. It uses a nitrogen buffer system to ensure the suffienct pressure is applied to the sample to prevent alteration.

In this paper the capabilities of this new LWD fluid analysis and sampling tool and its first field application on a land rig in Oklahoma are be shown. The field results are compared with a wireline results run to prove the concept of shorter clean-up times while sampling soon after the formation is penetrated by the drill bit. An outlook will be given how to apply this new technology in future applications.
Successful Deployment of a New Generation of Progressive Cavity Pump in a High GOR Argentinian Heavy Oil Field
Authors: Zimmer L. , Young E. , Bertomeu F.
Published: April 2012

Following the study of Progressive Cavity Pump Technology's behavior in Multiphase conditions (SPE Paper 95272 -presented at the SPE ATCE 2005 in Dallas, TX, USA) and the subsequent development of the "New PCP" (SPE Paper 97833 - presented at the SPE ITOHOS 2005 in Calgary, AB, Canada), this paper presents an overview of a pilot project where the Hydraulic Regulated Progressive Cavity Pump (HR-PCP - new name of the technology) was deployed in an Argentinean Heavy Oilfield.

Application

Deployment of the HR-PCP Technology in a gassy heavy oil field with recurrent Artificial Lift System failures. Average GOR usually recorded around 600 m3/m3 with presence of CO2.

Conversions of 6 wells from conventional PCPs, Sucker Rod Pumps and natural flow to HR-PCP.

Results observations & Conclusions

The implementation of the first version of the HR-PCP technology led to mixed results. A second version was then deployed and led to successful results in terms of production, run life and overall operational costs.

The HR-PCP not only was able to provide a solution to the reliability issues. It proved to be able to handle extreme Gas Void Fraction values and reduce per well power consumption.

Key to the success of this pilot project was the interest brought by all companies involved (operator, manufacturer and distributor) creating a valuable teamwork in order to share point of views, data and field operation practices.

Further testing will determine if the HR-PCP will allow optimizing the field production by maximizing the drawdown.

Significance of Subject Matter

The HR-PCP technology is meant to better handle gas than the conventional PCP Systems, enabling not only to operate at higher GVF (up to 99% compared to usual maximum of 30 to 40%), but for a much longer time and with no need of downhole gas separation technology.

The HR-PCP Technology targets include re-activation of wells considered uneconomic in mature fields, conversion of inefficient gas lift systems, increase run life in ageing or naturally gassy oil wells, increase reliability of artificial lift systems in gas well dewatering as well as allowing production from complex heavy/waxy/gassy oil wells, eliminating the need for gas anchors/separators.
An Integrated Case Study of Improve Oil Pay Evaluation in Shaly, Laminated, Low Mobility Reservoirs Using Wireline Cased Hole Dual Packer and Production Test
Authors: Mas C. , Yaxley L. , Ardila M. , Ayan C. , Tanuwidjaja V. Indrayanti
Published: April 2012

The subject of the case study is a recently discovered oil and gas accumulation characterized by laminated, shaly sandstones with high apparent water saturation. Conventional openhole log data was inconclusive in identifying hydrocarbon type and net hydrocarbon pay zones. Moreover, reservoir complexity, low mobility, and inadequate differentiation of oil versus gas pay made it unlikely that a conventional production testing program would be successful and cost effective. However, reservoir fluid identification and pressure measurements were critical for resolving key uncertainties and guiding decision making for future appraisal and development.

Cased-hole wireline formation testing was used to better determine reservoir fluid type and productivity in selected intervals so as to differentiate oil pay from gas pay and net pay limits. A total of 30 dual packer stations were conducted in cased hole. The test results were used to choose the intervals, methodology, and equipment for subsequent production tests, which successfully proved the existence of three separate oil reservoirs and demonstrated commercial production rates.
Wettability Modifier Field Trial in a Sandstone Condensate System: Facts and Gaps of a Promising Technology
Authors: Restrepo A. , Ocampo A. , Arenas M. , Rendon N. , Osorio R. , Reyes D.
Published: April 2012

Deliverability of gas and liquid hydrocarbons in retrograde condensate systems is highly affected by factors related to both reservoir characteristics and operative variables. It is well documented that pressure depletion coupled with tight petrophysical environments can lead to severe PI decrease due to liquid accumulation initially in the near wellbore area and then in the whole reservoir. Conventional approaches for condensate blockage removal have included the injection of low interfacial tension systems and alcohol blends to promote capillary forces minimization up to levels at which liquid bank gets remobilized. This type of solutions though, can be durability limited as liquid will reform once chemicals leave treated area. This condition become even more critical when static reservoir pressure gets below dew point as liquids from non treated zone will rapidly imbibe into the treated zone decreasing durability even further.

The present work documents a field trial of a fluoro polymer technology aimed on Kro and Krg enhancement by rock wettability modification. This technique, as opposed to conventional chemistries working at the fluid-fluid interaction level, is aimed on altering rock's original wettability. The objective is to promote a neutral wettability condition to minimize capillary effects driven by the contact angle according to LaPlace equation (fig 1).

Through a "facts and gaps analysis", a set of root causes are presented to explain the high PI improvement (–50%) but limited durability observed at field scale. Uncertainties on original rock wettability condition, water saturation profile in the near wellbore, deployment technique effectiveness and chemical properties of size and adsorption are all included in the root cause analysis. Data from pre job coreflood tests, pumping variables behavior and backflowed samples chemical analysis are also incorporated to the exercise. A final set of recommendations derived from the f&g analysis are to be included in further trials of the wettability modification technology where heterogeneous sandstone, compositional condensate environments are present.
An Innovative Solution to Optimizing Production in Naturally Fractured Carbonate Reservoirs in Southern Mexico
Authors: Quevedo M. , Tellez F. , Resendiz T. , Bueno O. Jimenez , Ramirez G.
Published: April 2012

The results of stimulation treatments in southern Mexico's carbonate reservoirs have been significantly improved using a new fiber-assisted, self-diverting acid system. These reservoirs are thick, deep, and hot. Depths are usually greater than 15,000 feet, bottomhole temperatures reach up to 350°F, and permeabilities range from 1 to 1000 mD within the same interval. Wells are typically completed with multiple perforated intervals. In the past, high-viscosity diverting fluids have been used to improve zonal coverage during stimulation treatments. Despite repeated treatments during the life of the well, in many cases, post-treatment logs show that the treatment was not effectively diverted to lower permeability, less productive intervals. To overcome these challenges, we introduced an innovative degradable diverting acid system combining the properties of viscoelastic diverting acid (solid-free) and degradable fibers to southern Mexico. This, combined with a rigorous candidate selection process, resulted in improved zonal coverage, increased oil production, and higher ultimate reserve recovery.

Maximizing oil production using this diverter system requires a detailed understanding of the petrophysical properties of the reservoir and production history. This information helps determine treatment volumes and the volume and number of diverter stages. Wells with the highest permeability contrast are often the best candidates. In many cases, producing from natural fractures depends on correctly determining the number and volume of the diverter stages. The experienced gained from treating more than 10 wells has resulted in the development of clear guidelines with respect to the treating fluid, volume, and number of diverter stages. On average, the guidelines have resulted production increases of 1,500 BOPD. By applying the treatment guidelines with an effective diverter fluid, operators can significantly increase oil and gas production in previously stimulated or new wells within naturally fractured carbonate reservoirs.
Minimum Flowrate to Unload Gas Wells: Dynamic Multiphase Modeling to Validate Existing Correlations
Authors: Daas M. , Golczynski T. , Harry J.
Published: April 2012

The Turner model is widely used in industry to estimate critical gas velocity to flow a gas well and unload its liquid content under steady state conditions. The Zhou model introduced improvements to the Turner model by taking into account the influence of total Liquid (condensate and water) to Gas Ratio (LGR) on critical gas velocity. While fairly acceptable at low LGR, current models do not address the impact of liquid holdup on wellhead flowing conditions and subsequent changes in critical gas unloading rates. Multiphase modeling is used in this study to validate the applicability of current models at various wellbore conditions and LGR.

This study finds important applications in offshore and onshore gas field developments because it provides moe reliable assessment especially for gas fields in the depletion phase, or when liquid breakthrough occurs resulting in high LGR.

Dynamic simulations indicate that at low to moderate LGR existing models under predict critical gas flowrate because they under estimate critical velocity, especially at high wellhead pressures, and don't take into account the impact of increasing liquid holdup on gas flowrate. Moreover, an inversion in critical flowrate occurs at very high LGR because the film holdup is sufficient to restrict the flow of gas and offsets any increase in critical velocity at such high LGR. The onset of liquid loading (well choking) is associated with the transition from annular to churn/slug flow. This is well demonstrated from the calculated trends of entrained droplet holdup.

The significance of the current work to our understanding of critical flow in gas wells is illustrated by utilizing a multiphase simulator to better characterize the impact of entrained droplet and film holdup on critical flowrate and by predicting the inversion in critical gas flowrate at high LGR. The results of this study provide an enhanced understanding of well loading during all development phases and various production conditions to evaluate the applicability and accuracy of widely used models in a broad range of well conditions and liquid loads.
Production Forecasting for Shale Gas Exploration Prospects Based on Statistical Analysis and Reservoir Simulation
Authors: Morales-German G. , Navarro-Rosales R. , Dubost F. Xavier
Published: April 2012

Shale gas exploration and production is still in its infancy. Information is scarce and flow monitoring is usually absent, but many studies aiming to understand gas shale reservoir behavior and to optimize its exploitation are now being developed. However, the understanding of fluid flow and transportation mechanisms in shales, given their micropore particular matrix structure coupled to induced fractures, is still under debate.

Several shale gas exploration projects are currently underway in diverse regions of Europe and Africa. The current lack of understanding of the main elements controlling well productivity, and the limitations of the available tools to correctly characterize the reservoir and forecast production from this type of well, make it difficult to predict the likely commercial value of a project. This value is controlled by drilling costs and the associated number of wells to develop a play, and the production returns that each of these wells may deliver.

The purpose of the work presented in this paper was to generate, based on statistical analysis of major shale gas basins in the USA, a synthetic reservoir simulation model that can represent shale gas wells and be used for forecasting purposes in exploration areas with limited available information. Such a prediction is mainly based on the accurate identification of parameters that have the greatest impact on production, either reservoir parameters or operational/controlled parameters, so that the production profiles may be predicted and controlled parameters optimized.