bluuebunny/crossref_metadata_2025 huggingface dataset:
How to Obstruct Divistiture of Clean Properties
Authors: Holliday George
Published: December 2007

Obtaining funding for the purchase of existing facilities can be daunting, particularly, if the seller has not maintained adequate records. This paper presents a troubled case history of the transfer of assets, where the seller did not conduct adequate due diligence during the previous transfer and could not satisfy the prospective buyer's lender request for proof of previous disposal of solid waste. In addition, the paper offers recommendations for avoiding data acquisition problem.

Small operators must obtain financing for the acquisition of existing facilities to enhance their market share. With the strenuous environmental regulations existing in the United States, lenders are reluctant to provide funds unless the purchaser/seller can provide proof of a clean facility and environmental compliance with existing regulations. No proof of a clean facility and compliance, no funds are made available!

Most technical papers considering acquisitions concentrate on evaluating oil and gas reserves payout or property value. These issues are important, but even with the best economic situation; a lender is hesitant to loan funds for a purchase having an environmental "cloud" or non-compliance issues.

The recommendations contained in this paper are based on an actual acquisition almost stopped in its tracks by a Resource Conservation and Recovery Act question.
Improved MMP Correlations for CO2 Floods Using Analytical Gas Flooding Theory
Authors: Yuan H. , Johns R. T. , Egwuenu A. M. , Dindoruk B.
Published: December 2007

Local displacement efficiency from CO2 gas injection is highly dependent on the minimum miscibility pressure (MMP). Correlations are often used to estimate the MMP where the injected fluid may or may not contain impurities such as methane. These correlations, however, are based on a limited set of experimental data and as such are not widely applicable. They also do not accurately account for the more complex condensing/vaporizing displacement process.

This paper presents new MMP correlations for the displacement of multicomponent oil by CO2 and impure CO2. The approach is to use recently developed analytical theory for MMP calculations from equations-of-state (EOS) to generate MMP correlations for displacements by pure and impure CO2.1–8 The advantage of this approach is that MMPs for a wide range of temperatures and reservoir fluids can be calculated quickly and accurately without introducing uncertainties associated with slim-tube MMPs and other numerical methods. The improved MMP correlation is based solely on the reservoir temperature, molecular weight of C7+, and percentage of intermediates (C2 − C6) in the oil. The MMPs from the improved correlation are compared to currently used correlations and 41 experimentally measured MMPs. Correlations are also developed for impure CO2 floods, where the injection stream may contain up to 40% methane. The new correlations are significantly more accurate and applicable than currently used correlations.
Lean gas injection into an extra light oil reservoir-Initial results and further steps
Authors: Palásthy Gy. , Benedek L. , Pipicz V. , Lövei A. , Papp I.
Published: December 2007

The Tisza-1 reservoir is situated at the top of the SE part of Algyo field, Hungary. The 1700 m depth reservoir has been developed in the uppermost sandstone series showing good reservoir quality. The well sortiered, middle and coarse grain sandstone contains extra light crude: the reservoir volume factor is near 4,0 res.bbl/bbl and the oil quality is 63 API. The extreme characteristics of the reservoir oil mean that the intermediate content is above 34 mol%. The production started as early as 1986. The 17 year exploitation history has proved, the strong bottom water drive as primary driving mechanism. By the end of 2002 a 45% of oil recovery was reached and the reservoir pressure drop was 8.3 bars with average water cut of about 23%. Control logs have indicated that about 35% of the net pay pore volume has been unaffected by the bottom water. The main aim of the reservoir management was to increase the recovery of mid-components and to sweep the oil from the upper zones by using dry gases. A 3D, compositional simulation model was developed to evaluate the potential of the gas injection. The static model has been up-scaled to flow units corresponding to the interconnected reservoir rock bodies of identical depositional environment. Comparing the production forecast cases the gas injection showed an additional 11% of mid-component recovery. During the modeling different gases were investigated to use. The economical evaluation was highly affected by the developed gas market environment but finally the lean gas was chosen for injection purpose. The gas injection project started in 2000 after a 4 year planning and preparation. This case study summarizes the planning, preparation of the gas injection project, highlights the dilemmas of the economics and shows the latest results of the process.
Effect of Composition of a Polyacrylamide-Chromium(III) Acetate Gel on the Magnitude of Gel Dehydration and Disproportionate Permeability Reduction
Authors: Nguyen T. Q. , Green D. W. , Willhite G. P. , McCool C. S.
Published: December 2007

For some polymer gels applied in reservoirs to control water flow, a favorable disproportionate permeability reduction (DPR) occurs in which permeability to water is reduced to a much greater extent than to oil. Also, when the gels are subjected to an applied pressure gradient partial dehydration can occur, i.e., some solvent is forced out of the gel structure. In this study of a partially hydrolyzed polyacrylamide crosslinked with chromium acetate, the magnitudes of DPR and gel dehydration volumes were measured as a function of gel composition and the pressure gradients imposed on the gels following placement in unconsolidated sandpacks. For the range of parameters studied, the reduction of permeability to water and oil and the DPR were strong functions of gel composition and applied pressure gradients, although gel dehydration volumes varied by only a small amount.
Phosphonic Acid Complex for Stimulating HF-Sensitive Reservoirs – A Revolutionary Response
Authors: Nwoke Linus , Uchendu Chike , Arukhe James , Essel Philippe , Ndinemenu Felix , Vecchio Alessandra , Fatusin Sylvester
Published: December 2007

HF-sensitive reservoirs that could not be hydraulically fractured nor effectively stimulated have been a challenge to the Petroleum Industry, hence locking the potential reserves that could otherwise be producible. These formations are typically those with high swelling clays, chlorite clays, feldspars and certain zeolites. Experience shows that even when such formations are stimulated with conventional HF- or HCl-based acid systems, the production performance declines shortly after the treatments, causing the reservoirs to produce at less-than-optimum rates. The skin damage associated with such reservoirs and stimulation by-products act as down-hole chokes, strangling production and increase drawdown.

Successful stimulation of these kinds of HF-sensitive reservoirs had been carried out with a Organo-Phosphonic Acid Complex. Treatments have been carried out in seven Oil Producers, Water Injectors and Gas Injection wells in the Niger-Delta Nigeria and an oil producer in South East Asia. Post-treatment rates were above 800% of the pre-treatment values and more than 100% the maximum potentials ever recorded by most of these wells since they were commissioned. The new acid system offered true stimulation of carbonate and sandstone reservoirs as well as restoration to natural permeabilities of these intervals by the process of sequestration and complexation. An overall dramatic response of more than 200% over the wells treated with other formulations in the same basin was achieved.

This paper discusses the non-HF based Organo-phosphonic acid formulations for Oil Producers, Gas Producers, Water Injectors and Gas Injection wells in both carbonate and sandstone reservoirs. The process of dissolution of the acid soluble and insoluble minerals that plug the near-wellbore region; candidate selection criteria; design; process of scale inhibition; field applications; results; treatment effectiveness and evaluations. The performance over other formulations is compared with respect to treatment costs, accelerated production, payback time, sustained production or Injectivity after treatment and percentage of original permeabilities being restored.
Capillary Number in Heavy Oil Solution Gas Drive and Its Relationship with Gas-Oil Relative Permeability Curves
Authors: Ostos A. , Maini B.
Published: December 2007

Many heavy oil reservoirs under solution gas drive show a significant increase in productivity. Different mechanisms have been postulated to explain the high recovery factors observed in the field. Lately, a widely accepted cause of this increase in productivity is the foamy oil flow, which dramatically decreases the gas relative permeability. However, it still remains inadequately understood.

It has been reported that the foamy flow effects observed in the laboratory depletion tests are strongly affected by depletion rate. This observed rate effect has been attributed to the influence of the pressure depletion rate on bubble nucleation. However, the researchers have mostly overlooked the capillary number, which increases significantly with increasing depletion rate. The goal of this study was to examine this capillary number effect in heavy oil reservoirs and its relationship with gas-oil relative permeability curves.

A number of experiments were carried out on a two-meter long sand-pack to determine the conditions required to produced more oil under solution gas drive. The experimental data were matched on a commercial black oil simulator to determine the relative permeability curve under varying flow conditions and at different capillary number. The experimental results show that the oil produced was a unique function of capillary number and beyond a critical capillary number no additional improvement in the recovery factor was observed. An examination of the changes of capillary number during the test provides insight into the gas-phase build up during solution gas drive and the resulting production behavior. It was also found that oil relative permeability increases and gas relative permeability decreases with increasing capillary number. At high capillary number, relative permeability ratio remains very low up to higher value of gas saturation. The results from this research suggest that the conventional correlations of gas-oil relative permeability should incorporate the effect of capillary number in order to improve the prediction of foamy oil flow mechanism.
Comparison of Non-Darcy Flow of CO2 and N2 in a Carbonate Rock
Authors: Grigg Reid B. , Zeng Zhengwen , Bethapudi Laxman V.
Published: December 2007

This work presents the non-Darcy behavior results of carbon dioxide (CO2) compared to the previous work using nitrogen (N2) and is based on 85 series of high-velocity gas flooding experiments under high-pressure and high-temperature. It was found that pore pressure has more influence on permeability in CO2 flooding than that in N2 flooding. In contrast, temperature has definite and consistent influence on both permeability and non-Darcy flow coefficient in N2 flooding, but the same influence in CO2 flooding was not observed. Mechanism behind these differences is attributed to physical property differences of the two gases. Much of the work was near the CO2 critical point or liquid regions. Other anomalies are attributed to thermal effects caused by expansion cooling of the CO2. Field data indicates that this phenomenon could be responsible for productivity loses in high flow rate CO2 wells. Accordingly, attention should be paid to avoid flowing CO2 at conditions near its critical point.
Underbalanced Techniques to Reduce Drilling Hazards of Loss of Circulation and Underground Flows
Authors: Abel L. William , Yarim Gokhan
Published: December 2007

This paper discusses underbalanced drilling planning, implementation and risk management to solve a drilling hazard where a weak upper formation is open to a lower high pressure gas reservoir that has pore pressure greater than the frac gradient of the weak formation. The problem has been solved in the Burgos Basin where loss of circulation and underground blowouts are a major hazard for drilling operations. The paper presents the planning process, risk assessment/HAZOP analysis, computer modeling with a steady state 2-phase flow model, equipment specifications, operational guidelines and field results from an underbalanced operation undertaken in August 2003 to successfully drill a well where there was a continual inflow while a weak lost circulation zone was exposed.
Re-enterable Through-Tubing Gravel-Pack System
Authors: Leising L. J. , Ali A. M. , Young J. R. , Arciniegas O. E.
Published: December 2007

The use of through-tubing gravel packs (TTGPs) has been limited in the past to low-flow-rate systems that are not suitable for frac packing or vent-screen systems that use a long annular pack of sand for pressure isolation. Vent-screen installations are increasing rapidly—in both new completions and for remedial work—because of the ability to develop longer fractures and increase permeability with high-rate frac packs. Unfortunately, vent screens have a high rate of failure because of the lack of positive pressure isolation.

This paper presents a new re-enterable-screen method that allows a high-rate frac pack with positive pressure isolation either through an inflatable packer or packoff to the tubing.
Transient Simulator-Based Training of Rig-Site Decision Makers and Rig Crews for Through-Tubing Coiled Tubing Underbalanced Multilateral Project
Authors: Frink P. J. , Leslie C. , Wooten J. E.
Published: December 2007

Introduction

The Sajaa Gas field, producing from the Thamama carbonate formation, is a prolific and important gas producing field for BP-Sharjah and its partners in Sharjah, United Arab Emirates.1

In December 2002, BP-Sharjah decided to embark on a through tubing coiled tubing UBD campaign to drill underbalanced, horizontal multilateral sidetracks to increase wellbore deliverability in this low pressure environment.2

Due to the probability of cross-flow between multilateral legs due to variations in reservoir pressure and the existence of high intensity fractures, maintaining dynamic pressure control presented a significant technical challenge. Safely detecting and responding to rapid changes in a complex well geometry with a very small volume well annulus was of paramount importance. Adequate crew training and effective communication between rigsite decision-makers was considered to be essential success pre-requisites for conducting safe operations.
Hard Scale Mechanical Removal: A Solution for Brazilian Offshore Operations
Authors: Quiroga M. H. V. , Calmeto J. C. N. , Pinto S. L. , Assis C. A. S. , Santos I.
Published: December 2007

Scale deposition in producing well bores is becoming a serious problem to the oil industry. In situations of injected seawater breakthrough, the problem is especially hard, since the growth is often Barium or Strontium Sulfate, both of which almost completely insoluble.

The initial scale growth will change the surface roughness in the production tubing, raising the frictional pressure drop and reducing the production rate. Further growth will decrease the flowing area and hinder the production. Ultimately the scale can restrict the production tubing sufficiently to prevent access for tools into the lower sections of the well and finally it can bridge over completely.

The range of options for scale removal goes from a simple brush run using slick line or basic chemical treatment up to a full rig workover to replace the production string. Very often through-tubing treatments using coiled tubing are used due to the savings compared to the rig cost. This technology can convey tools for mechanical scale removal and also works as a fluid conduit for chemical treatments.

The objective of this paper is to describe the coiled tubing abrasive jet technology used to successfully clean, for the first time, heavy affected Barium Sulfate scale in production tubing in Brazilian offshore operations and its impact on the well economics.
Optimizing Integrated Rigless Plug and Abandonment – A 60 Well Case Study
Authors: Tettero Frans , Barclay Ian , Staal Timo
Published: December 2007

This paper presents the Petroleum Development of Oman (PDO) Rigless plug and abandonment (P&A) methodology, technologies & practices which resulted from the corporate goal to find a cost effective means to P&A obsolete oil wells. As the main Omani Oil Exploration & Development company, PDO is abandoning aging wells and fields and they must balance environmental and financial objectives. Technically sound abandonment practices are essential for long-term environmental protection. Many operators are revising their P&A procedures to ensure that abandoned reservoirs remain permanently sealed. During this 60 well pilot project PDO optimized their P&A practices by employing a rigless methodology as well as new technologies to minimize the cost of abandonment while still ensuring long term environmental protection from once prolific oil wells. Using a Coiled Tubing unit and eliminating the need for a rig can help speed up operations and reduce costs, while at the same time safeguarding environmental concerns. Typical savings of 30% over previous abandonment campaigns with a drilling rig have been achieved by PDO. This constituted a total saving of over $5M for this 60 well campaign.
Managed Pressure Drilling with the ECD Reduction Tool
Authors: Bern P. A. , Armagost W. K. , Bansal R. K.
Published: December 2007

High equivalent circulation density (ECD) is responsible for many wellbore pressure-related problems during drilling. Proper wellbore pressure management is a critical part of normal drilling practices, where static and dynamic fluid pressures are used to contain formation pressures and assure wellbore stability. Excessive fluid pressure while circulating can create problems including reduced operating margins between fracture and pore pressures and, in the extreme, lost circulation. To address these problems, an ECD Reduction Tool (ECD RT) is being developed.

The ECD RT is designed to counter downhole pressure increase due to friction in the annulus by reducing the hydrostatic head. The tool is expected to have a broad range of drilling applications including the narrow pore/fracture pressure margin in the deepwater environment, wellbores prone to instability, pressure depleted reservoirs and extended reach wells. The ECD RT will also potentially reduce the impact of uncertainty when selecting casing setting depth by widening the usable margin between pore pressure and fracture gradient.
Building a Vietnamese Company
Authors: Deaves Craig
Published: December 2007

This paper describes the strategy BP developed and the processes it used to build its Upstream Operation in Vietnam. This strategy followed a simple 3 point plan which covered recruitment, training and assessment through to retention. It describes the processes used to develop competency and provide assurance that BP has the right people with the right skills in the right place at the right time – both now and in the future.

The facilities include the Lan Tay offshore gas platform, the Dinh Co Terminal and the Phu My 3 Power Station. BP has recruited and trained over 250 technicians and support staff over the past 3 years to commission, operate and maintain these facilities.
Gravel Packing Wells Drilled With Oil-Based Fluids: A Critical Review of Current Practices and Recommendations for Future Applications
Authors: Parlar M. , Twynam A. J. , Newberry P. , Bennett C. , Elliott F. , Powers B. , Hall K. , Svoboda C. , Rezende J. , Rodet V. , Edment B.
Published: December 2007

Many of the recently discovered reservoirs in deep-water/subsea environments are prime candidates for horizontal open-hole gravel packs. Presence of multiple reactive shale breaks and penetration of different sand bodies along these holes introduce a formidable challenge for selection of proper carrier fluids, considering that most of these wells require oil-based (OB) drilling fluids.

Various procedures were practiced for gravel-packing wells drilled with OB fluids, most utilizing water-based (WB) carrier fluids. Primary concern in using WB carrier fluids is the destabilization of the shales.

If the displacements to WB fluids are performed prior to running in hole with the sandface completion assembly, inability to run the screen assembly to target zone is the risk. Consequently, operators were forced to use a two-step process, whereby a predrilled liner is run in hole in OB fluid environment, followed by displacements to WB fluids and gravel-packing with WB fluids. This approach introduces additional rig time and increases completion costs.

If the displacements to WB fluids are performed after running in hole with completion assembly, primary challenge is the prevention of screen plugging. This necessitates a comparison of the benefits and risks of displacements to solids-free oil-based fluids and conditioning of the OB drilling fluid, considering logistics.

An additional consideration in gravel packing with WB fluids in reactive-shale environments is the risk of intermixing of gravel with shales, thus reduced gravel-pack permeability. Various approaches may be taken to minimize this risk. The type of carrier fluid must also be kept in mind from a formation and gravel pack damage standpoints, should losses be experienced during gravel packing.

Another approach in reactive shale environments is to use an oil-based carrier fluid and avoid exposure of the open hole to WB fluids both prior to and during gravel packing. This approach, practiced in two applications, also has its limitations.

In this paper, a critical review of gravel-packing practices in oil-based drilling environments is provided, along with some of the recent developments and recommendations for future applications based on lessons learned from earlier practices.
A Novel Approach to Production Logging in Multiphase Horizontal Wells
Authors: Vu-Hoang D. , Faur M. , Marcus R. , Cadenhead J. , Besse F. , Haus J. , Di-Pierro Esteban , Wadjiri Abdoulaye , Gabon Perenco , Hofmann Andreas
Published: December 2007

Production logging sensors based on center-point measurements are not always successful in obtaining accurate flow profiles in triphase horizontal wells because of the effects of factors particular to these wells: fluid segregation, small changes in the well inclination, and the flow regime.

This paper presents a new tool designed specifically for highly deviated and near to completely horizontal wells. The tool provides a recording of holdup and velocity profiles along the vertical diameter of the borehole cross-section. Three sensor arrays consisting of six optical probes, six electrical probes, and five spinners are spread across the well bore on retractable arms that can be opened and closed with a hydraulic sub to better locate holdup interfaces. The optical probes use the fluid's reflectance to derive the gas holdup, and the electrical probes measure the fluid's impedance to derive the water holdup. The spatial location of the different sensors is accurately known through the use of an integrated relativebearing sensor and a caliper measurement. The direct measurement of the velocity and fluid holdup profile enhances the capability of the analyst to determine the downhole phase split and reduces the uncertainties associated with triphase flow interpretation.

This paper will discuss the problems mentioned and will illustrate through worldwide field examples the success of the new tool.
Production of Waxy Low Temperature Wells with Hot Gas Lift
Authors: Fleyfel F. , Meng W. , Hernandez O.
Published: December 2007

An Oil reserve is discovered in a remote shallow water area offshore Africa, where the water depth is approximately 200 ft. The predicted production rate is approximately 500 BPD per well. The obtained oil samples indicate that the produced fluid has a high pour point (91°F) and a high wax appearance temperature (105°F). A dry tree completion is the planned option for this field. The wellhead flowing temperature (WHFT) is predicted to be below the wax appearance temperature (WAT) during normal flow without heating.

Under certain specific field conditions, such as the development being considered, hot gas can be used as a means to maintain WHFT above the oil WAT and also be used as an artificial lift method to produce the low pressure / low temperature wells (LPLT). Economically, since the reserve is located remotely from gas market, the produced gas is "free." This paper describes the engineering evaluation of a hot gas lift design concept for a particular LPLT field. The hot gas lift method will avoid wax deposition, gelling and blockage problems in the wellbore. The wellbore thermal-hydraulic behavior is studied to optimize gas lift injection rates and temperature.
Water Permeability Reduction Under Flow-Induced Polymer Adsorption
Authors: Ogunberu A. L. , Asghari K.
Published: December 2007

Proposal

The influence of induced polymer adsorption for reducing the effective permeability to water in reservoirs was investigated. Results for the anionic polymer used in this study, show that polymer adsorption is unaffected by the ionic character of polymers, provided the polymer is hydrophilic.

In this paper, we present experimental results that show at increased shear rates, there is improvement in the adsorbed polymer layer. This phenomenon is known as flow-induced adsorption. These experiments indicate that above a critical shear rate, there is a shift in permeability-reduction-mechanism from static to flow-induced adsorption, necessitating a sharp increase in adsorbed polymer layer.

Different scenarios to investigate the effect of polymer residence time and increasing rate of brine flush were investigated. Results show that there is a marked difference on water permeability reduction at zero polymer residence time and when a polymer residence time is allowed. Under static adsorption, slight increase in adsorbed layer thickness at low shear rates is observed. This effect is induced during brine flush when polymer macromolecules are forced to penetrate the existing adsorbed polymer layer. This results in maximum conformance of the polymer macromolecules at low shear rates, contributing significantly to the influence of flow-induced adsorption, depending on the rate of brine flow. All the experimental results revealed that the critical shear rate for this polymer is between 400 to 500 s-1 in the absence of mechanical degradation. For comparison with the above experimental results, similar experiments were performed at increased polymer concentration and also carried out in a core. Results indicate that the permeability-reduction-mechanism is constrained by increased polymer concentration and low-permeability porous media.
Drilling Metrics for Improved Casing Running Performance
Authors: Mason Colin J. , Chen David C-K
Published: December 2007

Despite the use of advanced rotary steerable systems to improve drilling capability and performance, casing running in these same wellbores can sometimes be unpredictable. A collaborative study has been undertaken to develop a set of drilling metrics to assist with identifying wells where casing running has a risk of failure. This project called "DMICRP" (Drilling Metrics for Improved Casing Running Performance) is currently in the early phase of development; and, therefore, results presented here reflect thoughts, ideas, and progress to date. The framework described in this paper is not only specific to running casing and liner but can also be applied to the installation of other tubulars such as solid expandable tubulars and expandable sand screens. The project is also seeking collaboration with other operators and interested parties to share data and experience. Upon completion of the project, the knowledge based system will be made available to the drilling community.
Information System Optimization for Operations
Authors: Dumont Jacques , Duzan Marie-Christine , Huard Gérard
Published: December 2007

After the period of merger between TotalFina and Elf and the multiplication of complex operations, it has become imperative for TOTAL to optimize its Information System for operations management by taking advantage of the outstanding improvement of the Information Technology.

The main objective was to ensure an optimal environment of IS tools to end users and management in term of front office, engineering software's, data management, documentation, infrastructure and organization. The ultimate goal remains to vastly improve the costs of the Information System, the technical knowledge of engineers, the field experience sharing and finally the quality and efficiency of Operations.

This paper describes the strategy, information technology, technical applications and process used to address the optimization of an efficient and adapted Information System for Operation Management. This concerns Drilling, Completion, Production, Technology and Project activities.

This paper will also describe the specific solutions adopted for each activity as well as the problem encountered and lessons learned. It will then discuss the key factors of success, potential risks and associated costs.
Technology for Controlling Eccentric Wear of Sucker Rods and Tubing in Pumping Wells Lifting Fluids Containing Polymer
Authors: Wang Yan , Wang Demin , Sun Zhi , Han Hongsheng , Gong Mingjing , Wang Gang
Published: December 2007

In Daqing Oil Field, after polymer flooding, severe eccentric wear of sucker rods and tubing in many wells with pumping units have occurred. The life span of the tubing string has decreased from 750 days for lifting fluid that does not contain polymer to 270 days for fluid that contains polymer. This has greatly increased work-over job frequencies and the production cost, and has seriously affected normal crude oil production.

With respect to this problem, this paper gives an introduction to a technology to control eccentric wear of sucker rods and tubing in pumping wells lifting fluid containing polymer.

Based on visco-elastic fluid dynamics, the constitutive equation of visco-elastic fluid and its flowing equation in an eccentric annulus is established, the magnitude of the normal force caused by the flow of fluid containing polymer on the sucker rods and pump barrel is derived and calculated. Based on lab experiments with visco-elastic fluid flowing in the annulus formed by the tubing and sucker rod, the relationship between the magnitude of the normal force of flowing viscoelastic fluid with different concentration, velocity and eccentricity of the sucker rod related to the tubing is measured; the resistant force of visco-elastic fluid flowing across pump valves and pump barrels is also measured; it could be seen (both visually and numerically) that the eccentric wear is mainly caused by the normal force of the flowing visco-elastic fluid.

On the basis of the above study, measures to prevent eccentric wear were implemented, which includes centralizing sucker rods, using large clearance pumps with large channels, using uniform diameter sucker rods in the whole well-bore and regularly rotating the sucker rod string. Practice on 6,266 wells in the field indicates that these measures can effectively solve the problem of eccentric wear of sucker rods and tubing in pumping wells, the life span of the tubing string increased from 270 days to more than 1,000 days, which brought about marked economic benefits. At present, all pumping wells in Daqing that lift fluid containing polymer use the technology described in this paper.
Simulation of Air Injection in Light-Oil Fractured Reservoirs: Setting-Up a Predictive Dual Porosity Model
Authors: Lacroix Sébastien , Delaplace Philippe , Bourbiaux Bernard , Foulon David
Published: December 2007

In addition to standard oil recovery methods by depletion, various fluids (water, nitrogen or many types of gas) can be injected from the surface in order to produce the trapped oil. Among all gas, air is the most convenient one since it presents the advantage of being available everywhere. Therefore air injection can be an economical alternative for pressure maintenance of fractured reservoirs as it avoids reinjecting a valuable associated gas and/or generating or importing a make-up gas. A major contribution of this technique is that the oil recovery can be enhanced significantly thanks to the thermal effects associated with oil oxidation. In addition, from an operating point of view, economical and feasibility studies concluded on favourable future perspectives.

However, its use is limited by safety reasons due to the explosive mixture resulting from oxygen and hydrocarbons. In the reservoir rock, the microscopic size of the pores prevents any explosion. On the other hand, a commingled arrival of oxygen and hydrocarbons in production wells may result in dramatic damages. Therefore, air-injection methods require a careful assessment of the involved reservoir displacement mechanisms, in particular the magnitude and kinetics of matrix-fracture transfers. Actually, the latter will largely control the displacement efficiency as well as the composition of well effluents from which residual oxygen has to be absent.

The aim of this paper is to identify and model the physical mechanisms controlling matrix-fracture transfers during air injection in light-oil fractured reservoirs, first at the matrix block scale then at the field scale. The study actually relies on a careful analysis and compositional thermal simulations on a fine-grid single-porosity model of a matrix block surrounded by air-invaded fractures that allows us to study the influence of block size on the kinetics of oil recovery as well. These fine-grid simulations mainly show that gas diffusion and thermodynamic transfers are the major physical mechanisms controlling the global kinetics of matrix-fracture transfers and the resulting oxidation of oil. The chronology of extraction of oil components from the matrix blocks can then clearly be interpreted in relation with phase transfers

Once all the mechanisms have been identified, we focus on the equivalent (up-scaled) dual-porosity modelling. This model, rooted in a specific numerical formulation which ensures a proper up-scaling of diffusion and inter-phase transfers at the overall scale of matrix blocks, eventually appears to be a reliable simulation tool usable for field-scale predictions, in agreement with the previously defined reference model. Thus, results could be simulated and interpreted at different scales closer to the field scale than the matrix block scale. In addition, some conclusions were drawn regarding the sensitivity of the process to the kinetics of oxidation and the water saturation conditions.
Practical Diagnostics Using Production Data and Flowing Pressures
Authors: Anderson David , Mattar Louis
Published: December 2007

There have been tremendous advances in the science of production data analysis in recent years. Three of the most important examples are the inclusion of flowing pressures into analysis methods, the usage of a "boundary dominated" equivalent production time function to make constant rate and constant pressure equivalent, and the use of pseudo-time, which corrects for varying gas properties with pressure. In theory, these advancements enable more sophisticated analyses, accompanied by more reliable results. However, it must be realized that their value is strongly dependent upon the quality of "real" production data, and more importantly, the analyst's ability to filter out the "junk" and retain the true reservoir signal. The blind application of modern decline analysis methods, without consideration of data quality issues, can lead to misinterpretation and erroneous results.

This paper presents several practical diagnostic procedures, some general and others specific, that can be applied to production data, both on simple production charts and on advanced typecurves. Some examples include identifying liquid loading and changing wellbore skin, detecting a shift in well productivity, and diagnosing external pressure support and interference. Field examples are presented to illustrate the effectiveness of these diagnostics. This paper represents the first and only compilation of practical diagnostics for advanced production data analysis that the authors are aware of. The potential benefit of this work is that it will enable engineers at the operational level to more effectively apply advanced analysis techniques to real data, by limiting the possibility of misinterpreting the data.
Some Pitfalls in Well Forecasting
Authors: Williamson H S , Sawaryn S J , Morrison J W
Published: December 2007

Monte Carlo simulation is rapidly superceding deterministic methods as the preferred technique for many well forecasting applications. This paper contrasts the two techniques and highlights the potential benefits of the former. The main part of the paper is a discussion of the application of Monte Carlo simulation to time and cost estimation of single wells, and in particular of some common errors which the authors have observed practitioners to make (or have themselves made) in this context. This discussion, together with sections covering multi-well programs, scheduling, and production issues, demonstrate that although Monte Carlo simulation has the potential to enhance the reliability of well forecasts, this potential can be realized only if the technique is applied with great care.
Best Practices from RPM-Fracturing Treatments in Colombia, South America
Authors: Pinto Sandra González , Izquierdo Guillermo , Téllez Oscar
Published: December 2007

Approximately 30 relative permeability modifier (RPM) fracturing treatments performed in Colombia will help establish consistent, reliable best practices for future applications. Some of these treatments combined scaling inhibition stages to maintain production enhancement, in spite of high or medium formation water scaling tendencies. Because the water-injection system is significantly dynamic in these fields, new injection water channels were communicated with producer wells after RPM-fracturing treatments, reducing scaling inhibition requirements and RPM effectiveness for water production management.

The objective of combining RPM and fracturing treatments was to increase oil production over time through effective water production control techniques.

Evaluations of the effectiveness of both general and specific treatment processes and service are available in the industry. However, data for the analysis of RPM-fracturing treatments presented in this paper was obtained in two basic procedures:

The workover operating efficiency (WOE) index was established to evaluate fracturing effectiveness (total fluid production increase) and RPM effectiveness (water-oil ratio [WOR] reduction). The WOE index quickly analyzes all treatments and identifies the best-performing ones based on two factors: (1) production-related WOE indexes higher than one, which is the maximum production rate after treatment vs. the minimum production rate before treatment, and (2) WOR-related indexes lower than one, or the minimum WOR after treatment vs. the maximum WOR before treatment. This analysis can quickly define the best and worst performances by evaluating individual fracturing effectiveness and individual RPM effectiveness. The reservoir-performance analysis is a cyclical and detailed process that does not focus on individual wells but rather analyzes the entire reservoir. This stage consists of an extensive analysis that involves reservoir characterization, well testing and production history, completion design, stimulation operation design, and stimulation operation execution and feedback.

Because this analysis was so extensive, it was applied only to the best- and worst-case scenarios (two different fields) in which combined RPM-fracturing/scaling inhibition treatments had been in effect for more than 2 years. Those two fields presented some similarities in terms of producing-zone depth, reservoir character, reservoir fluid properties, and water-injection systems.

Both general and specific processes for treating and servicing wells have been evaluated for effectiveness by the industry. Applying the results of the two analyses presented in this paper, best practices are now defined for future well selection, treatment design, and operation execution for combined RPM-fracturing/scaling inhibition treatments.
After-Closure Analysis to Identify Naturally Fractured Reservoirs
Authors: Chipperfield Simon
Published: December 2007

After-Closure Analysis (ACA) in homogeneous matrix reservoirs provides a method for extracting critical reservoir information from pre-frac injection tests. This paper extends the theory and practise of ACA to identify the presence of productive natural fractures.

Natural fractures are important to identify prior to conducting a stimulation treatment because their presence may require designs that differ from conventional matrix treatments. Literature shows that naturally fractured reservoirs are very susceptible to formation damage and require stimulation treatments to account for this issue. The historical problem however, has been to confidently characterize the reservoirs pre-frac, both in terms of the reservoir quality and deliverability mechanism (fractures versus matrix), prior to committing to these design specifications.

This paper presents the results of a simulator used to analyse the mini-frac after-closure period to identify the presence of natural fractures. The simulation results are distilled to a field implementation methodology for determining the extent of natural fracturing and the formation reservoir quality. Unlike previous mini-frac analysis methods, this approach identifies natural fractures that are material to production and allows the engineer to distinguish them from ‘fissures’ that are open only during injection and are not a production mechanism.
Optimization of Injection Field Design with Consideration of Cost and Pressure Constraints Under Conditions of Uncertainty
Authors: Fontaine Russell C. , Anderson Jeffrey A. , Hunter W. Alan , Tubbs Dallas H.
Published: December 2007

A unique approach has been developed to optimize injection for managing excess produced water at oil and gas fields. A simulation case study is presented demonstrating how the approach helped ChevronTexaco to quantify ultimate injection volume, number of injectors, injection rate per well, and well location for two sandstone aquifers downgradient and fault separated from their associated oil reservoirs. The approach combines stochastic, deterministic, and optimization models and is flexible to honor all the available data and also incorporate uncertainty in the field parameters (e.g. permeability distributions, boundary and initial conditions, and geologic barriers). A stochastic version of the model is best used to assess uncertainty in the geologic and pressure regimes. These runs are preceded by traditional deterministic simulation techniques, including history matching to the available pressure transient data. Once the scenarios have been selected, optimization simulations quantify the optimum number of injection wells and location, and the total volume of water that can be injected over the period of interest. A particle tracking technique is also used to define the pathways of the injected water and assess its ultimate fate and potential impacts. This approach can be used cost effectively to optimize produced water management under conditions of uncertainty with a sparse data set.
Central Waste Treatment Facilities (CTRD) Reduce Drilling and Waste Management Costs in Heavy Oil Operations, Eastern Venezuela
Authors: Arrocha Alfonso , Ellis Gustavo , Browning Keith , Redfern Kevin , Bernal Gonzalo
Published: December 2007

The Ameriven Central Waste Treatment Facilities (CTRD Centro de Tratamiento y Recuperación de Desechos), which were designed and implemented with the technical support of teams provided by a major drilling waste management service company, receives and processes heavy-oil drilling and production waste generated by operations in the Hamaca Project, located in the Faja Region of the Orinoco Belt in Venezuela.

The CTRD operational strategy emphasizes the 4Rs: reduction, reuse, recovery, and recycling. Important cost savings have been achieved from: (1) the consolidation of waste treatment at one location near the source; and (2) the efficient waste management practices implemented by the fluids and waste management team, under contract with Petrolera Ameriven (Ameriven). The facility now serves as a model for similar operations in the region and has earned unconditional approval from governmental agencies and prominent companies with commercial interests in the area's forests and resources.

Over the life of the 30-year project, the facility will process the waste from approximately 250 to 500 wells. The current development production phase yields 80,000 bbl/day, with 190,000 bbl/day extra-heavy crude expected in the commercial production phase. Cost reductions related to waste management and disposal at this site are currently estimated at 22% (since commencement of operations) and are expected to improve further as the facility is used to full capacity.

Several integrated processes are implemented for the efficient disposal of drilling waste products: thorough rig audits, solids-control equipment performance, rig, field, and plant supervision, dewatering, water treatment, and landfarming and landspreading of processed solids and cuttings.
High-Speed Pressure and Accelerometer Measurements Characterize Dynamic Behavior During Perforating Events in Deepwater Gulf of Mexico
Authors: Schatz J. F. , Schatz John F. , Folse Kent C. , Fripp Michael , Dupont Richard
Published: December 2007

With the current oilfield trend to pursue prolific oil and gas producers in the deepwater markets around the world; operators are drilling and completing larger boreholes to deliver and accelerate the production stream more effectively. Typically, in deepwater environments, the intervals to be perforated tend to be longer than on shelf-type completions. In addition, deepwater completions are more complicated with stacked pay zones that require additional completion steps and associated hardware. To execute these larger completions, operators normally opt to choose the largest perforating assembly that will yield the best charge performance (casing-entrance hole diameter and formation penetration) at in-situ conditions. These larger perforating systems with higher shot densities and total explosive load have the potential to create very large fluid-pressure waves and solid shock loads that can cause damage to the completion (unset packers, move bridge plugs, buckle tubing, split casing, etc.) under certain conditions.

Because of the added expense of completing wells in the deepwater arena, problems during the perforation process can considerably increase completion expenditure. To help minimize potential risk during the completion program, it is critical to understand the dynamic pressure and shock events that occur during perforating.

This paper will present a new numerical model that helps to ensure service quality by improving reliability on deepwater completions. The model has been validated with field measurements and employs high-speed recorders that were previously dedicated primarily to validating burn parameters for propellant-type equipment.