bluuebunny/crossref_metadata_2025 huggingface dataset:
An Update of Recent Production Responses Obtained from Devonian Shale and Berea Wells Stimulated with Nitrogen Foam (with Proppant) vs. Nitrogen-Only, Pike Co., KY
Authors: MacDonald R. J. , Frantz J. H. , Schlotterbeck S. T. , Adams B. , Sikorski D.
Published: December 2007

This study updates SPE paper 77464, which compared 97 nitrogen-foam (with proppant) stimulations versus 120 nitrogen-only completions performed in the 1990's in Pike County, Kentucky. Ninety-three of the 97 foam stimulations are located outside of a relatively high permeability area located in the northwestern portion of the study area. For analysis purposes, these 93 wells have been compared with 14 recent foam stimulations drilled throughout 2002 and the first quarter of 2003.

All wells are owned and operated by Equitable Production Company and are located in Pike County, Kentucky and are completed with two stages in the Devonian Shale and Berea formations. Our results indicate that the latest foam treatments outperform the earlier foam stimulations by a noteworthy percentage. This improved performance is most likely due to high-quality post frac clean-up methods, promptly turning the wells in line, and subsequent expert well maintenance.

There has been no significant change in stimulation design for the new wells when compared with the earlier completions, however the latest stimulations are utilizing a consistent design per well (e.g. ramping from 90Q to 75Q, standard proppant volumes sent downhole, similar pad size etc.), whereas the earlier stimulation designs tended to vary from well to well. In addition, line and annular pressures are similar, and reservoir qualities (e.g. relative permeability, net pay thickness, etc) are analogous between the earlier wells and new completions.

In furtherance of this study, the operator is continuing to pump foam with proppant in wells throughout the study area. The results of this paper are significant for Appalachian Basin operators utilizing nitrogen foam treatments since it quantifies the positive influence of rapid well clean-up and first-class well maintenance. Additional acreage is also being evaluated for use of this stimulation treatment, including evaluation of existing wells for restimulation potential. This is the first paper published to update results over such a large study area.
Fracture Height Development and Control in the Mississippian Sandstones of Central West Virginia
Authors: Mack David J. , Awny Joseph , Kendrick Daniel
Published: December 2007

Natural gas production in central West Virginia is primarily from the shales of Devonian age upward to the sandstones of Pennsylvanian age. These productive intervals are typically low permeability, under pressured and adjacent pay zones can have similar closure pressures with only a minimally competent barrier separating them.

Such a scenario exists in the Weir and Injun sandstones of Nicholas, Fayette and Kanawha Counties, West Virginia. At a depth of 2000 to 2500 ft, both the underlying Weir and overlying Injun exhibit only a few hundred psi reservoir pressure, frac gradients in the 0.4 to 0.6 psi/ft range and are separated by 10 to 20 ft of sandy shale. To make either of these zones commercially productive, both must be hydraulically fractured.

Initially it was felt that historical treatment data and the comparison of conventional electric logs to offset wells would provide sufficient data to effectively fracture model stimulation treatments. This technique provided interesting computer simulations, but treatment and production results did not substantiate the modeling.

In an effort to better model and stimulate both zones, mechanical properties were obtained from a sonic log. Treatment parameters such as pressure, fluid efficiency/formation permeability and near wellbore connectivity characteristics were obtained from step-down and mini-frac tests. Real-time job monitoring, post-frac RA tracer survey and production testing were performed to verify the design simulation.

Treatment design history and current philosophy will be discussed in this paper. In addition, the results of the data gathering, treatment design and execution and RA tracer survey will be presented.
Pulsed Water Injection During Waterflooding
Authors: Groenenboom Jeroen , Wong Sau-Wai , Meling Tor , Zschuppe Robert , Davidson Brett
Published: December 2007

During a half-year field test a novel method was applied for water injection during waterflooding in a weakly consolidated, heavy oil reservoir (90–120 cP). The injection has been combined with a hydraulic pulsing tool downhole in the injection well to provide additional dynamic pressure pulses on the order of 4–17 bar, with 5–6 pulses per minute. The technology has been developed in Canada and applied successfully, especially as a well stimulation technique in order to initiate or stimulate oil production with sand coproduction. The first objective was to see whether pulsing would be beneficial for the efficiency of the injection process. Furthermore, laboratory experiments and theoretical developments suggest that pulsing might improve the sweep efficiency of the flooding pattern. Hence, the promise of this technique would be potentially faster and higher oil recovery during waterflooding. In the design of the field test it was chosen to keep the total water injection rate on the same level as before pulsing was applied, on the order of 110 m3/d. The rationale behind this decision was that previous experience in the field has shown that higher injection rates resulted in pressurization of the reservoir and increased fingering. In addition, the fixed injection rate allowed us to focus on improvements in sweep efficiency, without correcting production figures for the higher injection rate.

Pressure Pulse Technology (PPT) was applied without any significant operational problems for half a year although severe corrosion problems unrelated to the PPT project were uncovered after the trial. Injection and production performance has been monitored before, during and after the test. When pulsing started, injection pressure dropped, and even after the pulsing stopped a lower wellhead pressure has been measured. With constant injection rate this shows an improvement in injectivity. It also indicates a significant reduction in near wellbore skin factor or possible improved injection conformance. The injection water used is considered dirty and potentially deteriorates injectivity over the life of the well. Indications are that injection pressure is now slowly building up again following the trial.

Improvements in production have not been confirmed by this field trial. The accuracy and repeatability of the production measurements have not assisted in identifying the potential effect. However, the field trial results have enabled us to recognize the potential use of the technology for an efficient high-rate injection strategy. Possibly this would avoid injection under fracturing conditions. We outline situations where such applications would be desirable. Higher injection rate and more efficient pulsed injection potentially lead to improved recovery, although actual improvements need to be assessed with further tests.
A Technically Rigorous and Fully Automated System for Performance Monitoring and Production Test Validation
Authors: Bruni Thomas , Lentini Amelia , Ventura Stefano , Gheller Ruggero , Maybee Charles A. , Pinedo Jorge E.
Published: December 2007

This paper describes the integration between a dynamic surveillance tool and a system analysis tool to provide the surveillance engineer with a new, fully automated and technically rigorous system, capable of true performance monitoring and reliable production test validation.

The combination of the software tools and workflows resulted in an innovative PROduction Management and Optimization system (PROMO), with new and extended capabilities beyond those of either of the stand-alone packages. Algorithms were defined in order to automatically compare actual and modeled production (taking into account FTHP variations) on a daily basis. Additionally, as new production test data becomes available, the system can automatically display it on a calibrated IPR plot for fast and rigorous validation. The system has also been designed such that when a new well test is approved and validated, the IPR curve will be automatically re-calibrated to honor the new performance measurements.

In principle no gas or oil field is outside the scope of such an application. Once an appropriate interface is set up to allow for data exchange between the surveillance and system analysis tools, it is a matter of building the appropriate processes that will yield the most beneficial results in terms of production optimization and data validation. The addition of data linkages to corporate data warehouses results in a system that requires little maintenance of input parameters and is always up-to-date with respect to the available data.

The PROMO system, currently deployed in one gas plant (comprising of seven offshore gas fields, 14 platforms and 180 production strings) and one oil plant (comprising of two onshore oil fields and 10 production strings), is allowing the production engineers to easily identify under-performing strings (completions) and promptly intervene. In addition to providing a more reliable and time effective production test validation process, the engineer can fully analyze current well performance with daily, historical and forecasted data. Additional benefits include calculation of historic SBHP’s from production tests, dependable production allocation (with great benefit for overall field management and reservoir modeling) and considerable time savings as pertinent data is automatically (as opposed to manually) handled and used in the system analysis algorithms.
Using Geological Knowledge Gained Through Special Seismic Studies To Provide A Strategy For Improved Oil Recovery
Authors: Cullen Andrew , Johnson Timothy. E. , Toulekima Serge , Miltos Xynogalas , Zhu Hua
Published: December 2007

There are many techniques beyond standard seismic interpretation that can help optimise and direct improved oil recovery. Firstly, an integrated approach involving a multi-scale analysis of petrography, image log analysis, seismic facies studies, petrophysics, AVO forward modeling and seismic inversion aid understanding the depositional system, burial history, diagenesis, deformation and fluid movement history of the reservoir. The resulting reservoir geometry and properties are used as direct input to a detailed static model, which is used to plan development activities in an optimum way. 4D forward modeling tied to dynamic modeling is used to test development scenarios and select optimum bore locations to help maximize production efficiency. A key element in ensuring the applicability of such work is the rock property constraints employed. A consistent methodology for deriving calibrated rock properties for such work is described. Examples of such an approach are given from several fields in Sabah where a variety of production challenges are encountered.
Propellant Perforation Breakdown Technique: Eastern Venezuela Field Applications
Authors: Boscan Jorge , Almanza Edgar , Folse Kent , Bortot Maximiliano
Published: December 2007

PDVSA operates the RG-231 and AM-102 wells, located in eastern Venezuela. The wells are characterized by stratified reservoirs and complex geology due to the presence of low permeability and porosity. The RG-231 well is in a gas reservoir with extremely low permeability (less than 0.02 md). During a well-testing operation, additional perforations were added to increase gas production. The AM-102 well was in an oil reservoir.

To effectively meet the operator’s needs for a method that would help to optimize well productivity and costs without compromising the results of the operation, a change from traditional perforating operations was required. A propellant-assisted perforating method to optimize well productivity while maintaining stringent health, safety and environmental standards was proposed. The propellant-assisted perforating method uses standard perforating components and procedures; thus, it was capable of providing the necessary safety features. The propellant is essentially an oxidizer that creates carbon dioxide gas at extremely high peak pressures in the millisecond time regime to overcome in-situ stresses and create perforation breakdown and mild fracturing near the wellbore.

This paper will focus on the method developed to satisfy the operational challenges specific to the PDVSA wells. The discussion will cover the results obtained by using propellant technology in a low-permeability, low-porosity reservoir as well as how the technique was capable of addressing the operator’s requirements in data acquisition as well as the difficult reservoir conditions. Instrumental in the success of the methodology was the combined use of super-deep penetration technology and propellant assisted perforation.
Waterflooding in Low N/G Fluvial Environment – Thai Shell Experience
Authors: Chuenbunchom Supamittra , de Bruijn Gerbert , Indran Devarajan , Akrapipatkul Piti
Published: December 2007

Thai Shell operates three onshore oil fields producing from the Yom/Pradu Tao Formations in the Phitsanulok Basin in Thailand: Sirikit D block, Thap Raet and Sirikit West. The Yom/Pradu Tao Formations originate from a low energy fluvial depositional environment with a low net-to-gross ratio of 20–40%. After a comprehensive evaluation of EOR methods, waterflooding was found to be the most attractive development concept to achieve a significant increase in recovery factor in the Yom/Pradu Tao reservoirs. However, waterflooding in a complex low net-to-gross fluvial environment is not straightforward. Thai Shell has followed a step-by-step approach in the implementation of waterflood starting with the Sirikit-D block in 2000, which is geologically least complex, followed by Thap Raet in 2001. Sirikit D block and Thap Raet are both showing a positive response to waterflooding, substantially increasing production and reserves. Sirikit West, the largest and geologically most complex of the three fields, has started water injection in May 2003. Prior to the implementation of waterflood in Sirikit West, the field had been subjected to extensive studies using multiple static and dynamic model realizations. This paper will provide an overview of the experiences and performance of waterflooding to date in the Sirikit-D and Thap Raet fields. In addition, it will explain the modeling approach and waterflooding plans in the Sirikit West field.
Rotary Steerable System Applications in the Middle East
Authors: Pratten Charlie , El Kholy Khamel , Naganathan Sivaraman , Sharaf Ehab
Published: December 2007

Rotary Steerable drilling systems have led to a step change in drilling performance in many areas of the world. However their use in the Middle East has generally been slower to develop than in other drilling provinces around the world such as The North Sea where the value of rotary steerable drilling has been documented since 19981. Commercial as well as technical issues have limited widespread deployment of these systems in the region. This paper reviews successful rotary steering applications in the Middle East to date and explores areas for potential increased use.

Using case studies the paper looks a range of specific applications where the change from steerable motor to rotary steerable system has been both technically and commercially successful in the Middle East. Through these case histories the paper will demonstrate both tangible and intangible benefits resulting from the use of rotary steerable systems that have led to a step change in overall drilling performance in the Middle East.
Enhancing Rig Site Risk Awareness
Authors: Coakley Brian , Baraka Choaib , Shafi Mohamed
Published: December 2007

NDC has very successfully implemented an Unsafe Act (UA), Unsafe Condition (UC) and Near Miss (NM) reporting system. Over 20,000 reports are currently generated per year from the twenty four rigs which NDC own and operate.

These UA, UC and NM reports are reactive. Hence two additional systems, Behavioural Safety Auditing (BSA) & CHECK have recently been implemented. These provide a proactive input to prevent future NMs. In addition NDC are currently developing the SAP network to provide on-line HSE event tracking.

This paper presents how three systems can be run in parallel to provide comprehensive rig site risk awareness coverage. It describes how a multiple system approach to risk awareness avoids gaps and a reporting network allows all sites access to all reports.
Under Balanced Drilling Building the Future for PDO
Authors: Eissa Walid , Al-Harthi S.
Published: December 2007

Petroleum Development Oman LLC is one of the leading oil companies in the Middle East with a long history of early utilization of new technology. The cumulative production from its fields to date runs into millions of barrels of oil, with production starting back in 1967.

Drilling in PDO's mature fields using conventional drilling methods has become a challenge these days as severe reservoir impairment has been seen in Nimr and Saih Rawl fields. Much of this impairment is due to high overbalances resulting on the low reservoir pressures. Other problems were high water cut above that predicted from logging while drilling (LWD) evaluation. Underbalanced drilling (UBD) was identified as a method of overcoming this problem.

UBD trail wells have been drilled using 2 different UBD techniques (Concentric casing and Drill pipe gas injection). To date 18 UBD horizontal wells have been put onstream: 14 horizontal single lateral wells in the Nimr Field (12 new wells and 2 re-entries); and 4 horizontal multi lateral (total of 9 legs) UBD wells in the Saih Rawl Field.

Significant productivity improvements have been observed, and valuable reservoir data has been gathered during the drilling of these wells. Drilling performance has also shown marked improvements. This paper is written to highlight the key learning points which have been captured and applied in the UBD campaigns.
A Productivity Tool for Impact of Filtration on Well Performance in an HP-HT Environment
Authors: Amish Mohamed Belkasem
Published: December 2007

In recent times, the oil industry has shown increasing awareness towards maintaining optimum well productivity through better HP-HT drilling/completion fluids design. However, the mechanisms of drilling fluid filtration and impact on productivity performance are not well understood, especially in an HP-HT environment.

In open hole completions the productivity losses are critical because the near-wellbore damage is not by-passed by perforations.

Furthermore, a satisfactory model for field applications to simulate the near-wellbore damage in terms of well flow performance from laboratory core test analysis still is not available.

In this paper, the results of in-depth experimental research into rheology, filtration and formation damage phenomena and the relationships between them. The experimental data combined with data analysis of static and dynamic filtration models provided the database for the semi-empirical mechanistic models that were developed. These models have been combined and incorporated into a design and evaluation tool - the productivity tool, for predicting the effect of HP-HT drilling fluid filtration on formation productivity.

A number of results have been presented to illustrate how the new tool can be used to evaluate the damage factor of a given fluid, specify the invaded zone skin as well as the depth of invasion, two key parameters that are useful and relevant to optimum fluid selection and management in addition to well test data interpretation.
Prediction of the PVT Data using Neural Network Computing Theory
Authors: Goda Hussam M. , El-M Shokir Eissa M. , Fattah Khaled A. , Sayyouh Mohamed H.
Published: December 2007

Artificial neural networks theory creates, with other theories and algorithms, a new science. This science deals with the human body as an excellent source, through which it can simulate some biological basics and systems, to be used in solving many scientific, and engineering problems. Neural networks are tested successfully in so many fields as pattern recognition or intelligent classifier, prediction, and correlation development. Recently, Neural network has gained popularity in petroleum applications. In this paper we applied this technique in PVT parameters determinations.

The application interests in the estimation of the bubble point pressure through a designed neural network. As this value well estimated, it then used with other variables in a second network to determine oil FVF at this value of bubble point pressure. A comparison study between the performance of neural network and other published correlations has shown an excellent response with smallest absolute relative average error, and highest correlation coefficient for the designed networks among all correlations.
Laboratory Evaluation of Chemical Grouts for Wellbore Stabilization
Authors: Li D. , Chen G. , Chukwu G. A. , Patil S. L. , Khataniar S.
Published: December 2007

Wellbore drilling in highly fractured and unstable formations has always been one of the greatest difficulties in drilling operations. Failure and collapse of wellbore wall frequently occur in the fractured zone and may ultimately obstruct any further drilling of the wellbore. A number of techniques have been proposed and tested to improve drilling conditions in the fractured and unstable formations, but a highly effective method is still lacking. For many years chemical consolidation techniques have been studied and applied for ground support in underground mine openings. Very successful results have been achieved employing the techniques to stabilize fractured zones surrounding underground openings. For these a number of highly effective chemical materials for consolidation have been developed.

In order to examine the feasibility of this technology for enhancing wellbore stability, a series of laboratory experiments have been carried out in this study. These experiments included uniaxial compressive strength tests, triaxial compressive strength tests, shear bond strength tests, indirect tensile strength tests and thick wall cylinder tests. Chemical grouts Terraset B1000, Webac 4110 and others were used in these tests and their mechanical properties were assessed. The results of the experiments show that chemical grouting is likely to improve the stability of wellbore in fractured and unstable rock formations. Among the grouting materials tested, the Webac 4110 had the best performance. Its use increased the shear strength by 100-150%.
Real-Time Dip Applications for Geosteering Horizontal Wells, Onshore Nigeria
Authors: Ingebrigtsen E. , Onyirioha R. , Garrity J. , Logan J. , Butt P.
Published: December 2007

Geosteering is the interactive placement of a wellbore using real-time geological criteria; its use allows increasingly more complex geologic targets for horizontal producers and injectors.

This paper presents a case study of Geosteering horizontal wells in an onshore field of the western Niger Delta. The results demonstrate how an integrated team uses modern LWD tools to make real-time well path corrections in a challenging environment.

The objective of geosteering is to direct the well using real-time logging and interpretation to a specific target within the reservoir. Various best practices are discussed in which geologic and structural data are combined with LWD measurements to lower the risk of "landing" and subsequently maintain the horizontal portion of the well in the desired location.

Real-time dip estimation is a tool in the geosteering arsenal that can assist with geosteering decisions both during landing and while maintaining the lateral portion of the wellbore in the target window. Field examples illustrate the use of azimuthal density measurements to enhance real-time evaluation and decision-making processes. Quadrant density measurements and density images are used to calculate dips and enhance steering decisions made by an asset team of geologists, petrophysicists, and geosteering engineers for a field development project in Nigeria.

Present methods in geosteering for real-time dip estimation include interpretation of resistivity and density images, estimation from the quadrant density log, and detailed stratigraphic correlation during approach hole drilling. Associated with each estimation method is an inherent uncertainty with the dip calculation; these uncertainties can lead to geosteering decisions of low confidence. To reduce the total uncertainty, more than one method for calculating dip can be used to assist with well plan adjustments. The thinner the sand is, the tighter the steering tolerance becomes, requiring the well to be drilled closer to bed or target boundaries. The most accurate possible dip estimation is needed for these cases.
Incident Analysis using the Root Cause (Tripod Beta) Methodology-An SPDC Experience
Authors: Otutu F. , Agba S.
Published: December 2007

The Root cause analysis, called the Tripod Beta, is an approach to the analysis of incidents using the Tripod theory of Accident causation and the hazard and effect management Process (HEMP). This approach was adopted few years ago to stem the increasing rates of serious HSE incidents in SPDC and the advantages can be seen.

The pattern of previous incident investigation has been the same-the discovery that an incident happens always puts an end to the investigation, as if there is no need to look further-no need to see that such incidents are the effects of other causes.

The root cause (Tripod Beta) tool is a tree approach to the analysis of accidents and incidents. The method will lead you to take both short term immediate corrective actions, as well as finding the underlying root causes (latent failures) hidden in the way we do our work that will cause similar problems in the future. The Tripod Beta promotes thorough incident investigation with clear, concise and consistent reporting.

This paper presents the SPDC experience using this tripod Beta method in carrying out incident investigation/analysis and the incident trends (since adopting the method) and advantages will be highlighted
Using Production Logging Technology for Reservoir Management in the Persian Gulf
Authors: Alaeddin E. , Maizeret P. -D.
Published: December 2007

Is it a good idea to drill dual-lateral wells in a differentially depleted carbonate formation? The question is difficult. However, a state-of-the-art production-logging tool brought an answer that sanctioned the re-entry drilling program of this offshore field in the Persian Gulf.

The new-technology production services platform equipped with eight electrical e-probes for flow- imaging capability was run on coiled tubing for the first time in this offshore field to characterize the production of a new dual-lateral well. The main objective was to evaluate the total contribution of the horizontal drains. However, since the well was perforated in the different layers crossed by the well path, another critical objective was to determine the need for a stimulation program or a new completion design. Reservoir pressure in the different layers was expected to be non-uniform, so an additional objective of the logging operation was to obtain information on the differential depletion.

Production logging in highly deviated wells is difficult with standard sensors. One reason is that a conventional tool using differential pressure cannot measure fluid density. Moreover, flow regimes can be extremely complex, giving rise to phenomena such as water re-circulation, which is common in slanted wells and impossible to measure with a simple production logging string.

The data showed that both legs are contributing equally to the total production and observed water re-circulation on the bottom of the well. The perforations are not contributing to the total flow. Moreover, a crossflow observed during shut-in conditions suggested different pressure levels in the two layers.

This paper describes the logging operation and discusses how the results helped optimize the re-development plan of this aging field.
Opportunities and Challenges of an Integrated Energy Policy for Nigeria - Perspectives from a Competing Energy Product
Authors: Nwasike Obi Timothy , Gregory Oranugo
Published: December 2007

Until recently, policy and decision makers in Nigeria have neglected the socio-economic and commercial benefits that will accrue from the re- vitalization and re-development of Nigeria’s coal industry. This position is largely due to the lack of a clear energy policy that articulates the role and scope that each of the various energy media should play in our national development and in meeting Nigeria’s long-term goals.

Recent technical and economic studies have identified coal energy as a cost effective solution for power generation; it comes at a cost that is about 50% that of fuel oil. Furthermore, with over two billion tons reserves in Nigeria, coal is an abundant domestic resource that can support the mining industry and provide numerous jobs with potentially high multiplier effects on the local economy. Current technologies allows for clean burning of coal, which takes care of its negative environmental impact; indeed over 50% of the US electrical power supply is from coal resources.

This paper addresses the need to have an integrated energy policy that will define the role and scope to accommodate the various energy media available in the nation with the aim of promoting a broader development of and utilization of Nigeria’s many natural energy resources. With some emphasis on the place of coal as a viable energy resource, it also provides a clear evidence of the scope to apply knowledge and expertise from hydrocarbon sub-surface systems development, in this emerging industry sector. An outline of the key features of a possible integrated energy policy framework is also presented.
Lower Miocene Sequence Architecture in the Central Swamp Depobelt of the Niger Delta: Impact on Production
Authors: Ebong U.
Published: December 2007

The Lower Miocene strata of the gas-rich X, Y and Z oil fields in the Central Swamp depobelt of the Niger Delta, is evaluated in terms of its sequence stratigraphic architecture. The penetrated interval includes three superimposed estuarine valley-fill sequences (S1: 17.7Ma-16.7Ma; S2: 16.7Ma-15.5Ma; S3: 15.5Ma-13.1Ma). Apart from Field Z where S3 includes a lowstand systems tract, each valley-fill contains a fluvio-estuarine transgressive systems tract (TST) and a highstand systems tract (HST). This stratigraphic architecture appears to have a strong influence on reservoir properties and petroleum resource distribution. The bulk of the total original oil in place in Field X and Field Y, which occurs in narrow, wedge-shaped, discrete/amalgamated, proximal fluviatile-distal marine sand bodies encased in marine shales, are restricted to the 17.7Ma-17.4Ma transgressive estuarine valley fill of S1. In Field Z, the productive reservoir consists of alternation of detached shoreface sand lobes and outer neritic-bathyal shale. This reservoir occurs within the 15.5Ma-15.0Ma lowstand and transgressive systems tract of S3. Highest quality and greatest degree of homogeneity are indicated for Field X and Field Y reservoirs. Sand body geometry and heterogeneity in internal architecture of Field Z reservoir account for the more complex lateral and vertical fluid flow reported from this field.

The new knowledge of the depositional characteristics of the reservoirs and the genetic relationship among the oilfields minimises geological and dynamic uncertainties in the inter-field development plan.

Introduction

The sequence stratigrphic concept provides an excellent tool that addresses the problems of genetic relationships among oilfields and reservoirs, as well as sand development and property distribution. This report which focuses on the Central Swamp depobelt of the Niger Delta, evaluates the sequence stratigraphic architecture of X, Y and Z oilfields (Fig. 1). The three fields were discovered in 1971, 1966 and 1961 respectively. Field Y is separated from Field X to the north, by a major fault and from Field Z to the south by a macrostructure-bounding fault. Each of the three fields contains one major oil reservoir (Field X-E1, Field Y-D7 and Field Z-E2 reservoirs respectively) at depths between 10,000ft and 12,000ft below the surface.

The genetic relatioships of the three fields has remained a matter for speculation. Water injection was started in Field Z in 1981, but was discontinued in 2001 due to inexplicable water losses and persistent steep drop in pressure. To account for this, some schools of thought have speculated that the three major reservoirs might possibly be connected. It was therefore imagined that if production in the more proximal Field X and Field Y caused pressure drop in the more distal Field Z, a common production strategy could be adopted for the three fields.
Successful Matrix Acidizing: Is Guess Work Part of Your Design? Good Engineering Mitigates Uncertainties
Authors: Enelamah Uzodinma C. , Akunna Patrick O. , Poitrenaud Hugues
Published: December 2007

The global demand for oil and gas is expected to rise by an estimated 2-4 percent annually over the next decade while production decline from matured fields is estimated at about 5 percent annually. Well productivity enhancement through stimulation provides a cost-effective way of increasing production, especially in matured fields. This provides both an opportunity and a challenge. The worldwide success rate of matrix acid stimulation has been occasionally reported as low at 20% in some areas, with most operators reporting approximately 50% to 75%.

Case histories of a number of matrix acid treatments of several wells in the Niger Delta, some of which were successful and some of which were not, seem to indicate that the success of a treatment is not a matter of chance. All the successful treatments had one thing in common: they were not only producing with high skin, the damaging material was recognizable and removable. Unsuccessful treatments also had quantifiable skin and the damage mechanism had been identified (to be migrating formation fines), however, the mineralogy of the damaging material had not been accurately identified.

This paper describes the engineering process used to mitigate the uncertainties involved in sandstone acidizing and maximize success rate, including candidate selection criteria, treatment design, and post job evaluation. The paper also presents the key lessons learnt from the case histories and recommendations for future treatments.
Recognition of Sedimentary Facies and Deformation from Borehole Images in Deep-water Environments - Applications from Offshore Nigeria
Authors: Lawrence D. A. , Ros J-B. , Vandenabeele T.
Published: December 2007

Borehole image logs in deep-water turbidite reservoirs have often been used with limited success in sedimentary facies recognition, since many wells are drilled with oil-based muds preventing the use of high-resolution resistivity imaging tools. This paper presents the successful application of acoustic images (UBI1), oil-based dipmeters (OBDT2) and more recently oil-based micro-resistivity images (OBMI3) in enhancing deep-water reservoir evaluation with examples from offshore Nigeria.

Specific aspects highlighted in this evaluation are lithofacies discrimination, syn-sedimentary deformation and structural applications. Continuous ‘image facies’ interpretations, calibrated initially with core, were generated over the entire reservoir-bearing intervals and compared with conventional ‘electrofacies’ identification from wireline logs. A variety of syn-depositional deformation features are recognised, including slump folding, slide blocks and sandstone injection. Careful calibration with seismic, including generation of scaled seismic overlays of dip data, significantly enhances well to seismic calibration and highlights sub-seismic faults that may have been overlooked in reservoir model construction.

This paper highlights the value of borehole image logs in deep-water reservoir analysis, particularly when fully integrated with core and seismic data. Some implications for reservoir model construction are also emphasised.
Integrated 3-D Static Reservoir Modelling of an Onshore Niger Delta Field using Well and Analogue Data
Authors: Iwegbu J. C. , Arochukwu E. C.
Published: December 2007

The interpretation of depositional environment and prediction of reservoir properties in oil fields, where there are no cores, have always been characterised by a lot of subsurface uncertainties. The interpretation of the environment of deposition on the basis of log signature alone increases these uncertainties. This paper shows how the uncertainties in interpreting the environment of deposition were reduced by the integration of data from different sources. It also describes how the interpretation was used in predicting the reservoir properties across the field, thereby enabling the successful modelling of two reservoirs in a field that did not have core data.
Is "Live Annulus" Data Interpretation During Frac Pack Operations Viable Information
Authors: Hale C. L. , Conrad M. A. , Bose M. T. , Parker C. V.
Published: December 2007

The technique of using a "live annulus" for data collection analysis during frac pack sand control completions has evolved quite extensively over the past few years. Field case studies have revealed several anomalies in this data collection and analysis.

The following discussion covers more than 100 wells completed in the Gulf of Mexico using mini frac data analysis on both the workstring and "live annulus" data and their relationship to the bottomhole gauge data. The ability to incorporate this "live annulus" data has been facilitated by downhole tool development.

The use of "live annulus" data has been viewed by many as being the single most important factor in the successful interpretation of pressure analysis during frac pack operations. Certainly, the elimination of friction in trying to interpret real time data enhanced the ability to make "on-the-fly" decisions. Having a "live annulus" also may help in overcoming some of the water hammer problems in rapid closure situations. However, caution must be used in relying on "live annulus" data. A close look at this summary of data completed in the Gulf of Mexico highlights the need for this caution and questions the degree of it s use.
A Recent Gulf of Mexico Cavity Completion
Authors: Palmer Ian , Vorpahl Douglas G. , Glenn John M. , Vaziri Hans , McLennan John
Published: December 2007

Production was dramatically improved by cavitating (intentionally producing sand) an offshore gas well on the Gulf of Mexico Shelf. The cavity completion was conducted over a period of 10 days and involved producing the well through temporary equipment in order to safely produce, collect, and dispose of the produced sand. No hydrocarbon emissions resulted since production could be routed back through the permanent facilities. Following the operations, the well was returned to flow through the permanent facilities at a much higher producing rate, with much lower sand production.

Prior to the cavity completion operations, the well had been choked back to a low gas rate, <1 MMscfd, due to sand production. The low gas rate was insufficient to continuously lift liquids, causing the well to become liquid loaded and/ or slug. The well was evaluated for a sand control completion, but this type of repair was felt to entail too much economic risk due to significant reservoir unknowns. Further evaluation suggested that the well had the attributes for a successful cavity completion.

This paper will discuss the cavity completion evaluation process employed and operational results and learnings. A similar process may be applicable to other wells.
Reserves Addition Due to Minimized Formation Damage With Underbalanced Drilling
Authors: Guo Boyun , Ghalambor Ali
Published: December 2007

This paper provides theoretical analyses of hydrocarbon reserve that can be added by Underbalanced drilling (UBD). For simplicity, the analyses are based on the characteristics of solution-gas-drive reservoirs and deepwater reservoirs. The concept is also applicable to other types of reservoirs.

This paper addresses UBD-added hydrocarbon reserve in two aspects: a) minimizing formation damage so that lower reservoir pressure can be achieved at the same level of abandonment production rate at the end of field development; and b) producing hydrocarbons from those zones in deepwater that are not accessible with overbalanced drilling (OBD) or nearbalanced drilling (NBD).

Our analyses indicate that UBD can add reserve very significantly. An example calculation shows that UBD can increase oil reserves by 7% for a skin factor reduction from 10 to 0 in a low pressure, thin oil reservoir. The same example also indicates that the field development time can be shortened by 38% if the field is developed with UBD. Replacing the high-skin OBD or NBD wells with UBD wells in a depleted field can increase reserves and prolong the economic life of the field. Our analyses of formation pore and fracturing pressure gradient curves from a deepwater field confirm the results of previous studies in that UBD can add deepwater hydrocarbon reserve very significantly.
Rock Mechanics Aspects of Well Productivity in Marginal Sandstone Reservoirs: Problems, Analysis Methods, and Remedial Actions
Authors: Tronvoll Johan , Larsen Idar , Li Liming , Skjetne Tore , Gustavsen Øyvind
Published: December 2007

The paper discusses different mechanisms that may explain field observations of productivity decline. In particular, this work reviews some central issues related to rock mechanical processes that may directly or indirectly result in productivity decline and also possible remediation in sandstone reservoirs. Some emphasis is put on particle plugging of the formation itself, screens and gravel packs, scaling in the near-wellbore region, behind the screen/gravel sand production (including quantification of produced sand volume/damaged zone), filtercake mobilization, near-wellbore rock compaction and effects of water breakthrough on rock properties. All these mechanisms are directly or indirectly linked to rock mechanics aspects through local pore pressure changes and induced deformations of the formation rock. Plugging may further induce rock mechanical failure around the well. Two principles of direct sand control are discussed, i.e. borehole re-enforcement (expandable screens, gravel-packing, propped fracturing, chemical consolidation) and filtering (standalone screens, gravel-packs, frac-packs, pre-packed screens) and their impact on productivity upon reservoir depletion, scaling, sand production, filtercake mobilization and fines migration. Different analyses are used to highlight central mechanisms of productivity alteration and to define design parameters. In particular, chemo-mechanical effects upon water breakthrough are discussed with respect to permeability alteration around the wellbore and scale formation. Further, examples will be given that remedial actions to remove scale and other plugging agents in certain cases may harm the formation mechanical integrity, and result in sand production, rock compaction and productivity decline. An example of a simple laboratory test to quantify such loss of rock integrity will be given. The work demonstrates how rock mechanical analysis may guide the selection of completion method, and how proper diagnosis of well performance and formation integrity may guide the selection and design of remedial actions.
Life-of-Well Approach for Optimizing Production – GOM Case Histories
Authors: Proano Eduardo , Patel Yogesh , Thawer Roxy , Al-Harthy Salah , Gadiyar Bala , John Colin , Morales Hugo
Published: December 2007

A life-of-well comprehensive methodology for production optimization is demonstrated through two Gulf of Mexico stimulation treatments in formations requiring sand control. The approach considers the full well history in the process of well evaluation and candidate selection. The treatments were designed for remediation of damage caused by a time-dependent disruption of formation sand and/or sand-control mechanism, including fines migration, proppant instability, and scaling.

Traditionally, data from permanent bottomhole gauges have been used as a valuable tool for well and reservoir management. As demonstrated in this paper, the data can be crucial to the assessment of the evolution of time-dependent skin. The practical result of well or reservoir surveillance and diagnosis from permanent gauge or traditional production data is shown to produce better decisions on stimulation and production management, while maintaining life-long well integrity.
Optimization of an Oil Soluble Scale Inhibitor for Minimising Formation Damage: Laboratory and Field Studies
Authors: Wylde J. J. , McAra E. K.
Published: December 2007

Oilfield scale formation is dependent upon the production of water; as a result most scale inhibitors are water soluble and deployed using an aqueous phase. For treatment of wells that produce only small amounts of water and/or have water sensitive matrices, the use of an aqueous inhibitor can cause many problems. Even with the development of oil miscible scale inhibitors the same problem can be encountered when the incorrect screening procedure has been used in the laboratory.

This study illustrates the importance of using the correct coreflood protocol when evaluating an oil soluble scale squeeze inhibitor. Examples of different procedures for different types of scale inhibitor show that use of the incorrect procedure can seriously influence the formation damage and lead to misapplication in the field. Three field examples are included, comparing laboratory evaluation and field specific studies of different types of scale inhibitor, explaining why different formation damage mechanisms are seen in the field and sometimes not recreated in coreflood experiments.

The study goes on to describe the development of a range of truly oil soluble scale inhibitors, which preclude any aqueous phases, and have been specifically developed to minimise formation damage caused by aqueous and oil miscible scale inhibitors. The products have been screened for use in several fields which have historically had formation damage issues with both aqueous and oil miscible scale inhibitor squeeze products. Finally, the paper will talk about the consequences this has for field application based upon a field trial using the new, truly oil soluble scale inhibitor.