bluuebunny/crossref_metadata_2025 huggingface dataset:
Continuous Multistage Fracture Stimulation Completion Process in a Cemented Wellbore
Authors: Stegent Neil , Howell Matt
Published: December 2009

Multiple-stage fracturing is a very common practice, especially in reservoirs with microDarcy permeability. The process of perforating, fracturing, and setting plugs has been performed for many years and has both advantages and disadvantages. Coiled tubing (CT) completion methods have increased completion efficiencies but can have limitations as well. Though multistage tools placed in the casing string have become a standard completion practice in horizontal completions, little has been done in vertical, cemented wellbores. As multiple wells drilled on single pads become more common, increased economic completion efficiencies are necessary.

To address the increasing need for completion efficiency, an alternate method of multiple completions was tested in several vertical wellbores. The casing strings were conventionally cemented in place and ball-activated sliding sleeves were placed across target completion intervals. Failures in similar techniques can have catastrophic effects if the initial tool does not open. To address this issue, a new hydraulic-actuated sleeve was developed. It was successfully tested in multiple wellbores and performed as designed. Multiple fractures were completed in a continuous operation with excellent production results.

This completion process can provide an efficient method for multistage fracturing in conventional and unconventional reservoirs in either vertical or horizontal wellbores. It can be used on single-well completions or on multiwellpads.

This process provides an efficient, low-cost alternative to conventional multistage fracturing for vertical and horizontal wells.
Successful Strategies for Dewatering Wells Using ESP's
Authors: Bassett Lonnie
Published: December 2009

Pumping water from a well is a straight forward effort that has been done for centuries. Pumping fluid from relatively shallow wells should be an easy task. Normally a pump is installed in a well, started and then forgotten. This premise does not hold true in CBM wells. In CBM wells, this pumping process can be complicated by many issues unless precautions are taken. This paper is designed to address the basic precautions that can be taken to improve de-watering of CBM wells and will focus on real experiences in producing CBM wells and the steps required to make them economical.

Even though every well is different, this paper will focus on the common areas that are key to getting acceptable performance using an ESP as the primary artificial lift method. As in most pumping situations, success is planned for and not just an accident.Electric Submersible Pumps (ESP’s) best practices for a vertical well: This paper will address the key areas of importance for optimizing operations in a vertical well. The paper will address issues like proper motor cooling, successful operation in turbulent conditions and gas lock avoidance and solids control.This paper will concentrate on these three items and show through real case histories how CBM can be successfully produced through proven dewatering techniques.Electric Submersible Pumps (ESP’s) best practices for a horizontal well: A horizontal well is a place an ESP flexibility can really shine. This paper will identify the key areas that drastically improve the chances of success. The paper will identify the operational differences and the different options in running in a horizontal well compared to a vertical well. It will cover the preplanning required to avoid negative operational issues including gas locking, solids intrusion and optimized drawdown.

This paper will concentrate on these two items and highlight techniques that will increase the effectiveness of utilizing ESP equipment for dewatering.
UV Light Reduces the Amount of Biocide Required to Disinfect Water for Fracturing Fluids
Authors: Gloe Lindsey , Neal Greg
Published: December 2009

Water used to make fracturing fluids usually requires treatment to reduce aerobic acid-producing bacteria and, more importantly, to eliminate anaerobic sulfate-reducing bacteria that can cause a well to go sour. Typically, this treatment is performed with the use of chemical biocides. To reduce the amount of chemical biocides used, a new technology, ultra-violet (UV) light, was tested. The equipment used to generate sufficient UV light to disinfect the large volumes of water needed for fracturing was mounted on a trailer for road mobility (Fig 1). This required modifying the UV light equipment and the way it was installed to withstand oilfield conditions. The effectiveness of UV light in disinfecting water for a fracturing treatment was tested in both a controlled laboratory environment and also on a fracturing location. Serial-dilution tests were performed to examine the effectiveness of UV light in controlling both aerobic- and sulfate-reducing bacteria. The serial-dilution method was chosen because it measures both active bacteria and dormant spores that can become active when placed in ideal conditions.

Bacteria control has recently become an important topic for discussion among the oil and gas industry, although it is still misunderstood by the industry. A bacteria problem can oftentimes be subtle and difficult to detect. Bacteria detection in the field is difficult because many tests take a long period of time or are simply not accurate. New regulations on flowback and produced water have led to investigating ways to reduce the amount of residual chemicals in flowback fluids. Environmental concerns associated with chemical disinfection have led to the move from traditional chemical disinfection to mechanical procedures (Cho 2002). Using UV light to disinfect water on-the-fly for stimulation treatments will greatly reduce the amount of chemical biocides that are necessary. A low concentration of biocide is still recommended to provide a more long-term protection from bacteria as the fluid is pumped through the blender and then downhole. Although the use of some biocide is still recommended, these small concentrations are more likely to be at undetectable levels in flowback waters.
Optimal Use of Vogel's Dimensionless IPR Curve to Predict Current and Future Inflow Performance of Oil Wells
Authors: Chase Robert W. , Shaver Carter A.
Published: December 2009

Vogel’s dimensionless IPR curve is frequently utilized to predict the inflow performance of oil wells. While Vogel’s curve was developed for wells having a flow efficiency of one, i.e. a skin factor of zero, this fact is often ignored even when a well has a flow efficiency not equal to one. It has been widely documented that this usually results in serious over or under-prediction of a well’s inflow performance. This paper points out additional errors that may occur when using Vogel's dimensionless IPR curve to predict the inflow performance of an oil well. It demonstrates how the careful selection of the flowing bottom-hole pressure and resultant single stabilized flow rate will result in more accurate IPR curve prediction. A new, simple approach for predicting future IPR curves is also presented.
Marcellus Shale Post-Frac Flowback Waters – Where is All the Salt Coming From and What are the Implications?
Authors: Blauch M. E. , Myers R. R. , Moore T. R. , Lipinski B. A. , Houston N. A.
Published: December 2009

One of the most prominent unexplained phenomena observed in the Marcellus and some other shale plays is the concentration of dissolved salts in produced waters after hydraulic stimulation. In this paper, we present both geochemical and lithologic laboratory and field data to address the salt question. Is salt being dissolved from the shale, or are deep saline aquifers being breached during hydraulic fracturing? What evidence do we have to support or refute either theory?

To address these questions, over 100 flowback analyses were collected over 18 months from both the southwestern and northeastern regions of the Marcellus Shale play. These data incorporate both cation and anion water analyses in either a full or partial determination of the cation and anion balance. Detailed inorganic geochemical and mineralogical analyses of shale samples were integrated to help determine the presence or absence of physical evidence of minerals that may be the root cause for high salinity. If present in the shale, is halite dissolution desirable from a formation stimulation perspective? If so, is this gain a worthwhile trade when balanced against the costs of returned load water handling and reuse or disposal? This paper provides interpretations at both the regional and local scales to try to explain basinal variations observed in the data. It discusses implications of the phenomenon of high saline frac flowback fluids, along with methods being used to mitigate environmental problems associated with the post-frac flowback water geochemistry.
Reliable Method of Achieving Annular Isolatoin for a Multi-Stage Frachtrue Treatment in an Air-Drilled Hole
Authors: Hamilton Russell , Williams Shannon , Martin James , Stalnaker Chad , Davis Tim
Published: December 2009

With conventional reserves in the United States in a decline, more and more operators are turning to unconventional reservoirs such as shale gas to meet the energy needs of the country. Unconventional reservoirs provide additional economic reserves in the United States through advancements in technologies and new applications for existing technologies. There are a number of shales in the Appalachian Basin that contain trillions of cubic feet of recoverable gas reserves. The Huron Shale, a Devonian aged formation, has been developed since the early 20th century. The Huron Shale is a very low pressure formation and wells are drilled with air to minimize formation damage from drilling fluid. To achieve optimum gas flow, the wells must be stimulated. The most common methods used are hydraulic fracturing with N2 gas only or N2 foam with proppant. There are many studies in the literature with no clear indication of which method is best. The benefits of N2 only are presented in this paper.

Areas of the Huron shale that once showed to be non-productive with vertical wellbores are now being developed through advancements in horizontal drilling and cement-less multi-stage fracture treatments. One of the critical components of a successful multi-stage fracture treatment in a horizontal wellbore is effective annular isolation. Effective annular isolation ensures that fracture placement is known and that the entire length of the lateral is treated. This paper will describe one approach in completing and performing multi-stage fracture stimulations in an air drilled hole using inflatable casing annulus packers and ball activated frac sleeves.
Economic Impact of Reservoir Properties and Horizontal Well Length and Orientation on Production from Shale Formations: Application to New Albany Shale
Authors: Dahaghi A. Kalantari , Mohaghegh S. D.
Published: December 2009

This paper presents a study on the impact of reservoir characteristics such as matrix porosity, matrix permeability, initial reservoir pressure and pay thickness as well as the length and the orientation of horizontal wells on gas production in New Albany Shale.

The study was conducted using a publicly available numerical model, specifically developed to simulate gas production from naturally fractured reservoirs. Reasons for selecting a non-commercial simulator for this study were two folds. First, we wanted to make sure that our results, discussions, and conclusions are accessible and repeatable by all interested operators and individuals that are currently producing or plan to produce from New Albany Shale since the simulator we used is readily available. Secondly, we wanted to demonstrate the utility and ease of use of this publicly available simulation software.

The study focuses on several New Albany Shale wells in Western Kentucky. Production from these wells is analyzed and history matched. During the history matching process, natural fracture length, density and orientations as well as fracture bedding of the New Albany Shale are modeled using information found in the literature and outcrops and by performing sensitivity analysis on key reservoir and fracture parameters.

Sensitivity analyses are performed to identify the impact of reservoir characteristics and natural fracture aperture, density and length on gas production. Economic analyses are performed to identify and rank the impact of the above parameters on the Net Present Value of investing on gas wells producing from New Albany Shale.
Montney Unconventional Gas - Next Generation, An Integrated Approach to Optimizing Wellbore Completions Technology
Authors: Schnell Rodney , Tapper Nicole , Genyk Ryan , Deliu Dalis , Tavakol Habib
Published: December 2009

In this paper we will present the evolution of well construction in the Montney play, technical and economical challenges, and the new synergy developed between drilling and completions.

The financial driver that all operators are facing today is to lower well construction costs. The drilling and completions processes should not be looked at as separate entities but rather as an integrated team. This will allow for the achievement of an optimal solution for overall well construction, a solution that can not be achieved by either discipline in isolation. This paper demonstrates the evolution of a unique completion system that lowers costs in a technically challenging area.

Case histories of two completion methods, swellable packers and cemented sliding sleeve technologies are discussed in detail. The cemented sliding sleeve systems were deployed at a field scale for the first time in North America in the Pouce Coupe area of Alberta, Canada in December 2008.
The Impact of Stimulation Treatment on EUR of Upper Devonian Formations in the Appalachian Basin
Authors: Krcek R. , Aminian K. , Ameri S.
Published: December 2009

This study focuses on how the fracturing treatment design parameters such as the volumes of liquid injected, size and amount of proppant influence the Estimated Ultimate Recovery (EUR), in Upper Devonian formations in the Appalachian Basin. An extensive database containing completion, stimulation, and production data from the Benson formation was utilized in this study. The selection criteria for wells which were ultimately used in the study included wells with single zone completion and long production history with adequate completion data. These criteria eliminated the major uncertainty caused by multiple zone completions or inconsistent production data. The total proppant placed during stimulation treatments was found to be the major variable that influenced EUR. Increasing the total proppant not only increases EUR but also to decreases the number of wells required to effectively drain the reservoir. Subsequent economic analysis provided the basic guidelines to achieve economic recovery from the Upper Devonian formations in the Appalachian Basin.
Fracture-Stimulation in the Marcellus Shale—Lessons Learned in Fluid Selection and Execution
Authors: Houston Nathan , Blauch Matt , Weaver Dalton , Miller David S. , O'Hara Dave
Published: December 2009

This paper provides a look-back review of lessons learned from early exploration to the full-scale development phase of the Marcellus shale in Pennsylvania. Fracture stimulation of over 100 wells has resulted in an in-depth understanding of details needed to achieve optimal frac performance. Much of the necessary learning curve is derived from the empirical testing of theory and what many refer to as "trial and error." The ability to evaluate and capture the best practices and develop them into a standing operating procedure (SOP) is one of the most important aspects in development of a new unconventional play. Lessons learned involving fracturing strategies and technologies to date have greatly narrowed the learning curve enabling more rapid advancement toward full-scale development.
A Simple Operational Approach To Ascertain the Viability of Your Offshore Gas Lift Project Before Fully Committing: The Meji Jacket X and Y Pilot Case
Authors: Nwaochei Francis , Olufemi Adebayo , Eme Vincent , Ibrahim John , Nakpodia Eseoghene , Areo Wole
Published: December 2009

Application of improved Oil Recovery in mature fields is almost inevitable. However, the method applied in the IOR process is dependent on the economics and value of the method. In the Southern Offshore area of Chevron operations, there are huge cost implications in the implementation of gas lift on several offshore jackets.

New facilities for gas lift operation entails the installation of a compressor, liquid knock out equipment, pipelines, manifold configuration and associated piping etc. In many cases, gas lift sourcing might require completely fresh construction of entire facilities, which will involve project development, management costs, infrastructure cost and space limitation especially in the case of offshore locations.

In the Southern Offshore Area of Chevron operations, several wells have quit and require some kind of support to flow to surface. Artificial lift (gas lift) has been identified as the best method to optimize production from the wells reviewed in this case. However, the infrastructure required to implement the gas lift in the offshore location will come at a huge cost and there is a time factor as well to consider to install the infrastructure.

Numerous gas lift opportunities have been identified in the Meji Field (offshore location) which currently has no gas supply. Wells in the shallow, strong water drive, reservoirs of this field flow naturally to terminal water cuts of between 60 to 70%. Based on the observed trend of terminal water cut, the challenge for the team was to quantify the incremental oil gain if this terminal water cut is raised by introducing gas lift. If this proved to be substantial, it will make a case for the expenditure on pipelines and associated infrastructure.

In a bid to confirm that installing the gas lift infrastructure is a viable project, a simple operational approach of installing a temporary piping system was implemented after the necessary engineering analyses which are all discussed in this paper. Other operational methods of confirming the viability of applying artificial lift technology (gas lift) on the jackets were also reviewed with a resolution to utilize the temporary solution. An estimated production gain of about 1105 BOPD from three wells, through gas lift was identified in the field. The total production gain from the simple operation yielded 1540 BOPD.

This paper reviews a safe and simple operational approach to evaluate the viability of a gas lift project in an offshore environment. This was applied on Meji jackets X and Y by using gas from a high pressure source well delivered to the target wells with segmented pipe to ensure deliverability and accelerate production based on a 3-well pilot case on the 2 jackets.
Capacity Building Strategies for the Nigerian Educational System
Authors: Enejo Idachaba Francis
Published: December 2009

The consistent decrease in the quality of the Nigeria educational system over the last decade has continued to pose a serious challenge to the employers, the industry and the Nigerian state. This paper presents strategies aimed at enhancing the quality of the Nigerian educational system. It presents a review of the history of higher education in Nigeria and establishes the role of the industry as the driving force behind the development of research in Nigeria. It also emphasizes the Nigerian student as being intellectually capable of performing at international levels. A model is developed to show the interrelationships between the different parameters that impact on the Nigerian Educational System and this model shows that the quality of the teacher has the greatest impact on the Nigeria Educational System. Practical steps which will enhance the quality of Nigerian graduates are presented for implementation.
Economics of Nigerian Marginal Oil Fields - Identifying High Impact Variables
Authors: Akinpelu L. O. , Omole O. A.
Published: December 2009

Marginal Field Development in the prolific Niger Delta environment has taken on added significance since the Federal Government of Nigeria adopted an aggressive Reserve and Production Capacity development strategy as a launch pad for rapid economic development. The last few years have witnessed a number of developments in this area with the Government approving a new set of fiscal parameters for Marginal field development. Various strategies have been proposed to enhance the economic value from Marginal field Assets ranging from early production systems, to innovative least cost production strategies such as the use of a converted Jack Up Rig with subsea storage, to accelerating production through the use of horizontal wells. These strategies involve significant tradeoffs, sometimes quite sophisticated technologies and cost implications.

This paper examines the economics of Marginal Field Development using the latest NNPC fiscal/regulatory terms of December, 2000 with a view to identifying the most significant variables impacting the economics. From knowledge of the economic variables and their impact, insights into potentially proactive strategies to improve Marginal field economics are developed.

Preliminary studies inform that a much more aggressive production strategy be considered for marginal field exploitation since time value of money considerations have a disproportionately large impact in such economics and should be exploited. The production variable is treated as one of the main uncertain variables in the probabilistic model - Nigerian Oil Economic models are usually production dominated. The option of the Oil Majors taking equity participation in Marginal Field development and hence making available their technical expertise has very low probability of success. The main reason that these fields don't make it to the development stage in the budget allocation process of most Majors is economic. The current strategy in which the Majors negotiate an Overriding Royalty rate with the Marginal Field operator is likely to be the preferred option because it is less risky, does not involve any risk of their capital or other resources, particularly scarce human resources.
Encouraging Experience in the Use of Permanent Downhole Gauges for Well and Reservoir Management
Authors: Igbokoyi A. O. , Afulukwe C. R.
Published: December 2009

This paper illustrates how pressure data acquired from permanent downhole gauges in a shallow water offshore field are analyzed to provide insight into well performance and reservoir monitoring required for key business decisions. A continuous productivity index is generated to analyze the progressive well performance. Near wellbore damage or water influx into the wellbore in the case of unfavourable mobility ratio is easily flagged off. Combination of productivity index, bottomhole flowing pressure and production data provide robust analysis of the well performance based on which quicker decisions can be made on whether a remedial intervention is required or not. Where the right remedial interventions are made, for example when no stimulation is carried out because variation in productivity index is due to increasing water influx and not near wellbore damage, the derivable benefits are sustained oil or gas production, optimisation of recovery, reduction of operational expenditure, all leading to maximised life cycle economics for the well.
Environmental & Safety Management in the Nigerian Petroleum Industry
Authors: Effiong G. M.
Published: December 2009

It is fundamental to the health of any community to have a clean environment. Rapid industrialization worldwide and ever increasing oil operation has brought with it environmental impact on varying dimensions. In the past few years, the issue of environmental protection has been receiving a lot of attention at global, regional, national, state and local government levels. This is because of degradation caused by oil operation thereby making it unsuitable for habitation especially in oil producing areas.

The burning issues in this paper highlight the significance of the environment to man, the impact of petroleum operation on environment, environmental conservation, waste management and safety. It will also create awareness and stimulate the need for efficient planning for safety and management during and post production, impact control particularly from the legal perspective and emphasis the important of enactment of legislation which include environment, health and safety in the scope of certification of oil industries.
Modelling Subsurface Uncertainties with Experimental Design: Some Arguments of Non-Conformists
Authors: Lawal Kazeem A.
Published: December 2009

As a consequence of limited capability for the acquisition, analysis and interpretation of subsurface data, uncertainties pervade the Exploration and Production (E&P) business. To minimise investment risks, robust development plans, premised on adequate understanding of uncertainties, are critical. Experimental Design (ED), complemented with Response Surface Method (RSM), which uses a statistical proxy equation to model the response (dependent variable) as a function of independent variables (uncertainties), is a common method for studying subsurface uncertainties.

In this paper, current applications of ED to subsurface modelling are evaluated from fundamental principles- mathematical and physical consistencies of the proxy equations, as well as robustness in modelling uncertainties. Within the context of modelling and mitigating subsurface uncertainties, major shortcomings of the ED and their implications for decision-making are highlighted. These include inconsistency and non-uniqueness of proxy models, violation of basic theoretical physics, non-preservation of the correlation between variables that are known to be inherently related, non-controllability of input variables, under-estimation of the impact of uncertainties, and the challenge of constructing (interpolating) realistic simulation models from an ED output.

Although ED is consistent with statistical principles, its description of reservoir physics is not satisfactory. In its present form, reservoir complexities are apparently too overwhelming for reliable modelling or optimisation by the proxy models. Consequently, it is recommended that the application of ED be limited to situations where a simple understanding of the effect of a controllable variable on a dependent variable is required, or where the range of uncertainties is well known within a narrow interval. These include production/injection management, ‘model-based’ control algorithms for ‘intelligent’ completions, business planning and similar areas of the E&P business characterised by continuous data, and where the independent variables could be engineered for the desired objectives.
Probabilistic Inversion of Complex Channelised Reservoirs in Deep Water Niger Delta
Authors: Fehintola Tope , Al-Mandhary Inayat , Weaver Sidney
Published: December 2009

In this paper, we will discuss the probabilistic seismic inversion of Bonga main reservoirs, with the objective of updating the reservoir static models with the net sand prediction from seismic.

A unique solution to the seismic inverse problem does not exist. Uncertainties arise from two sources: noise in the seismic data and ambiguities in the inverse problem itself. Ambiguities are mainly caused by the fact that the seismic data are band limited. Most inversion algorithms, often guided by well and horizon constraints, typically produce a single solution. This solution may represent the most likely subsurface model but it does not give information about other possible solutions.

For the results discussed in this paper, we used a trace-by-trace based inversion that relies upon rock and fluid property relationships that describe acoustic properties (Vp, Vs, density) as a function of reservoir properties (e.g. porosity, net-to-gross etc). A prior model is provided as input. This prior model is the initial reservoir static model from which the rock and fluid properties are obtained. These properties are then perturbed in a statistical manner for a number of iterations, deriving acoustic impedances which are used to generate the corresponding synthetic traces. These synthetic traces are then compared with the actual seismic response, and selected against a matching criterion such as semblance. The probabilistic approach combines the seismic modelling with a statistically correct examination of uncertainties taking into account noise in the seismic data. As no well is used to constrain the inversion, this allows for blind well information to be used as validation points for the inversion results.

This procedure, in addition to providing the "most likely" model, also provides a statistical examination of uncertainties.
Quantifying Errors in Present Value Factor Relationships for Restricted/Declining Production
Authors: Akinpelu L. O. , Omole O. A.
Published: December 2009

In the petroleum economics literature, simple relationships for making rapid profitability calculations abound. These simple analytical expressions are quite useful and facilitate quick decision making. One of such is the Present Value Factor Relationship, PVF for determining the Net Present Value (NPV) of a development well under restricted or declining production. In this paper, the present value factor relationship, PVF of a development well under proration is examined. The production profile assumes that there is a period of restricted production and then exponential decline sets in. Continuous rather than discrete discounting of the cash flows is also assumed. It is shown that the PVF relationship commonly employed in the literature is mathematically inconsistent when the assumption of proration is removed. That relationship is replaced with a more precise one requiring very little additional computation and hence preserving the simplicity of the relationship. It is also shown that significant errors can occur when the approximate relationship is used to calculate the NPV for production profiles with low to medium decline exponents, Di and short to medium production lives, t. The longer the life of the field the more accurate the NPV obtained using the simplified PVF relationship since the defined Error factor, Er expression is a decaying (negative) exponential term. In fact for very long development well lives, (τ≈∞); the approximate and precise relationships yield the same results. The defined Error parameter, Er can be easily employed to correct for the results obtained using the approximate PVF relationship. Two worked examples are presented to illustrate the magnitude of errors that can result in the use of the approximate PVF relationship.
Statistical Diagnosis(VEMST) of Flow Regime: Alternative to Pressure Derivative Approach in Pressure Transient Analysis—Part I
Authors: Biu Victor T. , Biu Emmanuel O. , Onyekonwu Mike O.
Published: December 2009

Before the early eighties, identification of flow regime has been a difficult task for reservoir engineer and welltest analyst until the emergence of the derivative approach. This approach has helped to reduce the uncertainties of the interpretation of welltest result because key regions of radial flow and boundary features required for reservoir characterization, description and evaluation have been adequately diagnose. However the approach is complex for non-mathematician and an alternative method for improving its interpretation and reducing the difficulty of its practical application haven't been discovered most especially where there is inconsistency in data sampling.

The statistical approach(VEMST) utilized simple statistical tools such as StatDiff, StatDev and StatExp derived from time series analysis to identify possible unseen features, diagnose key flow regime for reservoir description and act as checkmate/alternative to the derivative approach to interpret complex features.

Result from channel sand, low and high permeability reservoir, infinite conductivity fractures, dual porosity and/or permeability reservoir show same trend as the derivative approach and also diagnose unseen features such as dual permeability, geologically interpreted as layered reservoir system and also double porosity model with high degree of accuracy.
The Implication of Poor Funding on HSE Policy Implementation in the Nigeria Oil Exploration Industry
Authors: Tubosun Fagbe
Published: December 2009

Employers crave for profit maximization with lesser concern for personnel's health, safety and working environment is worrisome and has made implementation and management of HSE Policy difficult for Professional Safety Personnel in the service of most Nigeria Oil and Gas Companies. In the contemporary setting, expert advices on sustainable Human Safety and well being in an appropriate workplace via provision of essential working tools and standard Personal Protective Equipment for safe operation are strictly adhered to by the Company's management. In Nigeria today, opposite seems to be the practice. This paper examines the impact of poor funding on HSE Policy implementation and enforcement capability in a typical Nigeria Oil Service Company. It avows a high and unsteady population influx and a disproportionate in demand for safety equipment, training and working materials budget for the phased Safety development. This paper proffer solution to stemming the HSE Policy poor implementation tide, which includes, appropriate planning, healthy budget, prompt release of fund and unbiased management commitment to Personnel and operational safety.
Artificial Neural Network Modeling of Viscosity and Wax Deposition Potential of Nigerian Crude Oil and Gas Condensates
Authors: Oladiipo Abiodun , Bankole Abidemi , Taiwo Elijah
Published: December 2009

Artificial Neural Network (ANN) based models were developed for predicting viscosity and wax deposition potentials of petroleum reservoir fluids as a preliminary measure to address the problem of loss of production associated with wax deposition.

Several ANN architectures were trained using supervised paradigms for viscosity modeling and unsupervised paradigms for wax deposition potentials. Input to the models is temperature, pressure and viscosity data of the reservoirs. Five Nigerian crude oil and gas condensate reservoir data were used to validate the models.

ANN competitive layer wax deposition model developed in this work excellently identified crude oil and gas condensate potential to deposit wax in upstream and downstream facilities compared to classical regression technique (CRT) based mathematical model.

The inherent problems of tubing and pipeline blockage by wax deposits would be minimized by the application of the predicting models during well development stage prior to production
Expandable Sand Screen Deployment in Cased Hole Completions: SPDC Experience
Authors: Ayoola Olakunle , Nnanna Erasmus , Osadjere Peter , De Landro Wendell
Published: December 2009

In recent years, expandable sand screen (ESS) has become popular as a sand exclusion mechanism in oil and gas sand face completion. ESS provides sand control through the bridging of formation sand on the screen that is sized to retain formation sand while allowing formation fines to pass through. The deployment of Cased Hole ESS (CHESS) in The Shell Petroleum Development Company of Nigeria Ltd (SPDC) since the late 90's has been mainly as a remedial sand control mechanism post-workover operation to replace the previous sand control mechanism if any or to complete over a new interval. The successful deployment of CHESS in over 30 conduits in the Niger Delta by SPDC over the years has come with various challenges and lessons learned leading to improvements in the selection criteria, deployment methodology and procedure, clean-up and operational envelope of usage. This paper presents some of the results and the lessons learned in CHESS deployment in SPDC and offers an insight into the selection and usage of CHESS as a sand control mechanism especially in well remedial operations to prolong well life and optimise hydrocarbon recovery.
Important Considerations in Matrix Stimulation Candidate Selection in Niger Delta
Authors: Nnanna Erasmus , Osuagwu Michael , Okereke Onyedikachi
Published: December 2009

Matrix stimulation improves well productivity through the removal of formation damage in the near-wellbore region of the reservoir. Success and failure of stimulation treatments are often attributable to candidate selection. Lack of a structured approach to candidate selection has had an adverse effect on the outcome of stimulation treatments industry-wide. Where good candidates have been identified, the absence of robust techniques for the determination of damage radius introduces uncertainty on the accurate volume of treatment fluid to deploy.

This paper presents a robust approach to candidate selection based on analysis of the relative impact of various skin effects in the well. Simple mathematical expressions that describe the relative impact of formation damage and partial penetration were also derived. A novel approach for the determination of damage radius is also introduced. The damage radius so determined is considered useful for accurate calculation of matrix treatments volumes.
Improving Production Forecasts through the Application of Design of Experiments and Probabilistic Analysis: A Case Study from Chevron, Nigeria
Authors: Adepoju Olaoluwa , Olufemi Odusote , Djuro Novakovic
Published: December 2009

A reliable production forecast is a critical part of the planning and decision making of companies in the oil and gas industry. The forecasts form part of a company's business and strategic plans and form the basis of evaluating an existing asset, major capital project, or exploration prospect. It therefore follows that generating a reliable and representative production forecast is a key desire of any Oil and Gas company.

There are many factors, surface and subsurface, that affect the reliability and accuracy of production forecasts. All these factors are not single-valued and would generally have a band of uncertainty around them. The challenge therefore is how to generate production forecasts in the face of these uncertainties. Previous production forecasts have been generated using deterministic values for these uncertainties at their end points – 3 forecasts. This method however, does not test the possible interactions between uncertainties which would lead to multiple production forecasts. This method, although reasonable, may sometimes lead to erroneous decisions due to optimistic or pessimistic production forecasts.

This paper describes another methodology which is currently a best practice within Chevron Corporation. This method involves the assessment of the uncertainties using design of experiments and probabilistic analysis using Monte-Carlo simulation. A design of experiment workflow will be presented and the mechanics of incorporating historical data into the workflow will also be discussed. This method enables the generation of a truly probabilistic range of forecasts which can then be used in decision making. A practical application of this method is also detailed in this paper.
Research and Development: Utilization of Local Additive in the Cementation of HPHT Wells in Nigeria
Authors: Joel Ogbonna F. , Iseghohi Prince Theo
Published: December 2009

Cementing of high temperature wells poses a big challenge and requires special considerations in slurry design applications. Among others, the problem of strength retrogression encountered during the life of the well if special additives are not added to the slurry design is critical.

Silica sand is one of such additives that is used to provide strength stability while maintaining good permeability characteristics when static temperature in the zone exceeds 230°F.

It is obvious that almost all of the additives used in Nigeria for oil well operations, including silica sand are imported. However, it is imperative to note that this material is in commercial quantity at Ibi in Taraba State. Moreover, test results indicated that results obtained from lab experimentation as well as field applications with the local silica sand compares favourably with the imported one.

For about four years, this local product has been deployed in Nigeria for high temperature, high pressure wells with huge success. This has resulted in cost savings by oil companies; break through in home based technology in line with local capacity and capability development, a step towards realizing the Nigerian vision 2020.

This paper is aimed at highlighting a local content initiative effort in research and development to source silica sand locally to be used as a suitable alternative for imported silica sand, the success story in field application as well as the challenges for effective implementation.
Vertical Flow Barrier Characterisation in Amenam R4 Reservoir (Nigeria) and Impact on Field Development and Reservoir Management
Authors: Mathieu Xavier , Onyema Uche , Sabatier Lionel , Blanchais Sébastien , Eme Uche
Published: December 2009

In the Amenam–Kpono Field, six of the hydrocarbon bearing reservoirs encountered are currently developed. The Main Reservoir (R4) is characterized by vertically stacked sand bodies with intercalated shale layers, laterally well extended.

In the initial reservoir study, a low vertical reservoir permeability (Kv/Kh=0.01) and maps of vertical transmissibility within these shale layers were implemented in the dynamic model.

In fall 2007, Amenam East well confirmed an excellent lateral communication with Amenam Main Field through the aquifer and highlighted the presence of multi disconnected hydrocarbon bearing flow units within R4 reservoir of the Amenam-East structure.

It was assumed in the initial Field Development Plan that these shale layers would play a crucial role in fluid dynamics and hydrocarbons recovery. The initial dynamic model was used to optimise well location and perforation strategy.

With 35 development wells drilled and almost five years of production (1 st oil in July 2003), the significant impact of vertical shale barriers was confirmed and 4 main dynamic units were identified in the R4 reservoir. Data acquisition during the development phase and early production life of the field with pressure data, interference tests and gas tracers yielded very significant results, essential to optimise the development strategy and to establish a proper reservoir management scheme of the Amenam-Kpono field.

A limited number of corrective actions were implemented, mainly with 4 additional wells in 2007-2008, drilled to sustain pressure and/or to enhance recovery in the under developed R4 bottom unit.
Achieving World Class Condensate Recovery Using Integrated Reservoir Management Practices - Oso 1-Y1 Case Study
Authors: Saborogha I. A. , Mkpasi E. E. , Ogunnusi H. , Leininger S. , Gunther M. , Wanorue E. P. , Ogunlowo R. F.
Published: December 2009

Oso 1-Y1 is a large, mature condensate field located in OML 70, about 45 km from shoreline in the southeastern part of Nigeria. Several geoscience studies for this complex deltaic have assessed Original-Condensate-In-Place (OCIP). Over 63% of the OCIP has been recovered, primarily through miscible crestal gas injection combined with sound reservoir management practices.

In 1987, MPN carried out a pre-production simulation study of the Oso field with the primary objectives of determining the condensate recovery factor, the optimal placement of wells and to obtain an insight into the reservoir behaviour under gas injection. The results indicated that the highest recovery factor (70%) would best be obtained by miscible gas injection. Additional simulation results post-production also estimated recovery efficiency of 72%. Actual production performance indicates a 74% recovery versus 55% average usually obtainable for gas-condensate reservoirs.

Although crestal miscible gas injection is the main recovery mechanism, different tools that use real-time production performance have also been concurrently utilized to continually optimize and update the depletion plan as required/necessary. These tools include adequate pressure monitoring to determine pressure trends and track efficiency of gas injection while monitoring miscible gas front movement and ensuring optimum contact closure. In addition, Integrated Production Model (IPM) updates are done periodically to confirm condensate remaining-in-place and recoverable volumes, assess infill opportunities and optimize production. The main objective of these tools is to reduce unswept condensate, condensate lost due to retrograde condensation and hence improve recovery.

This paper will focus on how the application of various reservoir management practices have been integrated to develop an ever-green depletion plan in order to optimize production and achieve world class recovery from a structurally and stratigraphically complex condensate field.
Comparative Evaluation of Models for Joint Venture Agreement and Production Sharing Contract Fiscal Systems in Nigeria
Authors: Mmakwe I. , Ajienka J. A.
Published: December 2009

Joint venture agreement and Production sharing contract are the two most common fiscal systems for petroleum operations in Nigeria. In this study, models were developed and compared for Joint venture agreement (JVA) and Production sharing contract (PSC) for the Nigeria fiscal systems. The results showed that the government has more take and a higher NPV under the JVA than the PSC. Sensitivities were carried out for the NPV and the results showed that NPV was most sensitive to oil price.

An approach was also developed, based on the percentage loss in NPV of the contractor and community take, that serves as a guide for the contracting firms and JVA partners to determine how much should be given to the host community in such a manner that will not significantly affect their NPV and yet achieve their social responsibility.
Estimation of Developed Reserves in Gas Lifted Wells
Authors: Daniel A. , Isehunwa S. O.
Published: December 2009

Reliable estimates of petroleum reserves are invaluable in reservoir management decisions and economic evaluation. Classical decline curve analysis techniques have been routinely used and are generally accepted in the industry to reliably estimate developed reserves up to a predetermined economic limit qec in oil wells. However Decline curve analysis techniques are based on the assumption that past production trends and their controlling factors will continue in the future and therefore can be extrapolated for predictions.

During gas lifting, production trends could be distorted hence there is need to modify the classical decline curve analysis equation. In this study, the principle of superposition has been applied to the entire duration of production (t) of wells producing under gas lift. This resulted in the so called Double Semi log equation for well decline analysis. Model validation with two fields in the Niger Delta area show excellent results and the economic advantage of gas lifting. The Models showed excellent correlation coefficients with available field data.

It is concluded that gas lift could increase the reserves in some wells. Furthermore the Double Semi log technique provides a better and more reliable theoretical foundation, easier and more reliable technique for decline analysis in gas lifted wells.
New Bubblepoint Pressure Empirical PVT Correlation
Authors: Ikiensikimama Sunday Sunday , Ogboja Olu
Published: December 2009

Knowledge of bubblepoint pressure is one of the important factors in the primary and subsequent developments of an oil field. Bubblepoint pressure is required for material balance calculations, analysis of well performance, reservoir simulation, and production engineering calculations. New bubblepoint pressure correlation based on data from the Niger Delta crude oils has been developed. Both quantitative and qualitative assessments were employed to evaluate this correlation which is compared to the best existing bubblepoint pressure correlation for the Niger Delta crude. The new correlation outperformed the best existing correlation by the statistical parameters used with a rank of 7.3 and better performance plot.