bluuebunny/crossref_metadata_2025 huggingface dataset:
The First Use of Gravity MWD in Offshore Drilling Delivers Reliable Azimuth Measurements in Close Proximity to Sources of Magnetic Interference
Authors: Matheson Elizabeth , McElhinney Graham , Lee Richard
Published: December 2007

Measurement While Drilling (MWD) is the preferred method of surveying a well bore when drilling deviated wells. MWD has an advantage over other types of surveying in that the tools are part of the Bottom Hole Assembly (BHA) and surveys can be obtained quickly without the need for interrupting the drilling operation to run a separate surveying tool. However, like all magnetic survey instruments, MWD is susceptible to magnetic interference. The directional azimuth information becomes unreliable when in close proximity to sources of magnetic interference such as casing strings or adjacent wells.

This paper describes a new method of MWD surveying which includes a second accelerometer sensor package to derive azimuth rather than using magnetometers. It is therefore not prone to magnetic interference and the same drawbacks as conventional MWD. The technique uses the inherent bending of a BHA between the two sets of accelerometers in order to measure the relative change in azimuth.

Two case histories are outlined where this technique was successfully used to sidetrack two near vertical wells from directly below existing casing strings despite the presence of magnetic interference. In both cases, the ability to initiate the build as early as possible was important as it provided the greatest possible chance of achieving the relatively tight directional plan.

The use of Gravity MWD may provide considerable cost savings compared to alternative techniques that could incur additional rig time, be sensitive to movement and may not be capable of including real time Logging While Drilling (LWD).
A Pressure Activated Deployment System for Openhole Memory Logging Tools and its Application in Directional Wells
Authors: Spencer M. C. , Ash S. C. , Elkington P. A. S.
Published: December 2007

Openhole memory logging was introduced in 1999 as a more efficient alternative to pipe conveyed wireline logging. It was developed subsequently into a shuttle system that conveys logging tools inside drillpipe, and which provides formation evaluation logs after drilling to supplement basic real-time logging-while-drilling (LWD) data. The original shuttle design used a dart pumped from surface to move the logging string into open hole after the assembly reached TD. In a new development, the dart has been eliminated together with the associated pumping time. In its place is an electro-mechanical pressure activated release mechanism capable of simple two-way communication. The method has been used in trials to activate and deploy logging tools downhole, and to return status information to surface. It has the potential to be developed further for post-drilling real-time data transmission, and is a key component in a repeat formation pressure tester being developed for memory operations.
Multilateral / Intelligent Wells Improve Development of Heavy Oil Field – A Case History
Authors: Rump Pascal , Bairagi Ronjoy , Fraser John , Mueller Klaus
Published: December 2007

Multilateral systems provide production from two or more wellbores and Intelligent Well Systems provide control over production. The combination of these complementary technologies can lead to future wells offering maximum reservoir and production efficiency.

Although both Multilateral and Intelligent Well Technologies have been available to the industry for many years, it is only recently that wells offering both capabilities have been installed. One reason for this hesitation in recent years has been the perceived risk of each technology and the concern with overall project risk when considering a combination of the two technologies. But many of today's multilateral and intelligent well systems have evolved to the point that low risk, highly flexible combinations of these two technologies are fully compatible and feasible in a variety of well situations.

A cost-effective Technology Advancement Multilateral (TAML) level 3 junction system was successfully installed in three horizontal dual-lateral production wells in the Mukhaizna heavy oil field. The junction allows for installation of 7" liners in both legs and selective access to each leg while providing suitable barriers to sand production. This paper will highlight a recent well installation in Oman that successfully utilized both multilateral and intelligent well technologies. The intelligent completion was installed in conjunction with a shrouded Electrical Submersible Progressing Cavity Pump (ES-PCP) lift system, a world's first. The single-valve hydraulic-operated system allows semi-selective zonal control and production testing for cost-effective reservoir management. As will be detailed, in addition to offering the flexibility demanded of a high technology well, this well also shows that such a system can be easily installed with minimal risk.
Surface Facilities Considerations for the Production of a Large Sour Gas Resource and the Injection of Sour and/or Acid Gas
Authors: Sourisseau Kenneth D. , Ibrahim Ibrahim Ahmed , Al-Jabri Adel , Wetzels Guus
Published: December 2007

An on shore reservoir containing a large volume of lean sour gas with hydrogen sulfide and carbon dioxide concentrations of 30 mole % and 10 mole % respectively was considered for production. A study was conducted to determine the feasibility of producing this gas and injecting the sour gas or the acid gas components in adjacent reservoirs. Production, processing, and injection of this gas requires extensive surface facilities. Equipment is required to handle the drop out of elemental sulphur that is expected to occur as the gas is produced. Large gas sweetening units are required, as well as large sour gas compressors. Dehydration of the sweet gas stream is required and dehydration of the injection gas stream is also proposed. Energy integration and heat recovery is an important consideration in the overall plant design. This paper describes the required surface facilities and presents the process, material and energy balance considerations that have been incorporated in the design.

Study Overview

Significant undeveloped sour gas reserves exist in Abu Dhabi. A feasibility study was conducted in ADNOC with the aim to increase sweet gas availability by unlocking these resources. The sweet gas could be the product of sour gas treating, the result of displacing current sweet gas injection volumes, or a combination of the above.

The source reservoir under study contains various zones with different conditions, but the average conditions of the sour gas reservoir used in this study are 380 bara and 142°C.

The average dry gas composition of the reservoir is:55.9 % methane,33.2 % H2S,9.5 % CO2,1.0 % hydrocarbons in the C2-C7 range, and0.4 % nitrogen.

Trace quantities of carbonyl sulfide and mercaptans are also present. The reservoir fluid is assumed to be saturated with water at the reservoir conditions. A calculated water content of 29.4 g/m3 was used. Experience and theoretical considerations indicate that the reservoir fluids are likely to contain elemental sulphur that will drop out of the fluid as it is produced. The well tests did not specifically look for elemental sulphur, but there is anecdotal evidence that the well test tubing was plugged during testing. A conservative design approach was taken, assuming that the reservoir fluid is saturated with elemental sulphur at reservoir conditions. Calculations based on data from Alberta Sulphur Research1 indicate a sulphur saturation of 7.5 g/m3. Reservoir volume estimates and production engineering work indicated that an initial raw gas flow rate of 22.5 106 m3/d would be optimal for the project.

Sweet gas from the project has to meet the normal pipeline specifications of:maximum H2S 20 ppmv,minimum LHV 33.7 MJ/m3,hydrocarbon dewpoint at 39.2 bara of -5°C,water dewpoint at 39.2 bara of -30°C, andthere is no maximum total sulphur specification.
Predicting Carbonate Scale in Oil Producers from High Temperature Reservoirs
Authors: Ramstad Kari , Tydal Trine , Askvik Kjell Magne , Fotland Per
Published: December 2007

Calcium carbonate scale is a common problem in the oil industry leading to reduced well performance and obstruction of the safety valves. Recent field experiences indicate that scaling may be a problem at lower Saturation Ratio (SR) than earlier anticipated. In a high pressure, high temperature Scale Cell crystal growth in synthetic formation water has been studied. Induction times and growth rates have been determined using a microscope cell. The results have been interpreted using nucleation theory. The findings indicate that wells may be safely operated at SR below 2.5 at 85°C. At higher temperature crystal growth is less dependant on SR and the temperature dominates the system. Care should therefore be taken when operating wells at temperature above 100°C.
Enhanced Scale Management through the Application of Inorganic Geochemistry and Statistics
Authors: Webb Philip J. , Kuhn Oliver
Published: December 2007

The surveillance of oil and gas production systems for evidence of scale deposition commonly involves trending well inflow performance, pressure, temperature, rate of flow and the composition of produced water. Surveillance using produced water composition data can be improved by the application of geochemical understanding of formation waters, including the processes that controlled the evolution of formation water composition. Also, use of multivariate data analysis (MDA) techniques provides methods that can resolve subtle and significant differences, and increase the reliability of information derived from produced-water composition data. MDA provides a systematic method of evaluating data as a whole as opposed to single variable investigation, which can overlook significant information.

The information derived from geochemical understanding of formation waters and MDA can also benefit reservoir and production management, for example reservoir compartmentalisation studies and subsea production allocation.

Shell Exploration and Production UK Ltd's operations in the North Sea have benefited from a combined application of geochemical understanding of formation waters and MDA. In addition, formation water composition data derived from residual salt analysis (RSA) of reservoir core has provided additional data for several fields, which has assisted produced- water data interpretation and reservoir management. Examples of the benefits include the case of the ETAP Heron Cluster fields, where well-intervention costs in excess of £1 million per well were saved. The Bittern field benefited from postponement of scale-squeeze treatments when erroneous tracer observations suggested injection water breakthrough had occurred. HPHT prospects in the Central Graben have been assessed for the risk of halite deposition before drilling based on regional studies.
Assessing Scale Risks and Uncertainties for Subsea Marginal Field Developments
Authors: Graham G. M. , Collins I. R.
Published: December 2007

The risks and uncertainties associated with scale control in new field developments can often have a significant impact on the field economics. This can be especially true for marginal subsea fields producing from areas with high barium concentrations in their formation waters. Other aspects such as completion design, reservoir formation and heterogeneity also have a significant impact both on the severity of the scaling potential and also the ability to effectively treat production wells via conventional bullhead squeeze treatments. In this paper we describe an analysis that was conducted during the Pre-Front End Engineering and Design (FEED) stage of a field in the Norwegian sector of the North Sea. The field was expected to produce hydrocarbons from two subsea templates located 1.6km and 6.3km from a floating production system over a field life of ~ 10 years. Seawater injection was preferred over gas injection for pressure support owing to the higher predicted hydrocarbon recoveries. Of particular concern was the high barium concentration of > 700 ppm recorded from an appraisal well water sample, indicating a very severe barium sulphate scaling potential with raw sea water injection. For this field, in addition to the very severe potential barium sulphate scaling regime, a number of factors combined to present an exceptionally severe risk to the fields net present value. This related to: subsea completions with multiple production wells co-mingling at the wellheads (although dual production lines were incorporated into the design plan partially to assist in scale management); and long (500 - 700m) horizontal production wells and completion designs involving open hole screens served to increase the risks associated with scale formation and effective chemical placement. A range of alternative options were examined together with the associated risks and uncertainties. In summary, the most significant risks and uncertainties associated with the economic viability for seawater injection in this field related to: Uncertainties associated with the initial formation water composition.The ability to squeeze treat wells without inducing fines mobilization and plugging sand control screens as observed in analogue fields.The ability to effectively place scale inhibitor treatments along the length of the horizontal producers by bullhead treatments rather than coil tubing operations.The potential for changes in the base case field production scenario

This work therefore allowed the design team to make informed decisions at the pre-FEED stage in a field where scale control had a significant impact on the fields economic viability.
Forecasts and Alternative Analysis for Sulphate Removal or Chemical Treatments for Barium and Strontium Scale Deposition - Offshore Brazil
Authors: Mota R. O. , Bezerra M. C. M. , Rosario F. F. , Prais F.
Published: December 2007

Waterflood projects in oil fields cause important thermodynamic effects in the aqueous phase, resulting in precipitation of insoluble salts due to changes in physical parameters.

Giant fields offshore Brazil are operated by waterflooding. For some of the fields, injection of seawater, rich in sulphates, is not compatible with formation water that contains barium or strontium. Adding seawater to connate or aquifer water leads, during the field production life cycle, to saturation of certain compounds and hence their consequent deposition.

Decision about prevention or remediation of barium and strontium deposition must be attained during the conceptual phase of the field development plan. So, forecasting of the possibility of occurrence of this problem may have a strong impact in the water injection system design specifications and the well completion and interconnections to the floating production unit.

The scope of this paper is to present the results of the analysis conducted to investigate the scale deposition potential in Marlim Leste field, Campos basin, offshore Brazil.

Estimates of intensity of occurrence of precipitation and the critical locations have been conducted in order to obtain the fraction of seawater in the produced brine, which is an important information for evaluation of the problems associated to scale deposition in producing wells.

Based on these simulations economic feasibility studies (CAPEX versus OPEX) compared the alternatives of sulphate removal plants or well treatments with chemicals in order to obtain the final decision of what to implement in this field.
Scale Inhibitors for Co-Deposited Calcium Sulfate and Calcium Carbonate in Squeeze Process in White Tiger Oilfield
Authors: Tung Nguyen Phuong , Phong Nguyen Thi Phuong , Long Bui Quang Khanh , Duy Nguyen Hoang
Published: December 2007

Co-deposition of calcium carbonate and calcium sulfate scale was detected in the some of the wells in the White Tiger oilfield, but, up to now, not much attention has been paid to this problem. In fact, these salts (calcium carbonate and calcium sulfate) co-exist and co-precipitate in the system of seawater and squeeze (injected) water. The mixed CaSO4-CaCO3 scale was found to adhere to a test tube wall more strongly than the pure CaCO3 or CaSO4. More importantly, the treatment of this mixed scale in the field is much more difficult.

This study investigates the inhibition efficiency on mixed scale by using scale inhibitors such as DETPMP, EDTMP, and Lab of Magnetochemistry and Production Chemicals - Institute of Materials Science-NCST) and the chelants such as citric acid, maleic acid and ethylenediamintetraacetic acid. The experimental results show that the mixed DETPMP: MA in ratio 4:1, 1:1, and mixed DETPMP:CA in ratio 4:1; 3:1, and mixed DETPMP: EDTA (2:1) have given the high inhibition efficiency of 98.32%; 93.85%; 96.09%; 96.09%, 92.52% for mixed scale CaSO4-CaCO3 inhibition. These precipitations were analyzed by Scanning Electron Microscopy (SEM). From the SEM photos, it can be observed that for the pure CaSO4 in seawater, the crystals exhibited long needle shape structures (which is typical for calcium sulfate dihydrate) whereas the hexagonal structures were observed for the pure CaCO3 precipitant, which is a typical structure for calcite. In the mixed system, the morphology of CaSO4-CaCO3 crystals changes and spherical shape crystals are predominant. In the presence of the inhibitors, especially with the right inhibitors, the morphology of mixed scale changes and the size of crystals strongly decreases (from 100μm decreases 1-2μm) and are non-adherent. The relation between the inhibition efficiency and the scale morphology for CaSO4-CaCO3 deposits were clearly illustrated.
Old Working Relationship Model Test in a New Location — Integrated Project Management in Western Siberia
Authors: Lischuk V. Y. , Aker H. G. , Bakici M. A.
Published: December 2007

The history of integrated services is a decade old, yet the concept has found new application. A new contract model whereby certain services were contracted to drill horizontal wells on a lump-sum fee basis enhanced the existing relationship between operator and service company. The workscope covered provision of downhole drilling services, tools, and equipment to a maximum total measured depth. Conventional and slim design well options were considered, and equipment specifications were decided to provide flexibility, depending on ongoing reservoir modeling results and production forecasts.

A joint project team consisting of the operator and three principal contractors (namely integrated drilling services, drilling fluids, and rig) spudded the first well in January 2003 with a heavy land rig in the arctic drilling environment. Drilling of the first well with a conventional well design (8 1/2-in. horizontal drain) took longer than initially planned, partly because of high nonproductive time (NPT) that was related to harsh winter conditions, and partly because of workscope changes. However, the second well was finished as the fastest horizontal well drilled to date by the operator, in two-thirds of the scheduled time. Slim-well design, fit-for-purpose equipment and technology selection, improved mud system for intermediate hole sections, and close operational coordination among four participating companies were among the factors resulting in the benchmark performance.

Another key component of the success has been setting of project objectives and targets for quality, health, safety, and environment (QHSE) issues, which were also reviewed by an experienced project startup audit. The review identified critical areas for improvement and thereby facilitated the project's success. The remedial work plan based on the review contributed to the performance improvement in a short time.
A Safe Approach to Underbalanced Drilling in H2S Producing Fields
Authors: Coy Alejandro , Hall Don , Vezza Matt
Published: December 2007

This paper describes a safe and successful horizontal drilling operation on an H2S producing well, using underbalanced drilling (UBD) techniques. The well had been prematurely terminated after using conventional drilling practices that resulted in massive losses and posed the risk of stuck pipe; but, through proper planning, UBD allowed the operator to increase the horizontal length of an existing well. Initial production rates were substantially higher than the rates observed before drilling the UB lateral extension.

The drilling and production results were significant to the future operational potential and viability of this mature field. Equally important was the prodigious success from a health, safety and environmental (HSE) perspective because the field has a 4 percent H2S producing gas cap. Traditionally the industry has been reluctant to use underbalanced techniques in this type of environment.

Located in West Texas, the Yates field was discovered in 1926 and is one of the largest oil reservoirs in United States. Its shallow reserves have been accessed mostly with vertical wells. Over the last few years, implementation of a horizontal well program has made significantly affected on the overall production performance of the field.

The field maintains its reservoir energy by N2 injection into the gas cap and from field-produced water injection below the oil leg.

Low reservoir pressure and highly productive rock in both the gas cap and the water zone present challenges to maintaining underbalanced conditions. These conditions caused wells drilled previously by conventional methods to incur severe lost circulation on encountering a fracture system. The lost-circulation problem resulted in premature suspension of drilling operations. As a consequence, many wells did not achieve long lateral lengths.

This paper discusses the well design and the underbalanced modeling considerations (taking into account detailed reservoir properties). The paper also describes the process used to address HSE issues of the project in the face of the potential presence of high surface of levels H2S while drilling.

Extending the well length underbalanced and intersecting additional fracture sets without losses resulted in an eightfold production increase.
Subsea Rotating Control Head Shop Testing – A Key Step to Assure Subsea Reliability
Authors: Hannegan Don , Bailey Tom , Chambers James
Published: December 2007

Several deepwater drilling-related and environmental issues have dictated a need for the development of a Subsea Rotating Control Head (RCH). Such a tool may also be referred to as a Subsea Rotating Control Diverter. It’s purpose is to effect more precise pressure management by enabling annulus returns containment, diversion, and/or backpressure to be applied on the wellbore in a subsea environment.

Practical applications of such a tool generally fit within the IADC definition of Managed Pressure Drilling (MPD) and include:Alternatative technology to current industry practice of Pumping and Dumping sometimes huge quantities of a heavy viscous mud to the seafloor as a means of overbalancing relatively shallow-to-the-mudline geohazards (abnormally pressured aquifers, gas) when establishing subsea top holes, drilling without a marine riser.For the practice of dual gradient riserless drilling where mud and cuttings may be returned to the rig, this were a subsea RCH diverts returns to a subsea pump.For cost effective riserless drilled exploratory "throw-a-way" or "punch & go" wellbores. Here a subsea RCH with ROV operated choke enables greater wellbore pressure than the mud gradient itself would impart. More precise pressure management is achieved with the pre-selected drilling fluid, resulting in a simplified casing program and deeper open hole.As a component required in a proposed Rierless Top Hole Drilling Package for casing less wellbores when collecting scientific cores in deep water.And, when deployed within a subsea BOP, marine riser, or riser gas handler, function as a subsea annulus barrier, enabling the practice of several variations of dual gradient deepwater drilling.

Given the importance of reliability of subsea equipment in general, shop tests that mimic subsea conditions are warranted. Such test results confirm or otherwise quantify a design’s fitness-for-purpose.
Innovative Remedial Cementing Solution Provides Annular Isolation in Duyong B-4, Petronas Carigali
Authors: Morris Thomas C. , Bidi M. Zuki , Elmarsafawi Youssef , Nair Devan , Said Rifat , Tugcu Reha , Ong Jane
Published: December 2007

Whether a cement-squeeze operation results in an annular seal depends heavily on how far the cement can penetrate and disperse in the fine channels of a partially cemented annulus. In many cases, conventional or microf ine cement slurry will dehydrate and bridge off before it can achieve its objectives. This paper describes the use of engineered, optimized slurry for a squeeze operation in the Duyong B-4 well, which had a perforated zone that demonstrated a low rate of seawater injectivity. This paper also presents the slurry design and properties, execution procedure, and prejob and post-job log evaluations.

After several years of production, gas bubbles appeared in various locations throughout the Duyong field. Shallow seismic showed gas charging in several shallow gas layers throughout the Duyong field. Several wells were investigated as possible contributors to the charging of the shallow sandstone layers, and Duyong B-4 was selected as a probable contributor. Duyong B-4 is a gas well completed in November 1983 with four producing zones. In September 2003, this well was selected as a test well to evaluate the cement quality behind the casing. Both cement bond logs and ultrasonic imaging logs showed gas and fluid channels behind the casing. An optimized cement slurry (OCS) was engineered and tested in the laboratory under the well conditions. Results showed excellent penetration in narrow gaps, optimum fluid-loss control, and low rheology, both at surface and downhole con ditions.

The slurry was used in the squeeze operation; post-job logs demonstrated the success of the treatment. The slurry penetrated the narrow gaps without dehydrating, and good mechanical properties were achieved in short setting times. These properties are especially important in gas-producing wells and they met all the objectives set forth by the client.
The Cement Slurry Inflating External Casing Packer Technology and Its Applications
Authors: He Yurong , Yu Jinling , Liu Qingyou , Hu Qin
Published: December 2007

Lot’s of well-completion challenges face operators to exploit comprehensive reservoirs and old oil field, such as interzonal channeling, up water and bottom water etc. The conventional well completion ways can’t solve them effectively. For example, cementing method couldn’t isolate well for the short interval between layers, otherwise it will contaminate the reservoir, and normal inflating External Casing Packer (ECP) method couldn’t do well for its short life downhole and low isolation pressure. Recent advances in one of the old well-completion ways, namely Cement Slurry Inflating External Casing Packer (CSIECP) technology, will play a key role in meeting these challenges.

This significant technological breakthrough made it possible to inflate several ECPs with cement slurry in one well profile. The CSIECP technology provides permanent and dependable isolation between layers because cement slurry will solidify to be cement stone. So this technology will benefit for producing and later stimulating operation, avoid cement slurry contaminating the reservoir, and raise output.

The Drilling Technology Research Institute of Shengli Oil Field studies this technology and puts it into application firstly in 2002, P.R.China. The technology consists of three key techniques: special tools, high quality cement slurry and advanced process. This paper will give them detailed description including their properties and results of large-scale testing.

In addition to a description of the technology research, the paper will present applications of CSIECP technology in Shengli Oil Field. Some are used to seal thin layer channeling, and some are used as isolation for stimulating operation and producing apart. More than twenty wells’ applications show how this significant technological breakthrough provides cost-effective solutions to several completion problems that have loomed as obstacles to comprehensive reservoir exploitation.

The CSIECP technology is not only an important technical measure to develop thin-bed reservoir, but also one of the effective well completion technologies for extended-reach and horizontal well. It has great economic and social benefits.
Mature Field Re-entries Utilizing Level 4 Multilateral Technology
Authors: Yuan Fucun , Li Wenyong , Durst Doug G.
Published: December 2007

Beginning in year 2000 ConocoPhillips China Inc. has successfully been developing the remaining reserves of the Xijiang fields in the South China Sea through the use of a cost effective low risk multilateral re-entry program. In mature fields with platforms slot constrained multilateral technology provides a solution that allows for full bore access to the lateral while maintaining the value of the existing well bore production thereby increasing ultimate recovery. Through the use of multilateral technology ConocoPhillips gained the additional benefit of minimizing hole collision problems in cluster wells. A very routine level 4 multilateral junction system has been used repetitively and successfully adding value to the overall project. See Fig. 1.Figure 1Primary Level 4 (StarBurst™ system) MLT components
Using Expandable Liners in Deep High Pressure Wells : A Case Study
Authors: Al-Saleh Ali , Al-Kandari Ayad , Al-Fayez Fayez , Brewster T. W.
Published: December 2007

Sabriya 72 (SA-72) is a deep vertical high pressure well originally drilled in North Kuwait in 1983 which was temporarily abandoned due to stuck pipe. The last intermediate casing was set prematurely above the base of a critical highly pressured salt section. Due to the importance of the SA-72 location to appraise a newly discovered field, economics favored re-entering this well in 2003 and sidetracking directionally to intersect suspected fractures in the Jurassic Marrat carbonate formation.

The main challenges of this well were to sidetrack to the target depth without compromising well integrity, and to test the well with the largest production liner possible.

In order to meet these challenges, several first time technologies to Kuwait Oil Company were planned and utilized in this well. These new technologies included running a 6" x 7 ¾" expandable liner, as well as utilizing Near Bit Reamers (NBR), bi-center bits, and slim hole sidetrack techniques to prepare the hole for the expandable liner and to drill to total depth afterwards. An unprogrammed 6" x 7 ¾" expandable patch was also installed in the 7 ¾" production casing to repair a severely damaged area.

Due to unforeseen complications, this is also the first time that the expandable technologies have been used in a 19.7 ppg mud weight. Although the expandable tubulars were run successfully, severe lost circulation after drilling below the expandable changed the course of action and thus the final completion of the well.

This paper will be a case study that discusses the planning, implementation, and lessons learned from the utilization of expandable technology on SA-72.
Pressure Behaviour of a Well Between Two Intersecting Leaky Faults
Authors: Abdelaziz Bensadok , Tiab Djebbar
Published: December 2007

Traditionally if a multiple boundary is suspected in a hydrocarbon reservoir, it is analyzed for its location from the well and its degree of leakage if it is a single communicating fault. Although a well in multiple leaky boundaries presents a very important flow problem in conventional reservoir engineering, no comprehensive method exists in the literature to determine the location of the well relative to each of the leaky boundaries or to determine their degree of leakage and consequently pressure drop caused by these leaking faults in the reservoir.

This study presents a new analytical solution for the pressure behavior of a well near a leaky fault. An extension of the well imaging technique to model multiple leaky boundaries using the new analytical solution which is helpful to generate type curve plots. A study of the pressure and the pressure derivative behavior for a well in multiple leaky boundary systems for different boundaries such as (a) well near a single linear leaky boundary, (b) well between two intersecting leaky boundaries forming an angle of 120°, 90°, 60°.

The solution obtained can be used to improve the design and analysis of both a drawdown and interference tests between the wells separated by partially communicating faults. Type curves generated by these solutions will yield separate estimates of the formation transmissibility and the transmissibility of the fault itself. An explicit solution developed for drawdown at the active well offers the possibility of deriving fault transmissibility from the drawdown and buildup behavior of the active well. This method could be used if a convenient observation well is not available for interference testing. An extension of the well imaging technique allows modeling the leaky boundaries such as two intersecting faults when the well is located any where between them. Pressure and pressure derivative behavior of a well located any where between two intersecting leaky boundaries for different angles shows that the finger print is unique for a determined angle, the location of the well, and the specific transmissibility ratio of the two boundaries.

An accurate correlation between the transmissibility and the maximum pressure derivative has been established and Tiab's Direct Synthesis (TDS) technique is applied to interpret the pressure and the pressure derivative response of a well near a leaky fault. A new parameter, called leakage coefficient, has been introduced to describe a partially communicating fault in case of two intersecting faults. It has been found that the leakage coefficient has direct relation with the transmissibility ratio. Several analytical correlations relating reservoir parameters with the different characteristic points and straight lines in the pressure derivative curve have been developed. Several examples describing the various fault and well locations, fault properties, and angle between the faults are included to illustrate the use of the technique developed.
Analysis of Multi-Rate Test Data Distorted by Wellbore Storage
Authors: Sulaimon A. A. , Omole O.
Published: December 2007

A new method for analyzing multi-rate well test data distorted by wellbore storage is presented. The approach affords a reasonable analysis in the Early-Time-Region (E.T.R) where analysis by the existing models is impossible due to afterproduction and skin effect.

The technique handles variable flow rate by an exponential flow rates solution. Applying the principle of superposition, the additional pressure drop due to wellbore storage was accounted for to provide reliable estimates for the Pressure-Rate-Time-Function (P.R.T.F) in the early time region. A computer package utilizing regression analysis was used to test and validate the model with two field examples.

The assumptions concerning the reservoir and well system are those of the conventional analysis methods that employ the line-source solution.
Managing Uncertainties in Hydrocarbon-in-place Volumes in a Northern Depobelt Field, Niger Delta, Nigeria
Authors: Akinwumi Femi V , Arochukwu Elias C. , Abdul-Kareem Abiola S.
Published: December 2007

Petroleum resources represent a significant part of a company's upstream assets and are the foundation of its current and future upstream activities. Often times, at the discovery of a new field or extension of an existing field, there are uncertainties associated with quantifying the amount of hydrocarbons in place. These uncertainties may be related to the structure, aerial extent of the accumulation, unseen fluid contacts to delineate the vertical extent, internal architecture of the reservoir and the characteristics of the resident fluid(s). In some cases, companies may complete and produce discovery wells before they can fully appraise the structure or may be forced by other considerations such as community disturbances to abandon appraisal drilling and continue to produce from existing well(s). All these and much more, have an impact on the evaluation of in-place hydrocarbon resources and consequently recoverable hydrocarbons. In Field Development Planning, it is routine to identify and quantify the impact of major subsurface uncertainties such as the in-place volumes and their distribution.

This paper presents the methodology and results of an integrated disciplinary effort at translating uncertainties into a range of static (in-place) volumes for the purpose of field development. Erratic sand development, paucity of biostratigraphic control coupled with a complex structure make the G1.0 complex of the EGBM field one of the least understood hydrocarbon reservoirs of the Northern depobelt - Onshore, Niger Delta, Nigeria. Lack of PVT samples and analyses also add to the uncertainty in fluid properties. The erratic distribution of the petrophysical parameters especially from the G sand core also contributes to the petrophysical uncertainties.

The construction of 3-D static reservoir models based on the understanding of facies and their relationships, through the integration of all available data have been used to enhance the understanding and quantification of the uncertainties. Standard evaluation of uncertainties in the spread of petrophysical parameters like porosity, hydrocarbon saturation and Net-to-Gross ratio was carried out and compared with the multiscenario concepts incorporated in the geological models. PVT parameters were derived for the reservoir based on analogy and correlations constrained with production and test data. Efforts were also made to comply with definitions of proved reserves by Securities and Exchange Commission (SEC) while still evaluating expectation volumes for internal purposes. An attempt has also been made in comparing results from the probabilistic volumetric evaluation of this reservoir and the deterministic (best estimate) method.
Quantifying Uncertainties in a New Field Development: A Swamp Field Case
Authors: Aigbe Christopher O. , Randle Jim , Fitzmorris Robert
Published: December 2007

The Chevron Nigeria Limited (CNL) swamp field, which has oil-in-place in excess of 139.0 MMSTBO, is currently one of the major undeveloped assets in CNL's portfolio. A reservoir simulation study was commissioned in January 2003 to devise strategies for the optimal development of this reservoir. Some study objectives include the determination of the number and location of new wells (producers and injectors), requirements for water injection and gas lift and the optimization of various operating and decision variables, all of which is geared towards maximizing the value of this major CNL asset.

It was recognized that an accurate validation of the 3D geologic model will not be possible because of the absence of historical pressure and production data in the new field, which had two producers and one water injector already drilled. The older techniques of evaluating risks and uncertainties by running sensitivities on various input parameters on the un-validated model on a one-at-a-time basis was considered inadequate since interactions between parameters, which could have significant impact on the forecast ultimate recovery, cannot be captured.

A more robust methodology, which systematically quantifies the impact of the uncertainties in model input variables on the ultimate recovery, using Experimental Design (ED) techniques was adopted for the reservoir study. A two-prong approach was employed in which uncertainties in the sub-surface variables (e.g. Kv/Kh, Kh_Multiplier, Internal Fault Integrity, Sorw, Oil Viscosity and Krw) were quantified using ED to screen for the most significant parameters that could impact ultimate recovery. A multiple regression of the most significant parameters from ED yielded a response surface on which Monte Carlo simulations were performed to generate the p-10, p-50 and p-90 models. The resulting Chears replicated p-50 model formed the basis for the sensitivity runs on the various operating and decision variables (e.g. number and location of wells, well type, offtake rates, gas lift rates and timing, WI rates, voidage replacement ratios, well timing etc.) on the project ultimate recovery.

The study results indicate that the optimized development case will recover 68.5 MMSTBO (representing 49.3% of OOIP of the 21.7 deg. API gravity crude). This represents incremental reserves of 29.8 MMSTBO (over the base case) from the drilling of additional 5 producers and 2 water injection wells.

The paper will present details of how ED approach can be used to quantify uncertainties inherent in model input variables using the CNL Swamp field reservoir as a case study. The development options and detailed results obtained from the study, which now commands a greater degree of confidence, will also be highlighted.
Challenges of Gas Development: Soku Field Oil Rim Reservoirs
Authors: Cosmo Claudio , Fatoke Oluwaseyi
Published: December 2007

The Nigerian LNG Project at Bonny is undergoing significant expansion from it's current 3 trains to 5 trains by the end of 2005. Shell's share of the additional gas demand is met by gas offtake from the Soku oil rim reservoirs. The challenge in Soku is to manage gas offtake between reservoirs to secure optimal hydrocarbon recovery from the oil rims under concurrent production of both gas caps and oil rims

This paper addresses the methods used to establish the sensitivity of oil rim recovery to reservoir uncertainties and development strategy. It shows how an idealised box model, preconditioned to match historic production in reservoirs, is used to guide development plans which are later validated in full 3D reservoir simulation models. The box models and full field simulation have been used to confirm that concurrent production of oil rims and gas caps from Soku oil rim reservoirs can be achieved while optimising oil recovery from the rims.
Targeting Thin-Oil Rims in Bottom- and Edge-Water-Drive Reservoirs
Authors: Kabir C. S. , Agamini M. O.
Published: December 2007

This paper proposes completion strategies to target the remaining oil, left behind when water invades the producing interval(s) in bottom- and edge-water-drive reservoirs. In the first option, a conventional horizontal well is completed below the gas/oil contact (GOC). Once the completion waters out, recompletion occurs in the gas zone.

For either drive mechanism, recompletion of the vertical segment of the same wellbore at the crest is prudent, provided economic gas disposition is not an issue. In the second option, one can initially complete at the same location where the recompletion occurs, thereby skipping the initial completion. In all cases, gravity-stable flooding or disciplined withdrawal rate is required to maximize reserves.

Extensive flow simulations in multiple, history-matched models show that the proposed strategy improves oil recovery significantly. We show that the proposed completion strategies do not involve production of total cumulative gas/oil ratio any higher than those done with conventional completion involving much less oil recovery. In fact, the two-stage depletion scheme doubles the recovery factor in a saturated reservoir with a 34-ft oil column, which is underlain by a moderate size aquifer.

Beyond the computational results, several field examples demonstrate the usefulness of the proposed completion methods. We show that the normalized GOR or the cumulative gas production is less than those experienced under conventional depletion schemes because of gravity-stable flooding.
Abandonment of Wells in Shell Nigeria Operations
Authors: Odita Charles , Adenipekun Adedokun , Wakama Miebaka , Ahire Dondo , Ojo James
Published: December 2007

Shell Petroleum Development Company of Nigeria Limited (SPDC) recently embarked on a campaign to abandon some wells in line with a corporate drive to enhance the safety of the wells in her portfolio. It is also to ensure that SPDC as a responsible operator aims to safeguard people and environment as required by law. The campaign is part of a larger campaign that had the objective of enhancing safety integrity in SPDC. It will also afford the opportunity to carry out relatively inexpensive repair and recompletions.

A total of six wells were abandoned in the land and swamp terrain within a year period utilising the Hydraulic Workover Units (HWU) for Land anda combination of the HWU and Self Elevating Workover Platform (SEWOP) in the Swamp. The 6 wells were amongst the most critical wells for abandonment based on SPDC defined criteria (e.g wells in Navigable water ways or in built up neighborhoods). In one of the wells on land, human habitation had since grown close to its proximity and the well experienced high annular pressures, hence the need for the abandonment. The others are in the waterways in the swamp with other technical problems. Most of the wells were drilled over 30 years ago and they have either outlived their useful life or there is plan to recover the remaining reserves in other offset wells.

The abandonment involved full subsurface and surface abandonment with the entire wellhead and casing structures removed from below the mudline or cellar (for land). The use of the HWU / SEWOP arrangement brought significant cost savings (25 – 50 %) when compared to the cost of using conventional workover rig. This paper reviews the work that was carried out in the abandonment and highlights the challenges as well as strategies that were applied towards the successful abandonment operations.
Water Shut-off using Rigid Polymer: The Etelebou Experience
Authors: Augustine Ekeigwe , Abiodun Laoye , John Madu , Chiji Onwuzurike , Olatunji Williams , Hugues Poitrenaud
Published: December 2007

Aging fields, dwindling production and increasing water cut are major challenges to all operators in the Niger Delta. Thus, finding efficient means to shut-off or control undesirable water production has become paramount. Ironically, the industry does not lack the suite of tools and products to address these problems but, a survey conducted in early 90's estimated that the world wide success percentage of water shut-off was a mere 35%. Identified as key to the poor performance are the deficient problem diagnosis and inappropriate remedial interventions. This low success ratio ultimately led to the loss of confidence in the use of rigid polymers for water shut-off. Although the chemistry of these rigid polymers are robust and well-proven1,2,3,4, the poor result recorded with them heightened most operator's reluctance to use them for water shut-off operations.

This paper addresses a Through Tubing (TT) water shut-off successfully carried out, using a rigid polymer. Identified early was the need for additional data to properly define the problem. Following data acquisition, water encroachment in some of the perforations was established. The diagnosis also identified an undrained interval located beneath the flooded zone. A multidisciplinary team was set up to review all data and advance the most economic and cost effective intervention option. The main challenges including maintaining through bore accessibility, easy wash-out etc. were listed. This led to the choice of a rigid polymer (MaraSEAL), which resulted in the desired solution5,6. The advancing water was checked and in addition access to reperforate on a deeper horizon was achieved. The well is back on production.