bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lookback on Performance of 50 Horizontal Wells Targeting Thin Oil Columns, Mahakam Delta, East Kalimantan
Authors: Vo D. T. , Waryan Sukerim , Dharmawan Agung , Susilo Rusdi , Wicaksana Renas 
Published: December 2007

Abstract
This paper presents a case study to look back on the performance of over 50 horizontal wells recently drilled in three different fields in the Mahakam Delta, offshore East Kalimantan, Indonesia. The common application of these horizontal wells is to produce thin oil bands sandwiched between gas cap and bottom/edge aquifer. The objective of the study is to provide lessons learned from the actual well performance data for improving future well planning as horizontal wells continue to be used in these fields.
Based on well performance data, the lookback is mainly focused on the reservoir evaluation aspect of these horizontal wells. Reservoir and well performance is analyzed using a variety of techniques, varying from single-well analytical modeling (or decline curves) to more complex reservoir simulation. Based on statistical data resulted from the analysis of these wells, specific relations between reserves and reservoir-well parameters are identified which will be useful for predicting future well performance, especially during early prognosis. Practical issues related to well planning such as selection of well location, well length, well path, and standoffs to fluid contacts are presented. The paper also discusses specific operational strategy used in drilling, completing, and producing these horizontal wells.
Results from the lookback provide guidelines and refinements for our continuing implementation of horizontal wells to optimize thin-oil-column development in these fields.
Real-Time Rig Information System Promotes Operational Efficiencies in Drilling the Greater Ekofisk Area
Authors: Oberkircher Jim , Herbert Mike , Talkington Kelly 
Published: December 2007

AbstractFast, reliable information is critical in today's fast paced drilling operations where the time value of decisions can be very high. The need for a system to provide real-time data directly from the rig site of remote and offshore locations to the personal computers of the decision-makers in various locations at the same time has never been greater. Philllips Petroleum Company of Norway (PPCoN) and Sperry-Sun have embarked upon the implementation of just such a system within the Greater Ekofisk area of the North Sea with great results.The use of the INSITE System, with its low-cost, advanced communications and networking capabilities, on the PPCoN operated wells, particularly those classified as HTHP, has enhanced the operator's ability to make quicker, more informed decisions. It has stretched the technical resource base by putting the critical information at the users' fingertips, including information not normally captured or transmitted from the rig. The use of INSITE has contributed to reduced well costs by allowing better and more informed decisions and by allowing qualified personnel to monitor operations on more than one rig at time from the office.This paper will examine how the system was implemented and used and will discuss some of the operational and cost savings benefits.
Implementation of Hydraulic Fracturing to Improve Oil Production and to Solve Sand Problem (Case Study: Kenali Asam Field)
Authors: Hadi Gunung Sardjono , Arifin M. Ainul 
Published: December 2007

Abstract
There are many kinds of methods to improve oil production such as production optimization, implementing of enhanced oil recovery, horizontal drilling, etc. It's depending on the reservoir characteristics. For example, changing pump size with the big one is not always to get a good result particularly in the reservoir that has sand problem. Acidizing treatment is also sometimes successful and failed. In order to get the best solution, a hydraulic fracturing is one of many alternatives to handle sand problem and also could improve the production at the Kenali Asam field.
Kenali Asam field is located approximately 7 Km South of Jambi City, South Sumatra, Indonesia. Since the field was found in 1931, has drilled 260 wells with 19 layers in Air Benakat Formation group.
Hydraulic fracturing has implemented since 4 years ago in this field, particularly in layers d/320, b/400, P/1050, and S/1170. The best result is obtained from sand b/400 (shallow sands). The most problem in these layers one of them were tight (the permeability is less than 20 md) and another layer has a good permeability (more than 200 md), but unfortunately has sand problem.
Using hydraulic fracturing the production could be increased significantly and some of them also could solve the sand problem. For instance, from sand d/400 has been giving the gain around 1.170 barrel per day. And, from economical side this job still attractive due to the total cost of hyfract job (including rig cost) is still less than US $ 100,000 per well. Due to sand b/400 is very potential and attractive, in this paper, the focus discussion about sand b/400 and also will discuss about the kind of suitable proppant for this reservoir.
Improved Experimental Characterisation of Cement/Rubber Zonal Isolation Materials
Authors: Bosma M. G. R. , Cornelissen E. K. , Schwing A. 
Published: December 2007

Abstract
Recently, various companies published sophisticated design methodologies to engineer the ‘cement’ sheath in a oil/gas well completion such that the zonal isolation would remain intact (i.e. pressure tight) during its projected lifetime. Loading within a prescribed design envelope (e.g. pressure and/or thermal cycling or mechanical compaction processes) are the main considerations.
Improved performance of a candidate zonal isolation material is achieved by adjusting its material properties, especially the Young's modulus and the compressibility.
These earlier studies indicated that apart from a proper mechanical characterisation of the ‘cement sheath’ (preferably described by non-linear material models), the in-situ stresses in the ‘cement’ play a prominent role as well. The latter are influenced by the volumetric behaviour of the slurry during setting and the thermal expansion coefficient of the set ‘cement’.
However, often these parameters are not known for ‘real life’ well construction materials.
Therefore, Shell International E & P B.V., the Netherlands, decided to design and construct dedicated laboratory equipment to determine those parameters for commercial ‘cement’ formulations at conditions encountered in typical well completions.
A first feature of this unique system (which can operate at pressures up to 1500 Bar and temperatures up to 300 ° C) is to monitor i) the progress of the ‘setting’ reaction of Oil Well Cements and or thermosetting resins, ii) their reaction behaviour (from the onset of gelling to the ‘final set’) and iii) the softening or swelling phenomena encountered in thermoplastic and thermoset materials.
The apparatus has inter alia the same functionality as conventional API Cement Consistometers or Ultrasonic Cement Analysers. However, it can also be used in combination with self-vulcanising rubbers, that cannot be used in the conventional API devices.
A second aspect of the apparatus is the determination of the volume changes (at constant pressure) or alternatively the pressure changes (at constant volume), during setting of the cement (or resin) system.
All measurements can be performed at either isothermal conditions or for prescribed temperature sweeps over time. Either volumetric properties (shrinkage or expansion) or compressibilities of cements / resin systems can be measured in a time frame ranging from the onset of gelling to far beyond ‘final set’.
In yet another operational mode, the volume change of set materials as a function of temperature (i.e. their volumetric thermal expansion coefficient) can be quantified.
In addition to a review of the principles of this novel apparatus, this paper also presents a typical application of the data in a Plug and Abandonment design (i.e. the Finite Element Engineering design of a thermally pre-stressed ‘rubber’ abandonment plug).
Laboratory Development of a Novel, Synthetic Oil-Based Reservoir Drilling and Gravel-Pack Fluid System That Allows Simultaneous Gravel-Packing and Cake-Cleanup in Open-Hole Completions
Authors: Price-Smith C. , Parlar M. , Kelkar S. , Brady M. , Hoxha B. , Tibbles R. J. , Foxenberg B. 
Published: December 2007

Abstract
In this paper, we present a novel approach for drilling and completing open hole horizontal wells with a fully compatible synthetic/oil-based fluid system utilizing shunt tube technology. The proposed RDF is a synthetic/oil-external emulsion that is reversible through exposure to a fluid of pH less than 7. A surfactant package included in the RDF water- wets the bridging/weighting agents (e.g., CaCO3) upon reversal of the emulsion. The synthetic/oil external emulsion developed for gravel packing typically contains 50-75% by volume aqueous phase as the internal phase and is completely solids-free. The internal phase can either be brine or a pH- reducer as well as a fit for purpose dissolver for the bridging agents. The pH-reducing property of the internal phase provides the required break mechanism for the S/OB-RDF emulsion remaining in the RDF filtercake under leakoff conditions allowing the bridging agents and drill solids to be water-wet, ensuring dissolution of the bridging agents.
Laboratory data are provided for filtercake removal kinetics as a function of temperature, overbalance during gravel packing, gravel mesh size, and drill solids concentration in the RDF. Rheological data are given. Retained permeabilities and flow initiation pressures measured with the combined core and gravel-pack system are presented. Implications of the laboratory results on field practice are discussed.
Gas Shut Off Using Foam: The Solution for Unwanted Gas Production?
Authors: Ligthelm D. J. , van Eijden G. J. M. , Gronsveld J. 
Published: December 2007

Abstract
Gas shut off technology for wells with a high gas/oil ratio is extremely valuable to improve oil production and reduce environmental pollution. Foam treatments have been applied to reduce unwanted gas inflow. However, results have not always been favorable. This paper presents a field case supported by a modeling study of successful foam shut-off treatments carried out in the South Chinese Sea. This study shows that the possibility of success of gas-shut-off treatments can be greatly enhanced by having a good understanding of the process parameters. In the Champion field, Brunei, an increasing number of oil wells are shut in due to high gas/oil ratio. In November 1998, three wells were treated with a surfactant/polymer (foam) solution in water, co-injected with nitrogen. In two wells the gas/oil ratio was substantially reduced but also a significant loss in oil productivity was observed, which partly restored in the course of time. The treatments were based on laboratory core flow experiments under reservoir conditions. The experiments served to design the field trials and as input data for simulations with a numerical radial well model, which was used to interpret the field trials. The reduction in gas mobility by a factor between 2 and 10 as observed in the field is consistent with the results of the laboratory experiments.
The study identifies the permeability and temperature window and the type of geological setting and well configuration for which the applied foam system will be successful. This is essential to screen potential candidate wells. It will be shown that in future treatments less damage to the oil productivity and lower costs are possible by omitting nitrogen gas and by reducing the injected volumes.
Wellbore Stability Evaluation for Horizontal Hole Completion - A Case Study
Authors: Finkbeiner T. , Moos D. , DeRose W. , Shiflett D. 
Published: December 2007

Abstract
Understanding borehole stability has become increasingly important in recent years to facilitate design of costly horizontal wells. This paper presents a case study, in which we evaluated the stability of a horizontal well in a major California oil field by first determining rock strength and tectonic stress and then drilling the well to verify the results of the predictions. Given the opportunity to drill numerous horizontal and possibly multilateral wells, it was important to fully evaluate the possibility of a successful open hole completion. An 800-foot horizontal well was planned to be drilled within a poorly consolidated and highly porous Pliocene reservoir that is slightly over pressured.
The analysis revealed that one horizontal principal stress is greater and one is lower than the overburden. Maximum horizontal compression is oriented N60°E. Borehole stability of the horizontal well is predominantly controlled by the extremely weak reservoir rock (uniaxial compressive strength is only 1,175 psi). An open hole completion was predicted to collapse without supporting slotted liner or casing. Even for a cased well, perforations placed at their most stable orientation were predicted to produce considerable amounts of sand. Only 200 feet of open horizontal hole was tested to validate the prediction. The open hole produced briefly and then collapsed. The horizontal well was subsequently completed in 800 feet of interval using a 60 mesh slotted liner and has produced 15,657 bbls of oil, 291 bbls of water, and 41,181 Mcf of gas through 12/31/99 with no sand problems.
Considering The Reservoir in Determining a Perforation Strategy
Authors: Underdown D. R. , Mariotti P. , Venkitaraman A. 
Published: December 2007

Abstract
The choice of how to perforate an interval is considered by many engineers as a straightforward exercise. Typically, an engineer takes API gun performance data from RP-43, uses some nodal analysis program and determines the "optimum" shots per foot, phasing and shaped charge that provides the maximum inflow performance for the completion. This information in combination with operational constraints is then used to design the perforation operation.
As more and more is understood about the perforation process, some operators are becoming aware of the value of approaching the perforation operation as a system instead of a simple engineering exercise. However, one aspect that has not received very much attention is the make-up of the reservoir in the near wellbore area, and how this affects the overall performance of the perforated interval after the perforation event.
This paper presents the results of a program to optimize the perforation strategy for a major gas field in the North Sea. An emphasis is placed on understanding the effect of the perforation operation on the deliverability of the reservoir near the perforation. The discussion in this paper includes petrographic analyses of the near perforation rock before and after the perforation event. In addition, CT (Computer Tomography) scans and core flow tests were done in order to understand observations from whole core tests. Production data from several wells is presented that documents the success of the system approach to developing the perforation strategy for the field.
Re-orientation and Merging of overlapping 3D Seismic Data
Authors: Murty J. V. S. S. N. , Shankar T. , Srinivas D. 
Published: December 2007

Abstract
This deals with a new technique for re-orienting different overlapping 3D seismic data sets from their acquired grid orientation into an integrated 3D volume in a desired orientation. The technique involves effectively predicting the seismic amplitudes using the local amplitude gradients on a time slice along the acquired grid axes. The re-construction of the seismic data in the desired grid orientation and bin size, from four 3D data sets in different grid azimuths and bin sizes, has improved the utility of the 3D data in Cauvery basin, Tamil Nadu, India.
The advantage of this technique is that it a) provides the data in the orientation that suits best for the given geological objective, b) provides uniform quality in spite of the non- uniform distribution of input bins with respect to the chosen output grid, c) it does not smear the dipping events and d) the interactive interpretation tools such as horizon/time slices, cube displays, computing sequence attributes etc. could be effectively used to visualize the entire area instead of seeing separately on the four data sets. The required software was developed and the merging of the four data sets was carried out on interpretation workstations.
The integrated volume helped in evolving a comprehensive depositional model for Kamalapuram Formation of Eocene/Paleocene age and in predicting areas of reservoir development.
An Overview of Re-Entry and Clamp-on Infill Drilling for Incremental Recovery in Offshore Field
Authors: Tewari R D , Mittal A K , Patra S K 
Published: December 2007

Abstract
Bombay high is a highly heterogeneous, multi-layered carbonate reservoir overlain by gascap and underlain by aquifer in Western continental shelf of India and is in mature stage of its producing life. The field is currently undergoing "Mid-life Crisis", necessitating major re-development and well interventions programs for stemming the decline in oil and gas production and maximization of recovery. Being an offshore field, sidetracking (LDST, MDST and SDST) of existing wells and drilling of infill wells through clamp-on have become sort of immediate preferred cost-effective option in Bombay High; firstly, for sustained oil production and commensurating the water injection and secondly for facilitating the additional recovery of bypassed, un-swept/less- depleted reserves. Failures/limited success of repetitive workover jobs, poor cementation, bad wellbore condition, early water breakthrough have made many wells susceptible to channeling behind casing and cross flow between the layers. Relocation of such wells and utilization of slot have become inevitable. Sidetracking is being practiced, as a measure for reducing the inventory of sick wells where all the conventional remedial measures have not met with desired results and have also limited the further scope of rectification.
This paper deals with the selection criteria, implementation and analysis of techno-economic successes and failures of re- entry/re-engineering of sub-optimal/uneconomical and clamp- on infill wells and also summarizes what has been learnt over the past several years and future scope of such activities.
Whaarangi; Prospect Potential Resolved
Authors: Engbers P. , Adams S. , Farmer R. , Mathers R. , Soek H. 
Published: December 2007

Abstract
This paper describes the rise and fall of a Miocene exploration prospect in the Maui PML offshore New Zealand. Strong positive indications of moveable hydrocarbons were finally proven by a RCI program not to relate to mobile hydrocarbons. Petrophysical evaluation indicated moderate quality sands with medium hydrocarbon saturations (around 50%) in the Moki B3 sand in the Maui B area. Positive oil indications were observed while drilling. The B3 sand showed a rather clear oil pressure gradient. Moreover, a 1.5 l sample containing oil (40° API) had been recovered in an earlier MDT program. In addition, the inferred contact from logs and pressures fitted a DHI on 3D seismic that also coincided with a structural 4-way dip closure. However, given the history of other Moki sands (low productivity) and the small potential oil column (transitional), commercial produceability was considered the main risk. With the development infra-structure already in place for the deeper Eocene reservoirs, and given the potential size of the accumulation, only relatively low oil rates from the Moki sands would be required for commercial development. Consequently a recent infill well targeting the deeper reservoirs provided the opportunity to sample and potentially test the Moki sands. With facilities lifetime reducing, a definitive result on Moki development potential was essential. Several RCI samples at a single reservoir point were recovered with increasing pump-out. The proportion of mud filtrate versus formation water was analysed by using a tracer added to the mud system. At the end of the pump-out, mainly formation water was recovered with only traces of oil. This conclusively demonstrated that the oil was immobile. Consequently, by low cost means, a definite result on the production potential was obtained, thereby avoiding expensive production testing.
Reservoir Characterization Through Well Test Analysis Assists in Reservoir Simulation - A Case Study
Authors: Neog P. K. , Borah N. M. 
Published: December 2007

Abstract
The Upper Assam basin is a major onshore sedimentary basin located in the Assam-Arakan geological province in the north-eastern part of India. This case history of a high permeability, stratified sandstone reservoir of the Lower Eocene formation in Upper Assam basin illustrates how integrated pressure transient analysis coupled with geological, geophysical, petrophysical and production information can be used for construction of dynamic fluid flow models to provide better reservoir description for reservoir simulation study. Chronostratigraphic and litho- stratigraphic layering of reservoir units for this field done earlier through seismic and log interpretation suggested isolated units. Such a model led to the computation of high primary recovery factors. Independent analysis of well tests was found to yield conflicting results, especially with respect to outer boundary configuration. The reservoirs comprising of fine to medium grained sandstones with interbedded shale/carbonaceous shale are located at around 3600 m depth, generally very thin (1-5 m) and exhibit rapid lateral variation making well-to-well log correlation un- reliable in many instances. Consistent modeling of flow barriers through analysis of all available well tests and integration of the same with other geo-scientific data led to a more reliable and consistent interpretation of field obser- vations and facilitated refinement of reservoir description. A 3D-3P reservoir simulation study carried out with this model facilitated in establishing the fact that several sand units/reservoirs in the field under study are in pressure communication with a common aquifer system. This infor- mation allowed more reliable estimates of in-place reserves and provided good data for fine-tuning the reservoir model to arrive at reasonable history match. The new model used in reservoir simulation is much more plausible and brings out the importance of using dynamic information for reser- voir characterization. Performance prediction of the field based on the new model aided in making realistic assess- ment of future production profiles and proper planning for field installation of formation water disposal and artificial lift facilities.