bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evolution of Coiled Tubing Matrix Stimulation for Gas Wells in Saudi Arabia
Authors: Al-Atwi Mohamed , Solares J. Ricardo , Amorocho Ricardo , Garzon Francisco , Kharrat Wassim , Stuker John , Naji Iyad 
Published: September 2011

Abstract
Saudi Aramco has been using coiled tubing (CT) to acid stimulate gas wells completed as single or multiple open hole horizontal laterals in carbonate reservoirs. These CT interventions have evolved from pumping the treatment fluids through normal nozzles, to high-pressure jetting with or without a simultaneous bullheading of inert fluid through CT tubing annulus. Until recently, there was no CT bottom-hole assembly (BHA) available on the market to provide realtime downhole data monitoring during CT acid stimulation. Therefore, these types of stimulation jobs followed a predetermined pumping schedule, assuming that fluids are squeezed at the nozzles depth while reciprocating the CT string from toe to heel. The operator had no means to control the acid coverage across the extended reach open hole laterals.
The bottom-hole pressure (BHP) inside and outside the CT string, monitored real-time with the fiber optic bottom-hole assembly (FOBHA) allows the operator to adjust the differential pressure across the high-pressure jetting tool nozzles. The distributed temperature survey (DTS) recorded with the fiber optic at key stages of the treatment helps identify initial thief zones and any further developing ones during the acid stimulation treatment. Tracking with a DTS, the fluids placement through the high-pressure jetting tool showed that acid was still being injected into thief zones and not squeezed at the nozzles depth. DTS is therefore used to adjust the real-time pumping schedule by deciding when, where, what type and what quantity of diverter to pump to get uniform acid placement across target intervals.
The ability to place stimulation fluids in a highly effective way is the most important element in any successful production enhancement stimulation job. This paper will detail case histories of gas producers in which a fiber optic enabled coiled tubing (FOECT) and a FOBHA were successfully run together to record real-time downhole data in an effort to assess the full stimulation effect of an acid matrix stimulation treatment, and to control and optimize the CT operation.
Several cases demonstrating the effectiveness of the FOECT matrix stimulation technique are highlighted in this paper.
New SEC Rules: What is New for the Petrophysicist?
Authors: Glorioso J. C. , Rattia A. 
Published: September 2011

Abstract
The Securities and Exchange Commission (SEC) of the United States of North America has modernized in December 2008 its regulations for the report of oil and gas reserves. From now on, the oil and gas companies will be able to report reserves of bituminous sands, the economic evaluation of reserves will be made with an yearly average price instead of the price of the last day of the year, the use of (reliable) technology will be allowed to demonstrate the producibility and the (lateral) continuity of production of the reservoirs as well as to determine the fluid contacts. Also, it will be authorized to publish, voluntarily, probable and possible reserves that previously were explicitly prohibited in the SEC reports. One of the important changes that concern to the petrophysicist is the qualification of Reliable Technology to support or demonstrate the producibility of the reservoirs without having a conclusive test. Using technology the petrophysicist will also be involved in fluid contacts determination and in the construction of analogy of the reservoir of interest with other reservoirs at a more advanced stage of development. The use of reliable technology is also enabled to support the estimate of proved undeveloped reserves at greater distances than the development spacing in the field provided that reasonable certainty of the production continuity is obtained by using such technology. The intrinsic technical uncertainty in reserves estimations often makes the estimators to adopt a probabilistic estimate instead of a deterministic one. The use of probabilistic estimates has become frequent in the industry and now the SEC has defined that estimates of proved reserves can be made either deterministically or probabilistically. When a probabilistic estimate is chosen, or when in occasions the petrophysical parameters of an in essence deterministic estimate (net thickness, porosity and saturation of water) are chosen based on a probabilistic approach of the distribution of those parameters, the petrophysicist will have to observe some basic premises to avoid misinterpretations. Also, in the next years, operators and service providers will be embarked in an effort to find new tools and methodologies for reservoir evaluation and reserves estimation that allow them to value their properties with reasonable certainty still at the early stages of development. This will take place under a modernized regulatory framework that will enable the use of the most modern technologies provided that they can offer consistent, repetitive, and reasonably certain results on the expected answer of the reservoir.
Field Application of Chemically Treated Substrate in Pre-packed Well Screen
Authors: Weirich John B. , Monroe Terry D. , Beall Brian B. , Singh Amit Kumar , Gupta D. V. , McBee Jim 
Published: September 2011

Abstract
Chemically impregnated substrates have been successfully used for several years in fracture treatments to achieve long-term inhibition of downhole scale and other precipitates. These solid chemical treatments are gaining wider interest in non-fracture applications. The well designer is challenged to place the substrate in the production flow stream, so as to effectively treat the produced fluid, while at the same time ensuring the integrity of the completion as a whole. The application of a pre-packed well screen to convey the impregnated substrate in a gravel packed well is discussed as well as the evaluations made of the substrate’s fines plugging tendencies and the design of the pre-packed screen itself. The work conducted indicates that correctly sizing the substrate in relation to the gravel pack proppant and designing a special, enlarged pre-packed screen can ensure effective delivery of these chemical treatments in a variety of well completions.
Smart WaterFlooding for Carbonate Reservoirs: Salinity and Role of Ions
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed 
Published: September 2011

Abstract
The salinity level of injection water in the past has not been considered as a key parameter in oil recovery from water-flooded reservoirs. In the recent years, extensive research on oil/brine/rock systems has shown that injection low salinity brines has a significant impact on the amount of oil recovered. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect.
Saudi Aramco through its upstream research arm (the Advanced Research Center) has initiated a strategic research program tagged "Smart WaterFlood" to explore the potential of increasing oil recovery by tuning the injection water properties. Based on the research work for the last three years, we demonstrated in a previous report (SPE 137634) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Also, research confirmed that the driving mechanism is wettability alteration of carbonate rock surface.
This paper highlights extensive and a broad range of laboratory studies including wettability and surface chemistry studies to define the role of water ions in the induced wettability alteration, which is crucial in determining the optimum composition of injection water for future field applications.
The rock surface chemistry studies pointed out the potential mechanisms for wettability alteration triggered by injecting different salinity slugs of field injection water. The contact angle results indicated that a sufficient reduction in the ionic strength of field injection water is required to trigger the effect of wettability alteration. All evidence gathered during this research work indicate that what we deal with in this study is a new research trend, different from what have been addressed in the literature on low salinity waterflooding for sandstones, and seawater injection in chalks.
Accounting For Adsorbed Gas in Shale Gas Reservoirs
Authors: Mengal Salman A. , Wattenbarger R. A. 
Published: September 2011

Abstract
Shale gas reservoirs have become a major source of energy in the recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Therefore it is important to understand the adsorption phenomenon and to include desorbed gas and its effect in our analysis.
The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from Shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter (BDF) methods and utilizing end of transient time, to estimate OGIP, that are presented in previous literature are reviewed to include adsorbed gas in them. (Kings (1990) modified z* and (Bumb and McKee’s (1988) adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods.
Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as Shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply OGIP estimation methods with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption.
Original gas in place (OGIP) estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30% increase in OGIP estimates and 17% decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5% less stimulated reservoir volume estimate.
Single-well In-situ Measure of Oil Saturation Remaining in Carbonate after an EOR Chemical Flood
Authors: Edwards John , Ramamoorthy Raghu , Harrigan Ed , Singh Maniesh , Soek Harry , Van Wunnik John , Al Yarabi Mohammed , Al Mjeni Rifaat 
Published: September 2011

Abstract
The MicroPilot* is a log-drill-inject-log sequence of operations designed to evaluate the improvement in oil recovery resulting from the addition of chemicals to the injected water. The fluid to be injected is transported downhole in a sample chamber and injected into the formation through a pencil sized drilled hole, with measurements of the resulting changes in saturation proximal to the well. This technique was first used during 2009 in Oman to perform an in-situ test of alkaline surfactant polymer in high porosity-permeability clean sandstone saturated in medium viscosity oil.
This in-situ measurement is even more relevant for carbonates, as it eliminates the uncertainty associated with restoring mixed wettability in cores prior to laboratory enhanced oil recovery (EOR) floods. However executing a log-drill-inject-log sequence of operations in tight carbonates is more complex than clastics. The issues include small scale heterogeneity, presence of natural or induced micro-fractures, varying residual oil saturations, and the low permeability that requires injecting at pressures above the drilling fluid hydrostatic pressure.
The operation and results of the first use of this EOR screening technology in carbonates is described in this paper in which an alkaline surfactant mixture (AS) was injected into a partially water swept 3mD permeability carbonate containing light oil. Aspects described include the mechanical process of drilling and injecting AS and the petrophysics of measuring changes of oil saturation at a small scale. The saturation changes are compared with other AS flood measurements in a neighboring well test using Single Well Chemical Tracer (SWCT) and cased hole logs.
*Mark of Schlumberger
Long-Term Injectivity Test in a Field Characterized by a Tar Mat Zone Strives to Unlock Higher Reservoir Potential
Authors: Arukhe James O. , Al Dhufairi Mubarak , Al Ghamdi Saleh , Harbi Badr , Docherty Paul R. 
Published: September 2011

Abstract
A carbonate field in Saudi Arabia is undergoing major development requiring water injection wells to provide peripheral matrix water injection as pressure maintenance to support oil production. The field is characterized by a tar mat zone, which potentially could isolate the oil reservoir from the planned pressure support and serve as a barrier for the water injection. Therefore, the injection wells were geosteered horizontally right above the tar "barrier" into the transition zone between the heavy and lighter oil, which poses a challenge in assuring adequate pressure support to the producers, without leaving pockets of relatively high oil saturation behind the waterflood front.
To address transmissibility uncertainty between producers and the injectors, long-term injection (LTI) pilot tests were designed utilizing one water injector and six observation wells to capture pressure signals. Building the surface facility to deliver the required test as planned was challenging, starting with the seawater as a source, to the water treatment and ending with pump selection. This paper discusses the unique layout of the LTI surface equipment, a mini-plant by itself, and how operational challenges were overcome in the field. The authors highlight some operational issues related to the LTI test that had almost 90% efficiency from operating over 200 days and over 2 million barrels of injected filtered and treated seawater volume, as well as presents valuable insights to demonstrate how a project of this scale was successfully executed and more value added to the development plans.
The unique equipment layout is composed of twin sea-submerged, skid-mounted electrical submersible pumps (ESPs), 6″ hoses, filtration unit, a chemical treatment unit, eight 500 bbl storage tanks, and a horizontal pumping system (HPS). The layout of the surface facility components, their performance and the importance of continuous water injection in addressing the test goals are discussed. The injection well performance was monitored by integrating Joshi’s equation to Hall Plot and slope analyses to pr ovide means of more meaningful use of injection pressure and rate data. The synergy of the mini-plant components coupled with engineered performance monitoring tools were enablers in this test design to help unlock more reserves. Overall, the test was a great tool to qualify field development plan assumptions, indicating that less powered water injectors than initially planned are required.
The Potential Pitfalls of Using North American Tight and Shale Gas Development Techniques in the North African and Middle Eastern Environments
Authors: Martin A. N. , Eid R. 
Published: September 2011

Abstract
Many companies operating in the upstream gas industry in the Middle East and North Africa (MENA) are interested in the outstanding successes achieved by the US and Canadian tight and shale gas producers. It seems almost miraculous that companies can obtain economic gas production rates from rocks with permeabilities measured in nanodarcies – so low, in fact, that it becomes almost impossible to accurately assess. Operators in MENA, who are accustomed to working in formations with permeabilities 5 or 6 orders of magnitude greater, have recently realised that they may be sitting on top of huge untapped gas reserves that had previously been evaluated as sub-economic.
In recent years, several major MENA-based operating companies have bought interests in US and Canadian tight and shale gas operations, with the objective of acquiring experience and technology that can be applied to similar formations in MENA and elsewhere. This seems to be an obvious and wise strategy; unfortunately, the problem is not the strategy, it is the tactics ("the devil is in the details"). In many instances, operating companies have been disappointed to discover that they cannot simply transplant an American-style development into MENA. Similarly, many North American independents have viewed the untapped low-permeability gas reserves of MENA as a natural territory for expansion, only to find themselves frustrated at almost every turn.
This paper seeks to highlight the potential pitfalls of trying to use North American development techniques in MENA and to promote strategies and tactics that are more suitable. In addition, this paper will suggest structural changes that could have a significant positive impact on low-permeability gas developments in MENA.
Automating Well Performance Monitoring of Real Time Data
Authors: Al Nuaim Ahmed , Williamson Mike , Hasan Sualeh , Holdaway Keith , Krug Steffen , Labban Marwan M. 
Published: September 2011

Abstract
Estimating reserves and predicting production in reservoirs has long been a challenge. The importance of performing accurate analysis and interpretation of reservoir behavior using only rate and pressure data as a function of time or cumulative production is fundamental to assessing remaining reserves and for forecasting production. An interactive system was developed to assist in Decline Curve Analysis (Cartesian, Exponential, Harmonic and Hyperbolic) and Production Forecast in an Integrated Reservoir Management environment.
Different techniques are often applied in short and long term production forecasting. The associated uncertainties are of a different nature for the various time scales. The handling of these uncertainties has proven to be highly challenging for most oil and gas companies. There are tendencies to underestimate uncertainty and completely fail to account for "unforeseen" events which can erode the forecasts.
Adopting a methodology of advanced analysis of production decline curves provides important forecasting results for future production from a single well or multiple wells across reservoirs and fields. The amount of data to be analyzed must be managed and aggregated efficiently. It is imperative to ensure the data are robust and thus have been explored via workflows based on advanced analytics to remove outliers and provide spatially viable input parameter values.
This paper introduces a refreshingly intuitive navigation of the disparate data sources and input parameters aligned with a comprehensive suite of forecasting models wrapped into a web-based solution. The user is enabled with interactive graphical output to extensive "what-if" combinations of critical input parameters across multiple forecasting models. Whether working with oil or gas reservoirs, the user has access to a rich compendium of forecasting techniques that detail accuracy indicators and interactive graphs. The relationship, for example, between p/z and cumulative gas production for typical gas reservoirs can be studied by calculating pressure response to various modes of gas production and water encroachment. Water encroachment methods considered are Schilthuis, Hurst simplified and van Everdingen-Hurst.
Laboratory Investigation of Low Salinity Waterflooding on Reservoir Rock Samples from the Frøy Field
Authors: Hadia Nanji , Lehne Håvard Heldal , Kumar Kanwar G. , Selboe Kristoffer , Stensen Jan Åge , Torsæter Ole 
Published: September 2011

Abstract
Laboratory studies of low salinity waterflooding (LSW) have been performed to evaluate the potential of improved oil recovery at the Frøy field. Coreflooding experiments were conducted at high temperature and low pressure on reservoir core samples to determine the potential of LSW as an enhanced oil recovery (EOR) process for the field. Experiments were performed on several core plugs selected from two different wells at different depths of the reservoir. Synthetic formation brine and Frøy crude oil were used in the experiments. The injection brines of three different salinities were prepared synthetically by diluting the high salinity brine with deionized water. X-ray diffraction (XRD) analysis, computed tomography (CT) scans and thin section analyses were also carried out to study the mineralogy of the reservoir. The results showed an incremental recovery from 6 to 14 % of original oil in place for low salinity waterflooding. The residual oil saturations were reduced by 4 to 9 % of pore volume at the core scale. A significant reduction in permeability of the core plugs was also observed. It was also observed that the core permeability decreased more significantly with the increase in clay content as a consequence of LSW. The experimental results showed a possible EOR potential of LSW for the investigated formation of the Frøy field.
H2S Challenges Presented to ESP Systems
Authors: Sikes M. A. , Adams D. L. , Qi J. P. , Wonitoy K. 
Published: September 2011

Abstract
Hydrogen sulfide (H2S) can negatively impact electrical submersible pumping (ESP) system reliability through several mechanisms, including the increased probability of corrosion, promotion of iron sulfide (FeS) formation, and initiation of sulfide stress cracking (SSC). H2S is a naturally-occurring chemical compound in wellbores throughout the world. The presence of H2S can result in various forms of corrosion that attack ESP systems, causing premature failure that results in lost production. ESPs have shown to be good candidates for wells with H2S concentrations up to 40%. Bottomhole temperatures (BHT) of 325° F with measurable amounts of H2S have also had positive results.
H2S reacts with wellbore fluids to create free hydrogen resulting in hydrogen embrittlement potential. Additionally, the free sulfur can lead to SSC in high-strength steels over time. H2S can also react with H2O and form sulfuric acid (H2SO4) or free sulfur. This is an additional source of corrosion that the ESP can experience, resulting in corrosion or fatigue of the system.
Using application guidelines, H2S-resistant materials can be used in various configurations depending on the H2S quantity and the BHT, allowing for the best combination of defense while considering the overall system. High-strength shafting and corrosion-resistant couplings, fasteners, and housings offer the most protection from corrosive elements.
Cable and motor lead extensions (MLE) benefit from the application of lead barrier protection. Lead is a stable element that is dense and malleable, offering excellent corrosion protection to the electrical system. All of these combinations enable an operator to increase reliability of the ESP even when exposed to highly corrosive environments. Finding a balance between specialized materials with varied H2S resistance ability enables different levels of H2S prevention to be offered, depending on the concentrations seen.