Refai, Ahmed (Agiba Petroleum Company) | Abdou, Hesham A.M. (Agiba Petroleum Company) | Seleim, Ahmed (Agiba Petroleum Company) | Biasin, Giovanni (Agiba Petroleum Company) | Reda, Walid (Novomet Egypt) | Letunov, Dmitry (Novomet Egypt)
The majority of Western Desert wells (Agiba Petroleum Company) are completed with artificial lift systems and several kind of pump: ESP, Sucker Rod, PCP (about 40 ESP, 250 Sucker Rod and 10 PCP). A new technology - Permanent Magnet Motor (PMM) - has been developed for ESP motors as alternative to conventional asynchronous induction motor in the last years. PMM is synchronous motor in which the stator manufacturing technique is similar to that of conventional asynchronous motor, but rotor has permanent magnets (instead of copper winding). PMM has more benefit of conventional induction motor: high efficiency (90 94%) vs. induction motors up to 86%; smaller size and weight; wider ranges of rotation frequency regulation (100-1000, 1000-4200 and 3000-6000 r.p.m.); reduced energy consumption and rating of surface equipment (Power Saving); stable torque over wide operation range; Power factor is near to 1; lower specific heat release due to higher efficiency. Also indirect benefits are: a) low heat release (minimum cooling fluid velocity 0.05 ft/s); b) less size for cable and lower power rating for transformer and VSD; c) decreased reactive power; d) improved system Power factor. All Agiba ESP wells are equipped with conventional induction motor. In the middle of June of 2012 Agiba performed a trial installation of Novomet PMM replacing an ESP unit with induction motor on well North Nada 1 x (oil well - Qg =315 BFPD, Qn=173 BOPD) of North Nada field. The installation was successful achieving the expected results and benefits in term of low power consumption. Successful key point: keeping electrical system stability and minimize the number of shutdowns; minimum cost for power consumption and production.
The carbon dioxide (CO2) sequestration and storage in aquifers and depleted oil and gas reservoirs is eminently a feasible solution to provide substantial cut in overall emission into the atmosphere. The current need is to understand the factors affecting the CO2 sequestration potential and capacity of particular formation/reservoir.
The purpose of this study is to investigate the CO2 storage in carbonate reservoir rocks under different conditions of pressure and temperature. Two groups of experiments were undertaken including; (1) investigating the CO2 solubility under different brine salinities, and different pressure and temperature conditions, and (2) studying the effect of CO2 storage time interval on porosity and permeability of carbonate reservoir rocks. Core storage experiments were undertaken using actual and similar core samples saturated with 25,000 ppm NaCl brine. The potential of the CO2 storage capacity and variations in porosity and permeability are evaluated and quantified.
The results showed that solubility of carbon dioxide decreases with increase in brine salinity and/or temperature. The increase of pressure causes a decrease in carbon dioxide solubility. In addition, the effect of temperature on carbon dioxide solubility diminishes above 120 oF and 4,000 psi pressure. The results also indicated that storage of carbon dioxide increases the petrophysical properties of porosity and permeability of carbonate rocks when the storage period is more than 150 days. On the other side, the CO2 storage for short time < 7 days causes reduction in porosity and permeability of carbonate reservoir rock.
The application of the attained results of this study is expected to have good impact on design storage process of carbon dioxide, validation of developed mathematical models, and improving our understanding of the process.
During workover and completion operations, even a small overbalanced hydrostatic pressure can result in a significant loss of fluid to the formation, especially in high-permeability formations. This situation becomes even more drastic in depleted reservoirs, horizontal wells, or in zones that have been previously fractured and packed. Controlling fluid loss into the formation is of critical importance during overbalanced workover operations to minimize near-wellbore (NWB) damage invasion by the completion fluid, which can yield problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. In many hydrocarbon fields in southern Argentina, controlling fluid loss before NWB cleanout treatments is challenging because it can cause pressure differential sticking of the coiled tubing (CT) and/or inability to pump the treatment into the desired interval. This paper presents the successful field application of a novel solids-free fluid-loss (SFFL) system during wellbore cleanouts in the Cerro Dragon oilfield, which is located on the west side of San Jorge Gulf (SJG) basin in the Chubut Province of Argentina.
The SFFL system relies on water-soluble polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock, eliminating the need to shut the well in. In addition, this system does not require the use of breakers or a cleanup stage to reestablish hydrocarbon production once the workover operation has been performed. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment.
To date, about 200 treatments have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations in Argentina, including the job design and post-treatment results. This system has been proposed for returning partial and total loss to full circulation in overbalanced operations, such as (1) lost-circulation events occurring during cementing, fracturing and drilling, (2) well intervention cleanouts by CT and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (UTCP).
In North Africa like in any other region the share of the companies operating oil and gas fields as Join Venture Associations (JVs) is significant. Normally in a JV Set Up two or more companies agree to operate a field or a number of fields in a defined concession area. This implies that these corporate entities have to work in a collaborative environment towards achieving a common goal, under clear predetermined rules of interaction and organizational arrangement as per the JV Agreement. While the JV is a proven contractual and legal set up that delivers as per the set goals, under the condition of an unexpected production decline this collaborative environment is put to the test. Regardless of the nature of the Partners - whether state owned or private, the challenges are the same, especially when the decline is significant, sustained and way below the predicted yearly natural decline. Whether it is about a New Development or a Mature Asset, reversing the production decay trend becomes the number one priority for all the partners of the JV. Therefore they will tend to mobilize the best of their capabilities to overcome the unwanted situation as soon as possible as the "business as usual approach?? no longer works. The response varies depending on the operational expertise of the incumbents. Unfortunately there is not a unique recipe that applies for all the cases. Even if there may exist sufficient skills to handle the situation, solutions applied in prior experiences may not necessarily work out, giving the unique nature and dynamics of each field.
The flow of hydrocarbons in the reservoir is described by a diffusion-type equation. According to that rate changes do not occur abruptly or suddenly, rather are a function of the pressure and saturation distribution in porous media. Therefore an unexpected sustained production decline is more a result of the accumulation of several factors induced under inaccurate assumptions. This may hint to possible gaps either at the field development plan phase or at the execution level or both. If the applied solution attempts do not show signs of improvement, frustration and discouragement could further complicate finding an effective tailor suited solution. In extreme desperate cases a running like "headless chicken", or "punching in the air" situation sets in. Without doubt this is one of the most challenging cases for the management and staff of any JV. The required measures normally go beyond the pure technical aspects. While the JV Agreement may not automatically imply that partners may have unlimited access to the support of their Mother Companies skill pool to help reversing the trend, the key actors with the most knowledge about the wells and field features are right there, in the JV offices and fields.
In the present paper the application of a solution approach is presented and it is illustrated on four Field Cases, from different
well and reservoir conditions, development stage and geographical regions. Two examples involve JV Set Ups, and the other
two involved single company operating the field, yet JV like features. In regards to the JV partners the goal on one side could
be achieving the highest recovery factor over the field life cycle while on the side it could be the highest return of investment.
Both goals do not necessarily go in opposite direction, and could be properly aligned.
In all the above cases the Operators experienced a shift to an organization with a more innovative workflow, following the
reverse of the production decline. The presented Approach may serve as a reference for both existing and new formed JVs
when faced with the challenge of reversing unexpected production decline. The Solution Approach consists in applying a
systemic approach that targets both the technical and the operational-organizational aspects of the JV.
Baltim Concession is a large exploration/exploitation license located in the offshore Nile Delta, Egypt. The concession covers an area of 430 Km2 of the central portion of the present day Nile delta cone. High quality three dimensional (3D) seismic data, coupled with data from some wells drilled in the area, have highlighted the presence of some gas chimneys well recognizable started from pre-Messinian until the Plio-Pleistocene slope succession.
The geometry and architecture of the gas chimneys in Baltim area have been imaged by 3D seismic techniques, time section and a variety of attribute extractions, providing us with a high resolution definition of these features.
The main indicator for gas chimneys in seismic is an almost cylindrical shaped chaotic behavior of seismic signal, due to scattering of seismic energy by diffused gas through the cap rocks above the leaked reservoirs. The origin of gas chimneys has to be related to hydraulic fracturing by gas leaking through faults from deep accumulation where overpressure conditions have been generated by fast burial during the Plio-Pleistocene mega sequence deposition.
The petroleum system in Post-Messinian (Plio-Pleistocene) succession generated biogenic gas only, whereas the Pre-Messinian system proved to generate thermogenic gas and oil.
The role of gas chimney and associated structures as hydrocarbon migration pathways from the pre-Messinian kitchen section to the Post-Messinian reservoirs is testified by many DHI's within the Pliocene - Pleistocene reservoirs that are in contact with the boundaries of the gas chimneys.
In addition, geochemical analysis on gas samples from targets drilled in the Pliocene - Pleistocene indicates the presence of thermogenic gas clearly generated from pre-Messinian units.
From isotopic data, PVT samples and production data from gas fields discovered in Plio-Pleistocene succession evidenced that in many cases gas migrated from the pre-Messinian through high fracture zones related to gas chimneys activities in the studied area.
Well A, encountered multiple depleted reservoir layers (initial reservoir pressure >10840 psi) with up to 5,000 psi differential pressure across layers due to irregular depletion in thin bedded shale and sand layers. Well was drilled with over 16 ppg mud to limit under balance in any higher pressure layer and overbalance in depleted layers. After drilling 4 lopes of sand body and during the start of drilling the last sand lope, complete loss of circulation was encountered, followed by kick and differential sticking. The original well integrity assurance plan considered the deployment of borehole compensated sonic tool in order to acquire a discriminated cement bond log based on attenuation measurement. Also in the plan, a Cased Hole Dynamic Tester tool was to be run and the selection of pressure points to be based on the results of the cbl-vdl. So to assure the full integrity of the cement and be able to conduct the Cased Hole Dynamic Tester as required and proper decision to be evaluated regarding the Type of GP job, the use of the Ultrasonic Imaging Tool was evaluated to be run under tough and challenging conditions (high mud weight and thick wall thickness).
The Ultrasonic tool for cement to casing bond evaluation is typically limited by the attenuation of the ultrasonic echo caused by the wellbore mud weight and composition. With the cooperation between BP PhPc and Schlumberger, and making use of worldwide expertise, the decision was taken to include the Ultrasonic Tool in the cement evaluation suite despite the well conditions.
The analysis of the log managed to prove the zonal isolation requirements and be a source of development of best practices that can improve cement evaluation even with the presence of heavy SOBM.
Fundamentals for the Cased Hole Dynamic Tester (CHDT*) in order to acquire representative formation pressure measurements at interest depths:
1. Good zonal isolation obtained by an effective and homogenous cement sheath bonded to both casing and formation.
2. Casing quality for the seal between the CHDT* tool and casing ID.
The CHDT* tool seals against the casing and uses a flexible drill shaft to drill through casing and cement into the formation. When communication to the formation is established, multiple pretest measurements can be taken to ensure a repeatable formation pressure measurement. After performing the required pressure testing, the CHDT* tool can seal the hole with a 10k psi bi??directional corrosion resistant plug and test plug integrity.
Ultrasonic Imaging tool (USIT*) provides an overview of cement to casing bond quality as well as radius and thickness.
Cement integrity and casing quality is measured simultaneously with 360??degree azimuthal acoustic coverage by the USIT* tool. Precise acoustic measurements of the internal dimensions of the casing and of its thickness made with a rotating transducer provide a map??like presentation of casing condition including internal and external damage or deformation. Analysis of the reflected ultrasonic wave package provides information about the acoustic impedance of the material immediately behind the casing. A cement map presents a visual indicator of cement quality.
Suwono, Sugiyanto Bin (JOB Pertamina Medco E&P Tomori Sulawesi) | Wijaya, Rahmat (Job Pertamina Medco E&P Tomori Sulawesi) | Masbudi, Herryadi (JOB Pertamina Medco E&P Tomori Sulawesi) | Muttaqin, Muttaqin (JOB Pertamina Medco E&P Tomori Sulawesi) | Prasetyo, Hadi (SKKMIGAS)
Based on current approved development plan of Senoro gas field, the field will be produced at rate 300 MMSCFD (net) to fulfill the gas demand. Existing study based on black oil reservoir simulation conducted on developing depletion plan of Senoro Field give an unexpected result of plateau time which is only 11.7 years while the field has gas delivery contract for 13 years. This possibility of shortfall gas tends to risk the company to get a penalty as termed in the contract.
Further analysis of the existing development plan also shows that the gas depletion plan is not yet optimal. It is indicated by the unbalance recovery factor between southern and northern reservoir area as it is shown by a significant difference of its reservoir pressure at the end of contract year. Furthermore, the design of production network planned for Senoro Field also indicating huge pressure losses will be encountered by the southern area wells.
To solve the problem, a new study has been conducted to optimize the development plan. The method used in this study is dynamic coupling simulation by connecting reservoir simulation and surface network system into a single package of simulation run. This study has successfully optimized the Senoro field depletion plan to achieve the target 13 years of plateau time. Strategies used to achieve the target are by rescheduling well, utilizing pressure booster in southern area, installing gas compressor after 9th years of production, introducing horizontal well S-22hw to substitute well S-22, and reducing the number of well to 19 from the original plan of 21 wells.
The Senoro Field is an onshore gas field located in eastern arm of Sulawesi Island. The field was discovered after wildcat drilling of S-1 well in April 1999. After that, five delineation wells have also been drilled and tested in 2001, 2003, 2005, 2007 and 2009 which are well S-2, 3, 4, 5 and 6. The reservoir of Senoro Field is limestone formation, member of M-1 and M-2 Formation that existed at a depth around 5700 - 6600 ft TVD SS. Laterally, the reservoir is divided into two areas, the northern and southern area, separated by a saddle. The northern area is dominated by the M-2 Formation while the southern area by the M-1 formation. From the petrophysical analysis and DST results, it is found that in the northern part of reservoir, there is a gas zone with thickness up to 693 ft and oil rim of about 26 ft. In this section, the gas-oil contact (GOC) found at a depth of 6496 ft TVD SS while the oil-water contact (OWC) at a depth of 6522.34 ft TVD SS. In the gas zone, it has an average porosity of about 27.4%, average Net to Gross Ratio (NTG) about 98%, and average permeability around 202 md. For the oil rim part, average porosity reaches 30.9% but with average NTG only 76% and average permeability about 362 md. In the contrary, only gas zone found in the southern area. It has a thickness about 487 feet. Gas-water contact (GWC) is estimated exists at a depth of 6496 ft TVD SS. In this area, it has average porosity around 24.3% with average NTG 93% but with a very small average permeability of only about 5.5 md.
The world's energy consumption has risen geometrically over the last three decades due to advancement in technology. In response to this ever increasing rising demand, other sources of energy have been explored. Reports show that fossil fuels (crude oil and natural gas) continue to take the lead despite these efforts. Hence, the Oil and Gas industry has put in a lot of technical measures to meet up with this high energy demand. Many works have been done on how to increase reserves and ultimately increase recovery but little has been achieved in this area. Therefore, a more reliable, efficient and effective way of enhancing recovery is necessary to make headway in countering this challenge. This research seeks to provide the feasibility of enhanced oil recovery (EOR) projects using high level data mining technology in the African Oil Producing Regions.
Data mining is a process which finds useful patterns from large amount of data. Data analysis process involves data exploration, pattern identification and pattern deployment to make accurate judgement necessary for EOR investment decisions. It provides a significant reduction in the level of uncertainty when compared with other existing techniques. In our concept, artificial intelligence and genetic algorithm was employed and recommendation made.
Results show that data mining technique is a robust tool for making EOR investment decisions, right from the early life of a field. Thus, this concept makes it more economical to execute EOR projects with lower level of uncertainties. Marginal fields can also be invested upon using data mining techniques.
Oil-production from EOR projects continues to supply an increasing percentage of the world's oil. About 3% of the worldwide production now comes from EOR (Taber, et al, 1997). Efforts to increase reserves and ultimately production of petroleum to meet global energy demands have been on the rise for decades. Various methods of improved oil recovery have been employed at different world's petroleum production zones and the results are encouraging in most cases. EOR projects are successful when their candidates are chosen based on standard criteria for execution and right practices are adopted.
To make investment decisions on EOR projects, economic evaluations need to show fine prospects. Especially at zones such as the Niger Delta Basin in Nigeria where there are light crudes, a determinant is necessary to predict approximately how much an EOR method will produce. Since data are available across board on production history around the world, data mining technique has the capacity to analyse such data to predict the performance of prospective EOR methods.
Data mining is an analytical process designed for extracting or exploring hidden and predictive information from large databases which may be business or market related. It can also be described as the process of searching for valuable information in large volumes of data. Data mining is relatively a powerful new technology with great potential to assist companies focus on the most important information in their data warehouses (Olumoye, 2009).
Intensified US exploration and production activity in the liquids-rich shale plays has tended to overshadow issues with base gas production, particularly the continuing struggle to remediate liquid loading and return pressure-depleted wells to production. In recent years, Devon Energy has intensified efforts to maximize base gas production through deliquification of its mature East Texas wells. Accordingly, the operator has realized tremendous success with artificial lift, which is generating an average 50% rate of return and effectively breathing new life into many of its old and struggling wellbores. More recently, Devon has focused its efforts on the use of Hydraulic Pumping Units (HPU), which have recorded an amazing track record in deliquifying and returning to production low-rate gas wells that no longer respond to plungers, soap or velocity strings.
This paper examines Devon's experience using HPU to deliquify East Texas wells in reservoirs that vary from very low bottomhole pressure with high permeability to higher pressure with very low permeability and everything in between. The targeted wells range in depth from 5,000 ft to 10,000 ft with wellbores between 2 7/8 to 7 in. diameters. All of these well types have been put on pump and responded very favorably.
The authors will review case histories from several divergent East Texas well types to illustrate the efficiency of pumping units in restoring production to these lower fluid rate wells. The discussion will focus on a newly engineered HPU, which comprises a vertical hydraulic cylinder on the wellhead to reciprocate the rods and pump and offers a number of HSE, operational and economic advantages over conventional pumping units. The specific features that make the HPU a very viable and often preferred alternative to conventional pumping units will be detailed, as will the growing pains and subsequent lessons learned in the East Texas deliquification campaign. Owing largely to the impressive results in the East Texas production-restoration program, HPU technology has since expanded throughout other US gas basins where liquid loading has become a predominate issue.
This paper discusses the exploration potential of extensional structures in pre-Messinian formations in central Nile Delta Basin. The study aims at detailed description of extensional events and discusses the exploration potential of specific structures generated.
Particularly, structural elements of pre-Messianian sequences were partially deciphered in the past, due to quality of seismic data and spare and scarce wells drilled to these levels. The newly acquired high quality 3D seismic data has been able to improve the image underneath the pre-Messinian. This has resulted in the understanding of tectonic activity, faults system and structures developed.
Two extensional events characterize the tectonic activity in the Late Oligocene through Messinian.
First extensional event is related to onset of Gulf of Suez rifting and generate a W-E system of basement involved faults and reactivation of syn-rift hinge zone. Related structures of this extensional phase are represented by growth anticline, drag folds and rotated blocks.
The second extensional tectonic event occurred in Tortonian. The structural style corresponds to tilted and eroded fault blocks dipping to north and being aligned in a north-south direction corresponding to the main normal faults trend.
This study of the pre-Messinian extensional structures described here will have a direct impact on the exploration activities design, several important prospects being delineating among the structures developed during both extensional phases.