High pressure pumps used in oil well stimulation are usually powered by diesel engines using multispeed transmissions. Many high pressure well service pumps are reciprocating single-acting positive displacement pumps, mounted on a specially designed trailer chassis frame at a certain height to perform well servicing operations. These pumps require frequent maintenance at fluid ends (discharge area).
These maintenance operations require the technician to place his or her hands inside the fluid end to replace valves and related components. This is potentially problematic when the pumping equipment is remotely controlled and the person starting the engine might not have a clear view of the pump. During maintenance of the fluid end, it is necessary to rotate the input shaft of the pump to retract the plungers out of the way to access the valves. The equipment technician often must stand at an elevated height to perform these maintenance tasks, and must manage and hold various tools and equipment to perform this job. This can involve significant risk in terms of human factors, operational safety, and control of falling objects.
This paper addresses how a retrofitted safety work platform was incorporated into fracturing pump trailers to more safely perform effective maintenance. The real field operation conditions, field engineer’s input, and district requirements, such as railings, ladder position, and gratings are considered. In addition, different variables, such as road travel positioning, duration of work, frequency, task difficulty, work envelope, and ground level access requirements were evaluated during design and installation of the work platform on the unit at the field operation.
An ergonomically designed work platform adds benefit by providing worker stability, minimizing postural fatigue, and anthropometry, thereby reducing risk of personal injury incidents while performing maintenance of equipment at an elevated height. This outlined approach to increased safety will be useful to engineers, operators, and safety professionals to help reduce risk and improve worker performance.
Hydraulic fracturing is a well stimulation technique that was first tested in the oil and gas industry in 1947, and the process was accepted commercially by 1950 (King 2012). To perform hydraulic fracturing operations, a fluid must be pumped into the well’s production casing (or a treating string) at a high pressure. It is necessary that production casing has been installed and cemented, and that it is capable of withstanding the pressure for which it will be subjected during hydraulic fracturing operations. The hydraulic fracturing process requires an array of specialized equipment and materials. These materials and equipment are necessary to perform typical hydraulic fracturing operations in vertical and horizontal wells. The equipment required to perform a hydraulic fracturing treatment includes fluid storage tanks, proppant transport equipment, blending equipment, pumping equipment, and all ancillary equipment, such as hoses, piping, valves, and manifolds. Before beginning the hydraulic fracture treatment, all equipment should be tested to help ensure it is in good operating condition. All high-pressure lines leading from the pump trucks to the wellhead should be pressure tested to the maximum treating pressure. Any leaks must be eliminated before initiation of the hydraulic fracture treatment (American Petroleum Institute 2009).
Hydraulic pumping trailers located or installed at rig sites are primarily diesel powered high pressure pumping units designed for oil well stimulation. Typically, a pumping trailer unit consists of diesel engines, transmissions, and triplex or quintuplex pumps equipped with advanced digital controls for transmissions and engines. The fracturing trailer unit needs frequent maintenance of various systems such as fluid end lubrications, recirculating air/oil systems and grease systems. Fig. 1 shows a typical example of a modern diesel powered fracturing pump trailer.
Osman, Adil Mohamed (PETRONAS Research Sdn. Bhd.) | Halim, Nor Hadhirah (PETRONAS Research Sdn. Bhd.) | Alwi, Noraliza (PETRONAS Research Sdn. Bhd.) | Sedaralit, Mohd Faizal (PETRONAS Carigali Sdn. Bhd.) | Ibrahim, Jamal Mohamad (PETRONAS Research Sdn. Bhd.) | Hamid, Pauziyah Abdul (PETRONAS Research Sdn. Bhd.) | Ohen, Henry A (HPO Global Resources Ventures)
A number of Malaysian mature oil fields have been and are still under investigation for Enhanced oil Recovery (EOR). This includes Water Alternating Gas (WAG), chemical flooding and Foam assisted WAG. This field is one of the most fields under extensive EOR studies for WAG & FAWAG. Despite the promising recovery factor from EOR application there are always the side effects that accompany these processes which are formation damage and injectivity issues.
A lot experiments studies shown, when a large number of pore volumes of polymer is injected with medium permeability beyond a critical shear rate, a plugging tendency is observed. This plugging is attributed to a damage mechanism called “bridging adsorption” in which stretched polymer macromolecules form numerous bridges across pore throats. At the same time, causes fine migration issue.
In this study, the effects of fines migration, clay swelling and injectivity were investigated in separate core floods studies (one test for fines migration, one test for clays swelling and three for chemical injectivity). For the fines migration study, the core flood test to investigate the critical flow rate of the seawater injection shows fines migration problem as observed from sea water injection of intermediate critical flow rate for fines migration in the core. For clays swelling the permeability reduction test and pH measurement with decreasing salinity indicates a critical salinity much less than the sea water salinity and sea water is the proposed medium for the EOR chemical in this field. Moreover, SEM investigation analysis result shows that most of the damage is due to fine migration caused by the velocity flow rate of the injection sea water.
For injectivity study, core flood tests were conducted with injecting surfactant polymer (SP) solution and with surfactant and polymer individually. The results show that while minimum damage of less than 30% is typically expected in this type of test with permeability resistance factor of less than 3, what was actually obtained in this test is about 95% damage and permeability resistance factor (PRF) is 23 compared to KPI of 3. The results also indicate that incompatibility between the surfactant and polymer could be one of the reasons for permeability decline. This is because while injecting the chemicals separately no serious injectivity issue is observed.
EOR studies prior to field application have recently enjoyed global attention due to several reasons including declining oil production below par primary and secondary recovery, high crude oil price and increasing energy demand which is growing at approximately 1.5% per year (Du, K., et al, 2011). Laboratory testing in support of field application is critical to minimize field application failures. This paper addresses possible risk of formation damage due to fine migration, clay swelling and polymer absorption during Foam Assisted Water Alternating Gas (FAWAG) process proposed for the field.
The offshore field is located 170 km away from West- Malaysia land. Currently this field is being considered for enhanced WAG process called Foam assisted Water Alternating Gas (FAWAG). In this process it is proposed to alternate polymer surfactant with gas instead of water. Surfactant is proposed to precede the gas injection, which will generate foam in-situ. Foam so generated along with the polymer is expected to improve the displacement efficiency by virtue of better mobility control, once implemented, This field will be the first such application in Malaysia.
Zulkapli, Mohd Hanif (PETRONAS Carigali Sdn. Bhd.) | Salim, Muzahidin Muhamed (Schlumberger) | Zaini, Muhamad Zaki (Schlumberger) | Rivero Colmenares, Maria Elba (Schlumberger) | Curteis, Charles (Schlumberger) | Sepulveda, Willem (Schlumberger)
Gas lift has been the primary artificial lift method for wells in an offshore brownfield in Malaysia for the past 30 years. However with depleting and unstable gas lift supply coupled with the increase in water production, an alternative artificial lift strategy needed to be developed. A revisit to the Field Development Plan (FDP) in 2003 has found that Electric Submersible Pump (ESP) could be the solution to overcoming the field’s overwhelming dependency on gas lift. During a workover campaign in 2008, 3 ESPs were installed – marking the first production ESP in Malaysia. The ESPs have increased the well production from the gas lift baseline production and on top of that, there is a 66% additional incremental production from the re-allocation of approximately 1 MMSCFD of lift gas from the ESP wells. The success of the three ESPs has developed interest from the field operator to have more units installed.
By end of 2011, a total of 5 ESPs has been installed in the field. They consisted of conventional ESPs, followed by an ESP in a pod with a Distributed Temperature Sensor (DTS) cable and a dual ESP with bypass tubing. Another 3 installations have been planned in the near future. The operator is also looking at the potential and feasibility of a rigless deployment for the ESP - either by using coiled tubing or a standard slickline service. In an offshore environment where rig cost and rig availability is of concern to well uptime and project economics, alternative ESP deployment has been seen as the next frontier of ESP technology to increase revenue. The transformation of artificial lift strategy in the field – from gas lift to ESPs - has been very progressive and profoundly significant to the operator’s continual technological advancement in the industry.
Bokor field is located 45 km offshore Sarawak, East Malaysia. It was discovered in 1974 and started production in 1984. The field reaches its peak production of 30000 barrel of oil production in 1990.
Bokor field comprises of 3 production platform which are BODP-A, BODP-B and BODP-C, one processing platform (BOP-A) and one compressor platform (BOK-A). BODP-A, BODP-B and BOK-A are interconnected by bridge link while the BODP-B and C are only accessible via boat. Power generation is located in BOK-A and limited to BODP-A and BOP-A. The rest of the production platforms have solar power system limited to the platform’s Supervisory Control And Data Acquisition
(SCADA) system and basic utility.
Due to the field unconsolidated formation sand, all of the wells in the early years were completed with cased hole gravel pack. Strong water aquifer in Bokor provides good and continuous pressure support, however increasing water cut becomes a severe problems to the surface facilities and increased demand to the lift gas. As an initiative to boost productions in the field, the operator ties a new relationship with Schlumberger to be its technical partner in 2002. The main objective of the partnership is to produce the incremental oil from the field.
Bokor field comprises of more than 100 strings of oil wells with half of them is idle and the rest are producing on gas lift with several string on natural flow.
Brunei Shell Petroleum acquired 7000 km2 of broadband seismic data during 2012 and 2013, in support of its strategy to “Rejuvenate and Grow”. Exploration growth is a key component of this strategic direction and the broadband data is seen as a key enabler. The new seismic data not only delivers far better structural definition but also allows for streamlined QI support to identify new prospective areas. Weeks after the final migrations are available, we delivered a full bandwidth Acoustic Impedance and a Fluid Cube for the entire 3D data space. The swift delivery of these inversion products forms a corner stone in pursuit of Brunei Shell Petroleum’s exploration objectives.
1 - Regional Full Bandwidth Impedance Data
Broadband seismic delivers lower frequencies in the seismic spectrum and, through application of the latest imaging techniques, also delivers higher frequency content in the migration velocities. These 2 components can be merged seamlessly, creating an acoustic impedance volume, without having the need to estimate information in the range of ~1.5 to 8 Hz. With conventional seismic this gap needs to be filled with more or less substantiated interpolations of rock properties, based on time consuming interpretation efforts.
We developed a robust workflow to generate regional full bandwidth Acoustic Impedance (AI) data, that essentially relies on
a) signal shaping and subsequent coloured inversion to appropriately reflect the earth’s AI spectrum,
b) the derivation and application of a single calibration factor to obtain band-limited AI and
c) subsequent merging of this band-limited AI data with low-frequency AI data that is directly obtained from the imaging velocities. Well tests indicate the quality of the match of well log data against the final impedance volumes (Figure 1).
Production logging in ultra-long horizontal wells has long been recognized to be extremely challenging, both in terms of data acquisition and data interpretation. This paper describes the planning, execution and lessons learnt of an incident free production/injection logging (PLT) campaign completed in twelve shallow horizontal wells – water injectors and oil producers – to support the long term reservoir management strategy of the Al Shaheen field, offshore Qatar.
In this giant offshore oil field, the acquisition of even partial inflow production data is considered worthwhile. A production logging programme was therefore considered as essential.
A logging campaign was undertaken in twelve wells using tractor technology as means of conveyance, in a cased hole environment.
The key objectives of this campaign were to:
The campaign showed that although static data are essential in understanding the flow performance of a well, they cannot solely always explain the flow profile along the wellbore. The acquisition of dynamic data is essential to understand the well behavior.
Results confirmed that in some long horizontal wells the flow profile takes place uniformly along the entire logged interval, whilst in others sub-optimum conditions such as cross flow and thief zones were identified. The paper describes how the data acquired helped to identify these latter conditions along with the repair opportunities to improve oil recovery.
This campaign proved that tractor is a viable means of PLT conveyance in shallow cased horizontal wells by pushing the limits of the technology to greater depths than coiled tubing – up to 14,550 ft – with less disturbance to flow. To maximize success in future well re-entries, completion design has been reviewed in new wells, in order to make them “tractor friendly”.
The Al Shaheen oil field in Block 5 and Block 5 Extension, offshore Qatar, consists of a stacked sequence of low permeability carbonate and high permeability clastic reservoirs at relatively shallow depths around 3,000 ft TVD. Although the field was discovered in the mid 1970’s its development commenced decades later, in 1992, when Qatar Petroleum entered into an Exploration and Production Sharing Agreement with Maersk Oil Qatar (1). Today the Al Shaheen field produces ca. 300,000 barrels of oil per day and cumulative oil production exceeds 1.4 billion barrels.
There exists a strong relationship between mud and borehole stabilities. Mud instability is associated with flocculation that is primarily caused by high active solids, high electrolyte concentration, and high temperature. Drilling in hot environments coupled with active or reactive solid contamination results in severe operational problems which get worse with the presence of salt intrusion. Therefore, drilling engineers search for alternate drilling fluids to eliminate and/or minimize instability problems such as stuck pipes, circulation loss, excessive torque and drag, inadequate cuttings transport, and sloughing borehole. Such mud should tolerate for accumulation of high amount of reactive solids and mitigate diffetential pressure sticking to avoid stuck pipe.
This study is an experimental work to investigate and remediate the rheological and fluid loss properties of both unweighted and barite-weighted sepiolite muds heavily contaminated with active solid. Sepiolite muds were formulated in a certain mixing order of additives. Bentonite clay with API specifications (OCMA) at a rate of 80-lbm/bbl was used to simulate active solid. Rheological properties of mud samples were tested at varying temperatures ranging from ambient to 400oF along with a sodium chloride content of 260,000-ppm (120-lbm/bbl). The filtration loss properties were determined at 300oF. Methylene blue test was also performed to determine the tolerance of sepiolite mud for reactive solid contamination. Sepiolite mud was also investigated for tendency to cause wall sticking to consider incidence of differential pressure sticking of drill pipe. Bulk Sticking Coefficient (Ksc) of sepiolite based mud was determined as indicator parameters under high pressure (500 psi) and high temperature (up to 400oF).
Sepiolite mud samples resulted in appropriate yield point, plastic viscosity, and water loss values. More importantly, Methylene Blue values lower than 13-lb/bbl and appropriate sticking coefficient were the concrete usability indicator of sepiolite muds against heavily reactive-clay contamination. In other words, sepiolite muds might be a good alternative to drill wells experiencing instability problems resulting from active solid contamination and differential sticking.
Water flooding is the hinge pin for Petrobel Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests, Petrographic Techniquesand quantitative calculations of scale tendency using specific softwarehad indicated probable deposition of calcium sulphate scale in the near-wellbore (Critical Matrix). Calcium sulphate scale, paraffin & was have been recognized to be a major operational problem. The bad consequences of scale formation& organic deposits comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can’t be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options which usually lead to further formation damage when invasion of formation rock by small particle sizes of the scale components.
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
The Production of Sidri formation which is currently contained 23 % of belayim land field OOIP (original oil in place) and currently contributes 27 % to the total oil production has been stopped dramatically in some wells.
Sidri formation exhibits a high degree of permeability, heterogeneity and increase water injection was done in some areas that lead to increase the possibility of forming scale, most of scale in Belayim onshore is calcium sulphate.
Precipitation of mixed organic/inorganic deposits (Calcium Sulfate Scale) resulted in decreasing the permeability in the critical matrix and perforation tunnels. Scale formed in the near-wellbore reduces oil production by blocking the narrow pore throats of the matrix itself
This paper highlights Petrobel first application by using the new innovation product SCSR in Belayim land field (Sidri formation), its success and results based on extensive lab studies, SCSR was tested and applied through an effective treatment strategy proposed to remove the scale efficiently; the program was designed taking into consideration the nature of the scale.Furthermore the proposed treatments were conducted and placed using coiled tubing (CT).
D. Warrlich, Georg Mathis (Shell Malaysia) | Palm, Danielle (Shell Malaysia) | van Alebeek, Hans Johannes (Shell Malaysia) | Volchkov, Dmitry (Shell Malaysia) | Hong, Sia Chew (Shell Malaysia) | Adams, Erwin W (Shell Malaysia) | Ryba, Artur (Shell Malaysia) | Schutjens, Peter Maarten (Shell India Markets Private Ltd.) | Stevens, David A (Shell Malaysia) | Peacock, Anthony William (Shell Malaysia) | Row, Zuka (Shell Malaysia) | Ghosh, Kallole (Shell Malaysia)
Pore-pressure prediction in a mature hydrocarbon province with producing fields bears issues different from an exploration or immature basin setting. Appraisal and production activities can introduce an additional set of complications that needs to be considered to make well-constrained pore-pressure predictions. Problems for infill drilling can arise from severe changes in rock strength (fracture gradient reduction), caused by depletion of reservoirs through production, or development drilling in neighboring fields, if there is pressure communication via a common aquifer. Increases above initial pressure can be caused by crossflow from overpressured reservoir layers through poor cement bonds or abandonments. Reservoirs can also receive additional pressure through water or gas injection.
The Luconia gas province is a mature basin and several stages of successful exploration, appraisal, development and infill-drilling campaigns. Shell, supported by its partners, has successfully overcome the above mentioned issues by thorough and innovative pore-pressure prediction approaches. In addition to the standard bracketing of uncertainties, 3 key process elements are employed: (1) proper framing of the pore-pressure prediction and continued interfaces with all stakeholders and (2) a ‘scenario-based’ prediction approach, that captures all possible effects caused by appraisal and production of the target reservoir or neighboring fields, and that predicts their impact on the pore pressure of the reservoir to be drilled. (3) Risks identified are captured and mitigated via a 5 point pore-pressure prediction that spans a facilities design range as well as a wider drilling range. The drilling-range end members have a low probability of occurring, but have to be captured to enable hardware selection that ensures safe drilling execution. State of the art technologies are employed to achieve this, including 4D seismic, regional data bases, innovative modeling methodologies and full integration in a well-delivery process.
The work analyzes the contribution of adding 3D seismic information in an exploration prospect assessment project. The analysis follows the classical VoI framework, where a prior value is computed, and different accuracy values are tested for the 3D seismic contribution. The novelty lies in the ability of capturing the value of seismic throughout a whole integrated approach, from modeling the subsurface effect of the seismic survey to capturing its effect in terms of distribution of expected resources, up to a complete full-cycle economic evaluation of the project. We can therefore compute the prior and posterior distribution of the monetary value of the different projects, and use such values to estimate the Value of Information in a fully stochastic way. A complete sensitivity analysis is presented, both for what concerns the effect of seismic information on different volumetric parameters, and for what concerns the accuracy of the seismic information itself, ranging from perfect to imperfect information.
The case study represents a conventional onshore oil prospect. A contemplated 3D seismic survey may change the geological model either making it more positive or exposing details that can cause failure.
The paper addresses the problem of evaluating the value of seismic information in an exploration decision context. As compared to previous works in the literature (cfr. Pickering and Bickel, 2006 and Bickel, 2008) the discussed approach introduces two novel elements. First, we aim to provide a framework that couples the classical Value of Information (VoI) formulation with a complete full cycle evaluation of the economical potential of the project throughout the lifecycle of the field. Second, we aim to propose a stochastic formulation of the VoI that would allow the decision maker to read it really as a value (potentially with a certain utility function associated to it), and not just as the maximum price that we would be willing to pay for a determined piece of information, as it is usually intended in the literature. We will show that it is possible to take a step in this direction without losing the main and important theoretical results proven in the past 40 years, and thoroughly reviewed in (Bratvold et al., 2009).
The original VoI formulation dates back to (Howard, 1966), and to (Grayson, 1960), for what concerns its original application to the oil and gas industry. Along the years, the idea of evaluating the economical feasibility of certain investments through this tool has increased enormously in our industry, and now it is standard practice to apply such workflow at least when evaluating large and risky investments. In recent years, literature reviews such as the one provided by (Bratvold et al., 2009) and by (Smalley et al., 2008) have appeared, in order to present some recent applications of the Value of Information, and to provide a theoretical basis for its computation. As they point out, in fact, our industry is still lacking a unified framework to compute the Value of Information, and this is one of the reasons why there is still a certain level of distrust among the practitioners when using such tools.
Keong, Ong Swee (PETRONAS Carigali Sdn. Bhd.) | Bt. Abdullah, Azirul Liana (PETRONAS Carigali Sdn. Bhd.) | Bin Ahmad Fuad, Ahmad Syahir (PETRONAS Carigali Sdn. Bhd.) | Bt Hamdan, Norazean (PETRONAS Carigali Sdn. Bhd.) | Bt Anuar, Azlina (PETRONAS Carigali Sdn. Bhd.) | Basu, Debnath (Schlumberger) | Ysaccis, Raul (Schlumberger) | Murthy, K S (Schlumberger) | Kim, Taesoo (Schlumberger)
The study area is situated in the offshore West Nile Delta basin towards the northeast of Alexandria, Egypt. This is a major petroleum habitat hosting many gas and condensate fields. The present paper summarizes the petroleum system elements for hydrocarbon prospecting in the Messinian and deeper stratigraphic section based on an integrated study of seismic and well data.
Mixed well results have been observed in the area with proven gas fields found in stratigraphic fluvial channels in the Messinian. Rotated fault blocks and fault dependent traps were tested but no discoveries were proven. Failure could be due to trap integrity issues and inadequate migration pathways. Potential remaining stratigraphic plays identified are deepwater slope channels in the pre-Messinian to Oligocene section similar to overlying Pliocene gas fields.
Depositional models based on seismic attribute mapping and a few wells generally depicts a NW-SE facies belt trend dominated by deepwater slope channel complexes flanked by slope shales ranging in age from Upper Oligocene to Miocene (Pre-Messinian). In the Messinian, the depositional environment is associated with a major sea-level drop with consequent exposure of the shelf/slope. It contains predominantly incised valleys and fluvial-fills flanked by interfluves.
The hydrocarbon charge is expected from Cretaceous-Jurassic and Early Tertiary pro-delta shale source rocks (Marten et al., 2004). Evidence of highly mature thermogenic gases (2.0 % - 2.5% VRo) advocates the assumption of the presence of a deeper source rock contribution from limited well calibration. Basin modeling results shows that the modelled source rocks are presently in the hydrocarbon generation window. Source rock generation has occurred very late from 9.0Ma to 1.0Ma and migration timing post-dates trap formation. Traps are expected to be charged vertically and through fault conduits as observed in well results.
This study paved the way for a better understanding of the petroleum system elements which consequently forms the basis in risking the Messinian and deeper exploration plays and shows that the Messinian stratigraphic channel plays are most prospective.