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Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Since the industrial revolution, the oil and gas industry has played an important role in the economic transformation of the world, fueling the need for heat, light and mobility of the world’s population. Today, the oil and gas industry has the opportunity to redefine its boundaries through digitalisation, after a period of falling crude prices disrupted exploration and production activities, and ineffective mature field development challenges that are currently facing most oil and gas companies in Indonesia. The recent downturn in the oil and gas industry has led to massive layoffs. Digital industrial revolution is slowly changing how upstream businesses operate. Increasing public awareness of climate change has fuelled the urgency to shift to cleaner alternative energy. Can the current petroleum engineers survive in the next 10 to20 years?
The most common method used to enhance oil production over primary rates is water injection, commonly referred to as secondary oil recovery. Common practice in the industry is to refer to all other methods as tertiary enhanced oil recovery. According to Prats, thermal enhanced oil recovery (TEOR) is a family of tertiary processes defined as "any process in which heat is introduced intentionally into a subsurface accumulation of organic compounds for the purpose of recovering fuels through wells." By far, the most common vehicle used to inject heat is saturated steam. Hot water and heated gasses have been tried, but none are as effective as quality steam. According to a 2000 Oil and Gas Journal survey, steam enhanced oil recovery projects account for 417,675 barrels of oil per day (BOPD), or 56% of the total for all tertiary enhanced recovery methods. That production rate has been essentially flat for more than 15 years. Hydrocarbon gas injection and CO2 gas injection are the only other significant contributors and amount to only 17 and 24%, respectively.
Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).
Horizontal wells are being employed in innovative ways in steam injection operations to permit commercial exploitation of reservoirs that are considered unfavorable for steam, such as very viscous oils and bitumen and heavy oil formations with bottomwater. This page discusses some of the ways in which horizontal wells have been used to enhance steamflooding. Numerous papers have explored steam injection using horizontal- vertical-well combinations by use of scaled physical models or numerical simulators. For example, Chang, Farouq Ali, and George used scaled models to study five-spot steamfloods, finding that for their experimental conditions, a horizontal steam injector and a horizontal producer yielded the highest recovery. Figure 1 shows a comparison of oil recoveries for various combinations of horizontal and vertical wells and for four different cases: homogeneous formation, 10% bottomwater (% of oil zone thickness), 50% bottomwater, and homogeneous formation with 10% pore volume solvent injection before steam.
Introduction Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. The oil in oil sands is an immobile fluid under existing reservoir conditions, and heavy oils are somewhat mobile fluids under naturally existing pressure gradients. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation. Before 1985, heavy-oil production was based largely on thermal stimulation, ΔT, to reduce viscosity and large pressure drops, Δp, to induce flow. Projects used cyclic steam stimulation (huff'n' puff), steam flooding, wet or dry combustion with air or oxygen injection, or combinations of these methods.
Cai, Zhenzhong (Tarim Oilfield Company, PetroChina) | Zhang, Hui (Tarim Oilfield Company, PetroChina) | Yuan, Fang (Tarim Oilfield Company, PetroChina) | Yin, Guoqing (Tarim Oilfield Company, PetroChina) | Wang, Haiying (Tarim Oilfield Company, PetroChina)
The Kuqa depression located in northern Tarim Basin is the second largest natural-gas field in China, however, drilling engineering is faced with extremely complex geological conditions, such as complex structural movement history, complex formation conditions (huge thick gypsum salt rock, and different thickness of alternating sand/shale sequences and conglomerate), abnormal high pore pressure systems and strong anisotropy in situ stress. These complex geologic conditions result in severe wellbore instability problems.
An integrated research was conducted combining geology, geomechanics and drilling engineering to solve drilling problems caused by complex geological conditions. Firstly, geomechanical models are established according to the geological characteristics of different formations to get orientation and magnitude of stress, pore pressure and rock mechanical parameters. Secondly, based on rock mechanics experiments and wellbore information, the geomechanical mechanism research of wellbore instability was carried out under complex geologic conditions. Finally, the geomechanical model, wellbore stability parameters and the mechanism of drilling problems are applied to the drilling engineering design optimizing mud parameters, wellbore structures and trajectory of high deviation wellbore.
It is shown that geomechanical approach can improve wellbore stability and drilling rate. (1) For the uppermost conglomerate formation, according to the experimental study of the failure mechanism of conglomerate, accurate mud density is the key avoiding causing extension fracture around conglomerate grains. (2) The mechanical stability of borehole in alternating sand/shale sequences is good, but it is easily affected by hydration. Therefore, high quality mud properties can be matched with low mud density to maintain wellbore stability and improve drilling rate. (3)The interior of gypsum-salt sequences is divided into six lithologic sections. Based on the detailed analysis of different lithology, an in-situ stress model is established optimizing the mud density to find a balance between creep resistance and preventing from lost circulation. (4)Pay zone belongs to fractured sandstone under strong stress background. It shows strong anisotropy in stress field and rock strength. The mud density window determined by this mechanism can not only maintain wellbore stability and prevent lost circulation, but also protect reservoir.(5)The feasibility of highly deviated well was demonstrated based on geomechanical approach. And the wellbore trajectory was optimized in four aspects: avoiding shallow fracture, maintaining wellbore stability, traversing more effective fractures, and easy fracturing after drilling.
Geomechanical research under complex geologic conditions promoted the recognition of the mechanism of wellbore instability, and optimized the program of drilling engineering. The drilling incidents of formation above salt were reduced by 50% and the non-productive time was reduced by more than 20%. At the same time, this research project also promotes the successful implementation of the first highly deviated wells which provided a new way to further improve the gas productivity in this area.
Tejo, B. (ConocoPhillips Grissik Ltd.) | Singamshetty, K. (ConocoPhillips Grissik Ltd.) | Tupamahu, L. (ConocoPhillips Grissik Ltd.) | Gunawan, I. (ConocoPhillips Grissik Ltd.) | Nugroho, W. (ConocoPhillips Grissik Ltd.) | Satriya, Y. (ConocoPhillips Grissik Ltd.)
An operator recently drilled and completed an onshore well in South Sumatra by intentionally leaving 3-1/2 in. drill pipe in the hole, to be used as the lower completion string. This paper documents the design and execution of this unique drill pipe completion idea, overcoming challenges during drilling due to unanticipated formation collapse, leading to multiple sidetracks. The reservoir contains dry gas with >30% CO2 inside naturally fractured basement rock. Wells in this area are usually drilled with total losses throughout the reservoir section and completed by running a perforated liner.
In the 3rd and final sidetrack, the drill pipe completion idea was successfully executed resulting in a well that is producing ∼40 MMSCFD. The idea was selected after technically evaluating other viable options such as liner drilling using 5-1/2 in. casing or drilling with continuous water injection and then running the liner. The drill pipe completion option provided the highest chance of success to reach total depth (TD) in a single bit run while serving as a mechanical conduit in the wellbore for production and providing a barrier against hole collapse. The detailed planning conducted to finalize the drilling bottom hole assembly (BHA), perforating gun performance, drill pipe cutter, production rate impact, erosional and corrosion impact of using drill pipe as completion will be explained in the paper.
Operationally, after the well was drilled to TD, 1-11/16 in. strip guns were used to perforate the 3-1/2 in. drill pipe and then the pipe was severed using a non-explosive plasma jet cutter and left in hole. A fishing overshot was then run on the bottom of lower completion liner to swallow the cut drill pipe and provide future intervention capability. The upper completion was subsequently run and set prior to rig demobilization.
This unique application of a sacrificial drill pipe completion, also termed as the "crazy drill pipe idea" by the operator, generated a lot of discussion and interest within the oil and gas industry in Indonesia. We are hopeful that the technique and application discussed in this paper will provide valuable insight into this alternative completion design for use in depleted and unstable formations, where opportunities to pursue other viable options are limited.
Wibawa, Ramdhan (PT Chevron Pacific Indonesia) | Handjoyo, Teguh (PT Chevron Pacific Indonesia) | Prasetyo, Joko (PT Chevron Pacific Indonesia) | Purba, Monas (PT Chevron Pacific Indonesia) | Wilantara, Dedi (PT Chevron Pacific Indonesia) | Dongoran, Japet (PT Chevron Pacific Indonesia) | Gunawan, Gunawan (PT Chevron Pacific Indonesia) | Negara, Ari (PT Chevron Pacific Indonesia)
Sucker Rod Pumps (SRP) have been extensively utilized in the Duri field Heavy Oil Operations Unit (HOOU) for more than 6000 production wells. Approximately 2000 of these wells are equipped with dynamometer online that generates a daily dynamometer card (DC). Historically, the pump cards evaluation has led to the identification of several mechanical pump issues such as a traveling valve and standing valve leak that directly impact production.
One step of the traditional process to identification of rod pump failure is based on a manual pump card shape analysis performed for individual wells by different engineers throughout production history. To improve efficiency and reliability of shape analysis, Artificial Intelligence-based data analysis has been recently integrated in the oil and gas industry. This article proposes an approach to pump card classification, developed by the Integrated Optimization Decision Support Center, using a modified Case-Based Reasoning or computer reasoning by analogy approach where new problems are solved by comparison to analogous problems solved in the past.
The proposed methodology begins with definition of a reference DC for every known type of mechanical failure. The reference cards define the analogy set. Actual pump cards are then normalized and compared for similarity against each reference card or analogy using Euclidean distance measure between the actual and reference cards. For each actual pump card, the output of this approach is a set of similarity scores which indicate the pump failure type corresponding to references card shape, if any. The analysis is enhanced through the addition of rules based on pump operational parameters that result in specific pump failure signals. The methodology has been verified against DC evaluations from Subject Matter Experts (SME) and is demonstrated to provide robust pump failure signals more efficiently than by manual interpretation of DC for a series of individual wells.