The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Abstract Sand production is a pertinent issue in oil and gas well engineering and a major cause of concern for the production engineer. He can plan for it, or he can prepare for it, albeit he would rather have it nipped in the bud right from the well’s completion phase. Sand production is costly, reducing the lifetime and durability of pipelines and production facilities, inadvertently impacting the company’s balance sheet negatively and in some cases reducing the life and productivity of the well itself. This paper critically evaluates sand production in the Niger Delta, using the Ibigwe field operated by Waltersmith Petroman Oil Limited as a case study. It proffers optimal sand exclusion methods for wells in the Niger Delta by analysing various subsurface datasets and historical sand production from offset wells within the field. The subsurface datasets identified as relevant to this study include sonic transit time, depth of burial of zones of interest, particle size analysis, geomechanical data (specifically unconfined compressive stress logs), Rate of Penetration (ROP) and other data logs. Evaluating all relevant data to the subject is imperative as discovered during research; none of the datasets listed above can be analysed in isolation, rather interdependently. The selection of an optimal sand exclusion method consequently affects the deployment of an effective completion mechanism and as such, this endeavour should be carried out conscientiously.
Abstract The objective of the study was to examine the assertion that marginal oil field development remains one of the economic fortunes of Niger Delta region in Nigeria. This is evident with its shares in the region power output as well as its contribution to the industrialization. Multiple case studies of marginal oil field operations corroborate the relationship between marginal field development and economic fortunes of Niger Delta region. Marginal field firms provide electricity to the host communities where they operate. Also, industries are fed with natural gas from marginal field operating in the region. The marginal field operators ensures that host communities are getting electricity. Also cement factory is fed from natural gas operating in the area. However, the management of marginal field resources has been far from being optimally beneficial. The real issue is how to manage the marginal field for the welfare of the people. Against this background, the study findings suggested that the country marginal field wealth be used to implement people-oriented programmes for better welfare spread.
Eni reported a large gas and condensate discovery in the deep sequences of the Obiafu-Obrikom fields on the OML61 block onshore the Niger Delta. The Obiafu-41 Deep well reached a TD of 4374 m and encountered 130 m of high-quality hydrocarbon-bearing sands within the deltaic sequence of Oligocene age. The find amounts to 1 Tcf of gas and 60 million bbl of associated condensate in the deep drilled sequences. Eni said the discovery has further potential that will be assessed in the next appraisal campaign. The well will immediately be brought on production and is expected to flow more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said.
Abstract Obagi is a mature onshore oil field in the Niger Delta discovered in 1964 which comprises of mainly oil-bearing reservoirs with some reservoirs having large gas caps. Over the years, significant oil production has taken place in the oil rims of the reservoirs with large gas caps. Time-lapse fluid saturation evaluation using openhole well logs and cased-hole saturation logs (CHSL) established flushed oil zones and the existence of significant remaining gas columns in two gas cap reservoirs. Integrated reservoir studies identified watered-out wells that traverse these gas caps and are well placed to produce the gas zone with good clearance from the current water contact. In order to increase gas production potential from the Obagi Field at very low cost, a strategy of rigless intervention using coiled tubing for cement isolation and E-Line re-perforation to convert the watered-out oil wells to gas producers was adopted. Candidate wells for intervention were selected based on their location within the reservoirs, considering their proximity to the existing producers as well as the ease of connection to existing surface facilities. An intervention was carried out on OB-P1 by isolating the existing perforations via coiled tubing by setting a plug in the tubing above the watered-out zone, performing a tubing punch and circulating cement in the annulus. An E-Line re-perforation was then performed shallower in the R1 reservoir gas cap with a ceramic screen installed for sand control. A post intervention production test shows that OB-P1 has a gas production potential of > 250 kSm3/day (8.8 MMSCFD). This rate is constrained by damage (well still cleaning up) as well as mechanical skin due the completion type (ceramic sand screen) and the small effective wellbore diameter. Successful execution of three other planned conversion wells will replace, at least, one of the infill gas wells in the planned drilling sequence. This will result in a cost saving of about 65% of a new well.
E&P Notes BP To Sell Alaska Business to Hilcorp BP has agreed to sell its entire business in Alaska to Hilcorp Alaska, based in Anchorage. Under the terms of the agreement, Hilcorp will purchase all of BP’s interests in the state for a total consideration of $5.6 billion. The sale will include BP’s entire upstream and midstream business in the state, including BP Exploration (Alaska) Inc., that owns all of BP’s upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.’s interest in the Trans Alaska Pipeline System (TAPS). Bob Dudley, BP group chief executive, said in a press release, “Alaska has been instrumental in BP’s growth and success for well over half a century and our work there has helped shape the careers of many throughout the company. We are extraordinarily proud of the world-class business we have built, working along-side our partners and the state of Alaska, and the significant contributions it has made to Alaska’s economy and America’s energy security. • BHP, Anadarko Among Leaders in Latest US Gulf Lease Sale Australia’s BHP Billiton and the recently acquired Anadarko Petroleum submitted the largest dollar totals of high bids in US•Gulf of Mexico Lease Sale 253. The year’s second US gulf auction received 165 bids on 151 blocks from 27•firms, with high bids totaling $159.4•million, the US Bureau of Ocean Energy Management (BOEM) announced in New Orleans on 21•August. Those totals were mostly down from the last two gulf lease sales: Lease Sale 252 in March and•Lease Sale 251 in August 2018. “While we saw companies pick up acreage near remote areas, the infrastructure-rich Mississippi Canyon was the bid engine of the sale, capturing roughly 25% of total bids,” said Michael Murphy, research analyst at consultancy Wood Mackenzie, in comments following the auction. “Infrastructure-led exploration continues to be a theme” in US gulf lease sales, he noted. • Eni Makes Big Gas, Condensate Discovery in Nigeria Eni reported a large gas and condensate discovery in the deep sequences of the Obiafu-Obrikom fields on the OML61 block onshore the Niger Delta. The Obiafu-41 Deep well reached a TD of 4374 m and encountered 130•m of high-quality hydrocarbon-bearing sands within the deltaic sequence of Oligocene age. The find amounts to 1 Tcf of gas and 60 million bbl of associated condensate in the deep drilled sequences. Eni said the discovery has further potential that will be assessed in the next appraisal campaign. The well will immediately be brought on production and is expected to flow more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the•company said. • The Shale Bankruptcies Continue The US upstream space may be more than 3 years removed from the apparent bottom of a generational oil-price slump, but the number of shale operators filing for Chapter 11 bankruptcy protection continues to grow. The latest two are Sanchez Energy and Halcón Resources, both based in Houston. For Halcón, it is the company’s second time in 3 years.• Sanchez’s voluntary filing on 11 August “follows an extensive review of strategic alternatives to align its capital structure with the continued low-commodity-price environment,” the company said in a news release. The Eagle Ford Shale producer will continue to operate as usual with an additional $175 million in newly committed financing, of which $25 million will be used to repay borrowings and replace a letter of credit. • Equinor, YPF To Explore Block Offshore Argentina Equinor and Argentina’s state-owned YPF will team to explore the 15000-sq-km CAN 100 offshore block in the North Argentina Basin. Under the agreement, YPF will transfer 50% of its interest in the block to Equinor, giving the companies an equal share. YPF acquired 100% of the block in May, at which point a 4-year exploratory period began. Equinor and YPF are already partners on the CAN 102 and CAN 114 blocks, also in the North Argentina Basin, awarded in April as part of Argentina’s first open bid round for offshore acreage in more than 2 decades. Equinor gained seven blocks in the auction, including five as•operator.• • PDC Energy and SRC Energy Merge in Latest Shale Deal The latest move to consolidate the US shale sector came on 26 August as PDC Energy said it would acquire SRC Energy in an all-stock transaction valued at just over $1.7 billion in assets and assumed debt. The cash value of the deal is about $971•million and indicates that the offer is pegged at a 3.9% discount on SRC’s last•closing share price. The two Denver-based companies will form the second-largest oil and gas producer in Colorado’s DJ Basin and adds to PDC’s position in the Permian Basin. Land holdings in the DJ Basin will include about 182,000 “core” acres, with the newly acquired SRC share adding an estimated 10 years of inventory. PDC is taking on close to $685 million of SRC’s debt.
Abstract Integrated Asset Modeling (IAM) has now become widely used for oil and gas production optimization. It has the advantage of integrating constraints from reservoir, well inflow and outflow, pipelines, compressors and processing facilities in one integrated simulation model. IAM is also a powerful tool for decision making and planning, it allows a quick and comprehensive assessment of geosciences uncertainties combined with different development strategies. This paper describes how IAM is a key for OML58 gas fields optimization and forecast. It has proven its ability to identify potential benefits of upgrading surface facilities to ensure sustainable gas supply to the Nigeria Liquefied Natural Gas Plant (NLNG) and the domestic market. The OML58 upgrade project comprised the increase of gas compression capacity and the construction of two major pipelines: The Obite-Ubeta-Rumji (OUR) pipeline and the Northern Option Pipeline (NOPL). The commissioning and start-up was completed in August 2016 and the first domestic gas supply to the Alaoji Power Plant was achieved in October 2016, marking an important milestone for Total E&P Nigeria Limited (TEPNG) and its joint venture partner NNPC. The paper also highlights the importance of OML58 IAM in addressing both short and long term challenges. The model is used to maximize condensate production using an algorithm that automatically prioritizes high condensate wells in forecast stage. It also guides the planning and the optimization of well intervention for both data acquisition and production enhancement. In long term perspective, the paper illustrates the flexibility to perform the screening of different infill/workover drilling options, the integration of undeveloped gas fields and the preliminary assessment of gas explorationprospects.
Okoroafor, Rita Esuru (WalterSmith) | Ekhaesomhi, Peter (WalterSmith) | Ipinyemi, Gbemiga (WalterSmith) | Oyenuga, Funso (WalterSmith) | Ilesanmi, Olumide (WalterSmith) | Haq, Shahid (Schlumberger) | Zhou, Wentao (Schlumberger) | Ortenzi, Luca (Schlumberger) | Nnebocha, Ezinne (Schlumberger)
Abstract Geosteering is a proven concept which enables the delivery of productive wells by ensuring such wells stay within the target reservoir and sweet spot, and are precisely placed relative to fluid contacts. When reservoir engineering concepts are combined with Geosteering, quantitative estimates of the well's productivity can be determined to further evaluate the performance of the Geosteering and aid in decision-making. This workflow, applied in real-time, is called Real-Time Productivity Steering (RTPS). This paper describes the application of RTPS to a horizontal well placed in a thin layer of oil reservoir. Prior to performing the real time productivity estimates while drilling, a prejob model was built, using offset well data, to estimate productivity from the planned well. Sensitivity analysis was performed on the trajectory, well length and some rock and fluid properties, to determine the plan that would result in optimum productivity for the well. While the well was drilled, Logging While Drilling (LWD) information was used to update the existing model, geosteer, and perform productivity prediction while drilling. Productivity was predicted at three target depths: 8400 ft MD, 8800 ft MD, and at Total Depth (TD). The increasing liquid productivity index (PI) at the selected target depths were further justification to continue drilling until the predetermined TD. The results at TD showed that the open hole liquid PI of the well in the sand of interest was about 63.8 stb/d/psi for a stable production rate of 1200 blpd. When completions were imposed on this single well reservoir model, it was predicted that the well will produce at a stable rate of 750 bopd. This was compared with a preliminary test done on the well where for the same well and reservoir conditions, the well produced 800 bopd. This paper demonstrates that quantitative estimates of productivity can be made while drilling to complement geosteering. In addition to complementing and enhancing geosteering, RTPS provides a reliable dynamic model for subsequent completion design. The RTPS workflow of complementing geosteering with reservoir engineering will enhance the ability to drill more productive wells as it will enable wells to be steered in the direction of maximum productivity, and also provide operators with sufficient information while drilling to make informed decisions for completions and for future wells.
Gibrata, Muhammad A (ADCO, UAE) | Ali, Arfan (Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK) | Somerville, Jim M (Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK)
Abstract Formation evaluation in overpressured reservoirs is very challenging due to abnormally high pressures, relatively high reservoir temperatures, uncertainty in the determination of reservoir rock properties and in fluid types and contacts. Accurate determination of these parameters is a key in obtaining a reliable hydrocarbon volume assessment which would otherwise lead to an uncertainty of hydrocarbon accumulation in these reservoirs and subsequently impose a risk in developing such reservoirs. In this paper, we present an integrated approach for improved formation evaluation in overpressured reservoir rocks. The data used in this paper comes from two gas fields in Eastern Baram delta provincewhich is a sandstone reservoir separated by a fault. The approach makes use of various types of data including petrophysical, geological, reservoir, extracted core samples, downhole logs, in-situ fluid sampling, spill points, and saturation height data which provide key pieces of information in the evaluation of these reservoirs. One of the key conclusions is that the porosity and permeability of cores in overpressure reservoirs have better quality preservation compared to normal/under pressure reservoir intervals. Also a unique trend of QV vs porosity was seen for overpressure and normal/under pressure reservoir rocks. There is an uncertainty in fluid contacts determination in the studied fields. The formation pressure andlog data have been utilized to identify fluid contacts in a few reservoirs. However there are still some contacts which can not be identified where no water zones have been penetrated. In such reservoirs, free water levels are determined using gas/oil down to (G/ODT) and spill point data.
Gao, Y.N. (State Key Laboratory for Geomechanics and Deep Underground Engineering, China University of Mining & Technology) | Gao, F. (State Key Laboratory for Geomechanics and Deep Underground Engineering, China University of Mining & Technology) | Yeung, M.R. (Department of Civil Engineering, California State Polytechnic University)
ABSTRACT Large deformations and rotations of rock blocks may occur under high stresses around deep underground rock engineering works such as deep mines and deep tunnels. The original discontinuous deformation analysis (DDA) was developed by Shi and Goodman to analyze large deformations, rotations and displacements of rock blocks by accumulating small components of these quantities in a time-marching scheme. The small rotation angle approximation adopted in the original DDA may induce block expansion with rotation (free expansion). Some methods have been used to study and reduce the rotation errors, including the Taylor series method and trigonometric method. Based on mechanics, the free expansion is caused by the error due to the approximation of the real behavior using a displacement function, and the theory used to describe the geometrical relationship between movement (displacement and rotation) and deformation. The original DDA uses the geometrical relationship that is based on small strain theory. Small strain theory gives a linear relationship between displacement and strain that does not consider the high order components and the decomposition of rotation and displacement. The finite deformation theory, however, decomposes the displacement and rotation and gives a nonlinear relationship between displacement and strain. Therefore the finite deformation theory can handle the block rotation problem more correctly. In our previous work, we compared the displacement field around a circle tunnel obtained from the finite deformation theory and small strain theory. The results show that the difference increases as the deformation increases. The rotation error due to the small strain assumption and the validity of the finite deformation theory were also studied by Chen using an analytical method. In this paper, we use the finite deformation theory to adjust the displacement and strain components in DDA to study the free expansion of blocks in a model in which a rock block falls down a slope. The area of the block is monitored during the fall. The expansion of the block computed by DDA modified by the finite deformation theory, and the original DDA will be compared. The result shows that the DDA modified with finite deformation theory can eliminate the free expansion. INTRODUCTION The discontinuous deformation analysis (DDA) developed by Shi and Goodman was a 2-D numerical method for the statics and dynamics of discontinuous block systems. Shi adopted the small angle approximations (sin r0˜0, cos r0˜1) in the original DDA formulation for the displacements of a point within the block. This simplification is convenient for formula derivation and computationally efficient and fast, particularly for small rotation of the blocks. However, the linearization of the rotational displacements causes the blocks to expand with every increment of rotation and results in distortion of stress and velocity fields. Ke proposed to use a postadjustment with a maximum rotation limit, 0.1 radian, set up to reduce the errors in computing contact forces.This approach is easy to implement and can prevent the blocks from expanding. Koo and Chern also proposed to use linear displacement function and post-correction.
Abstract On exhausting conventional oil extraction techniques, about 2/3 of discovered reserves are usually unproduced. CO2 injection into oil reservoirs is widely accepted as an effective Enhanced Oil Recovery (EOR) technique, and has been used in the oil industry for over 40 years. In this study, incremental oil, producible by CO2-EOR from the large domestic oil reservoirs at Obagi field was calculated. The study utilized the CO2-PROPHET model to evaluate the oil database and found Obagi fit for CO2 flooding. Afterwards a Kinder Morgan Scoping economic model was used to evaluate the economic viability of the flood. With 1.2 Billion barrels initial oil in place and a residual oil saturation of 50%, the field would only have up to 17% recovery at a 100% hydrocarbon pore volume of CO2 injected. Sensitivity on the Dykstra Parsons correlation coefficient showed that increasing the parameter i.e. (increasing heterogeneity) results in no change in oil produced with time. Also, a sensitivity on viscosity showed that for the range of oil viscosities analyzed, oil production clearly decreases with increasing oil viscosity. Economic sensitivity was positive with a Present Value Profit after Tax of $149.8MM. This is equivalent to $1,623,038,950.00 after a project lifetime of 25 years.